ENBRIDGE ENERGY PARTNERS LP - 10-K Annual Report

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. ý

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 28, 2002, was $1,402,850,803.


		PART I
Items 1 & 2.		Business and Properties
Item 3.		Legal Proceedings
Item 4.		Submission of Matters to a Vote of Security Holders
		PART II
Item 5.		Market for Registrant's Common Equity and Related Stockholder Matters
Item 6.		Selected Financial Data
Item 7.		Management's Discussion and Analysis of Financial Condition and Results of Operations
Item 7A.		Quantitative and Qualitative Disclosures About Market Risk
Item 8.		Financial Statements and Supplementary Data
Item 9.		Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
		PART III
Item 10.		Directors and Executive Officers of the Registrant
Item 11.		Executive Compensation
Item 12.		Security Ownership of Certain Beneficial Owners and Management
Item 13.		Certain Relationships and Related Transactions
Item 14.		Controls and Procedures
		PART IV
Item 15.		Exhibits, Financial Statement Schedules and Reports on Form 8-K
Signatures
Sarbanes-Oxley Section 302(a) Certification
Sarbanes-Oxley Section 302(a) Certification
Index to Financial Statements, Supplementary Information and Financial Statement Schedules

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" or "will" or the negative of those terms or other variations of them or by comparable terminology. In particular, statements, expressed or implied, concerning future actions, conditions or events or future operating results or the ability to generate sales, 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.

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

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. On December 27, 1991, the Partnership completed its initial public offering of 17,390,000 Class A Common Units at $21.50 per unit. Since the Partnership's initial public offering, it has increased its quarterly cash distribution by 57% from $0.59 per unit to $0.925 per unit, effective with the distribution declared for the fourth quarter of 2002.

The General Partner owns an 8.7% limited partner interest (in the form of 3,912,750 Class B Common Units) and a 2% general partner interest in the Partnership. The remaining 89.3% limited partner interest in the Partnership is represented by 31,313,634 publicly traded Class A Common Units, or 69.0%, and 9,228,655 i-units, or 20.3%, a new class of limited partner interests owned by Enbridge Management.

Enbridge Management is a Delaware limited liability company that was formed on May 14, 2002. Enbridge Management's shares representing limited liability company interests are traded on the NYSE under the symbol "EEQ." Its principal asset is a class of limited partner interests, referred to as "i-units," in the Partnership. Enbridge Management's principal activity is managing and controlling 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 and control 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.

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

The operating segments described above reflect the inclusion of the Midcoast System, which was acquired from the General Partner on October 17, 2002 for approximately $875 million, including estimated closing adjustments for working capital and other items. Prior to this transaction, the business

of the Partnership was limited to liquids transportation and the East Texas gathering and processing operation. The Midcoast System consists of:

The Midcoast System also includes the assets known as the South Texas and Northeast Texas Systems (see "Items 1 & 2, —Gathering and Processing Segment, —Other Gathering and Processing Systems").

The primary strategy of the Partnership is to grow cash distributions through the profitable expansion of existing assets and through development and acquisition of complementary businesses with similar risk profiles to the Partnership's current business. The Partnership is expanding the Lakehead System's capacity through the construction of Terrace and the complementary expansion of pipeline facilities in the Chicago area. The recent acquisition of the Midcoast System also provides the Partnership with the opportunity to increase the utilization of capacity and realize the benefit of potential synergies due to the complementary geographic proximity of the assets.

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 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 acquisitions are anticipated in and around its recently acquired natural gas gathering, processing, and transportation businesses.

The Partnership files annual, quarterly and other reports and other 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 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, or furnish it to, the SEC.

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 for third parties. 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 Midwest regions of the United States and the Province of Ontario, and, through interconnects, the Patoka/Wood River pipeline hub and refining center 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 750,450 installed horsepower and 58 crude oil storage tanks with an aggregate working capacity of approximately 11 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 2002, 42 shippers tendered crude oil and liquid petroleum for delivery through the Lakehead System. These customers included 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 supply from the Alberta oil sands. Similar to 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.

The western Canadian oil sands are naturally occurring mixtures of sand, water, clay, and approximately 12% bitumen. Using existing technology, knowledge and economics, the remaining recoverable bitumen reserves in the Province of Alberta were estimated at the end of 2001 at 175 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 2001 stood at approximately 3.5 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 from the bitumen deposits are less than $8.50 per barrel. Industry experts predict that improvements in technology and operating methods will result in production costs below $6.50 per barrel by 2004.

To put the scale of the bitumen resource in perspective, the proven reserves of crude oil in Saudi Arabia at the end of 2001 stood at approximately 260 billion barrels. Similarly, the combined proved reserves of crude oil in Iran, Iraq and Kuwait stood at approximately 300 billion barrels. Proved reserves are reserves that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions.

Firms involved in the development of heavy crude oil from the Alberta oil sands have announced extraction and/or up-grader projects valued in excess of approximately $35 billion over the next ten years. This could provide up to 1.5 million bpd of incremental production. Based upon a recent survey of western Canadian crude oil producers, the supply of western Canadian crude oil and liquid

petroleum is expected to be approximately 2.2 million bpd in 2003, approximately 2.3 million bpd in 2004, approximately 2.4 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 4% of its receipts from domestic sources as below:

Deliveries on the Lakehead System have decreased slightly over the past three years as western Canadian crude oil was delivered to other markets. During that period, declining conventional crude oil production in Western Canada was replaced with increasing oil sands production. With the completion of the AOSP and several SAGD projects, supply in the WCSB, and hence future deliveries on the Lakehead System, are expected to grow significantly over 2003.

The Partnership estimates that from all sources of supply, deliveries on the Lakehead System in 2003 will average approximately 1.37 million to 1.47 million bpd, based on its most recent survey of crude oil shippers. 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 this event, the Partnership expects increased earnings contributions from this system. As an example, an incremental 100,000 barrels per day of deliveries on the Lakehead System to Chicago would increase operating income by approximately $10-15 million. The Partnership expects that increased capacity utilization on the Lakehead System will comprise 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 ultimately will depend upon numerous factors. The investment levels and related development activities by 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 out of the WCSB results in higher deliveries on both the Enbridge and Lakehead systems. Deliveries on the Lakehead System are also impacted by periodic maintenance, turnarounds and other shutdowns at producing plants that supply crude oil, 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 3.3 million bpd in 2001. Over that same period, production of crude oil within PADD II decreased from over 1.0 million bpd to approximately 458,000 bpd. The Partnership expects this gap between PADD II demand and production will continue to widen, contributing to an increasing need to transport crude oil to PADD II.

The Partnership expects aggregate demand for crude oil and other liquid petroleum delivered by the Lakehead System to the Province of Ontario to remain relatively stable for the foreseeable future.

In anticipation of the improving supply and demand fundamentals discussed above, 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. Upon the completion of the Terrace expansion program, the Partnership expects that approximately 350,000 bpd of incremental capacity will have been added to the system.

Competition. Because 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 2002, the Enbridge System transported approximately 65% 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 75% of the total pipeline design capacity. The remaining 25% is shared by five other pipelines transporting crude oil to the province of British Columbia, Washington, Montana and other states in the northwestern United States.

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, Superior, Chicago, Detroit, Toledo and the Patoka/Wood River area of southern Illinois. In 2002, the Lakehead System transported approximately 50% of all crude oil deliveries into the Chicago area, approximately 84% of all crude oil deliveries into the Minneapolis-St. Paul and Superior areas; approximately 47% of all crude oil deliveries to the Detroit/Toledo area; and approximately 55% of all crude oil deliveries to the Province of Ontario.

The following table sets forth Lakehead System average deliveries per day and barrel miles for each of the years in the five-year period ended December 31, 2002.

The North Dakota System, which the Partnership acquired from Enbridge on May 18, 2001 for approximately $35 million, 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, 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 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 willingness 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.

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

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

Customers. The 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. Since the 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 these systems being located in areas where industrial, commercial and/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, 2002 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, 2002
Kansas Pipeline	160	97	%
MidLa Pipeline	200	89	%
AlaTenn Pipeline	200	71	%
Bamagas Pipeline	450	61	%
UTOS System	1,200	0	%

The Kansas Pipeline system has 82% of its capacity reserved under firm transportation contracts extending through 2009 and an additional 12% of its capacity under contracts extending through 2017. The remaining capacity of the Kansas Pipeline system is either unreserved or reserved under contracts that will terminate before 2009. The Kansas Pipeline system's primary customers are local distribution companies.

The MidLa, AlaTenn and Bamagas Pipelines 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 Pipeline was completed in the first quarter of 2002 in northern Alabama, where it serves two power plants. This pipeline is contiguous with the AlaTenn Pipeline and a third party pipeline, allowing for operational flexibility as natural gas can flow between Bamagas and either of the other two systems. The Partnership anticipates marketing the unused capacity on these pipelines under both short-term firm and interruptible transportation contracts and long-term firm transportation contracts. These pipelines are located in areas where opportunities exist to serve new industrial facilities and to make delivery interconnects to alleviate

capacity constraints on other non-company owned pipeline systems. In addition to current excess capacity, the AlaTenn Pipeline has contracts representing 21% of its capacity that will terminate before the end of 2003. Expiration of the AlaTenn contracts is not anticipated to have a material impact on the business segment. In the case of the MidLa Pipeline, as of December 31, 2002, approximately 55% of its capacity is under contract to affiliated entities.

The UTOS Pipeline 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. While the UTOS Pipeline system has no capacity reservations, the average daily throughput in the fourth quarter of 2002 was 282 million cubic feet of natural gas per day. The Partnership expects additional sources of offshore natural gas supply to connect to the UTOS Pipeline system in 2003. The Partnership has initiated a proceeding at FERC regarding transportation rates that will be effective on this system in 2003.

The Mid-Louisiana Gas Transmission system is an intrastate natural gas pipeline system that interconnects facilities owned by major industrial customers to interstate natural gas pipeline systems. In addition to providing transmission services to large natural gas consumers and customers, the system is used by the Midcoast System's marketing operations to facilitate the marketing and transmission of natural gas to natural gas consumers. The Mid-Louisiana Gas Transmission system has no capacity reservations. In 2001, this system averaged throughput of 75 million cubic feet of natural gas per day. Further, this system is favorably positioned to grow as marketing and transmission opportunities emerge as a result of anticipated development in the industrial consumer base in the Baton Rouge, Louisiana area.

The Magnolia Pipeline system is an intrastate natural gas pipeline that interconnects with other gas transmission pipelines. The Magnolia Pipeline system consists of approximately 110 miles of pipeline in central Alabama and privately receives natural gas from the Black Warrior basin in Alabama for delivery to downstream markets.

Competition. Because pipelines are generally the only practical mode of transportation for natural gas over land, the most significant competitors of the Midcoast System'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 Midcoast System 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 and/or third parties that may hold capacity on the various pipelines.

The East Texas System, which the Partnership acquired on November 30, 2001 for approximately $230 million, is a natural gas gathering, treating, processing and transmission system. The East Texas System purchases and/or gathers natural gas from the wellhead, delivers 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, which is the processed natural gas that ultimately is consumed by end users, and NGLs. 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.

The East Texas System includes approximately 2,000 miles of gathering and transmission pipelines. Approximately 400 million cubic feet of natural gas per day flows into the gathering pipelines from approximately 440 gathering points. The East Texas System also includes four treating facilities, with a combined capacity of approximately 595 million cubic feet of natural gas per day. Currently, two of these facilities are active and have a combined capacity of 415 million cubic feet per day. This system also includes three cryogenic gas processing plants, with a combined capacity of approximately 375 million cubic feet per day, one of which is currently inactive.

The East Texas System is operationally similar to, and is located adjacent to, the Northeast Texas System, which is described below. The Partnership believes there will be opportunities to capitalize on operational synergies that exist between these two systems. The combination of these two systems should result in a more favorable cost structure from facility optimization, additional opportunities to serve wholesale customers and producers, expansion of treating, compression and processing services and increased utilization of the Midcoast System's trucking assets.

Customers. Customers of the East Texas System include both natural gas producers and purchasers. Purchasers include marketers and large users of natural gas, such as power plants, industrial facilities and local distribution companies. Producers served by the East Texas System consist primarily of medium to large independent operators. 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 East Texas System's services primarily depends upon the rate of depletion of natural gas reserves and the rate of drilling 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.

Competition. Competitors of the East Texas System include interstate and intrastate pipelines or their affiliates and other natural gas gatherers that gather, treat, process and market natural gas and/or NGLs and which vary widely in size. 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 other 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 for the East Texas System's services also varies based upon pricing arrangements and reputation.

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 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.

The following systems were acquired in connection with the Midcoast System acquisition, which closed in October 2002. Most of the natural gas gathering assets are located in Texas and Oklahoma, with additional facilities in Mississippi, Louisiana, Kansas and Alabama. The facilities include the Anadarko, Northeast Texas, South Texas and Harmony systems.

Customers. Most of the gathering system's customers are natural gas producers. The systems also serve purchasers, such as marketers and natural gas consumers. NGLs are sold to a variety of

customers ranging from large petrochemical and refining companies to small regional retail propane distributors or certain system's natural gas may be delivered in interstate commerce.

Supply and Demand. Supply is affected by the same factors that affect the East Texas System's supply, such as the rate of drilling of new wells and depletion of reserves. Due to their geographic diversity, the natural gas gathering, and processing assets are not dependent on a single supply or production source. Demand for these services largely is dependent upon overall economic conditions and the prices of natural gas and NGLs.

The Partnership intends to expand the natural gas gathering and processing services through a combination of internal growth and acquisitions, which should provide exposure to incremental supplies of natural gas at the wellhead, increase opportunities to serve additional wholesale customers and allow expansion of the treating and processing businesses.

Competition. Competition in the markets served by the gathering and processing systems is generally similar to that in the markets served by the East Texas System, although on the sour gas systems, competition is more limited due to the infrastructure required to treat sour gas.

The trucking operations were also part of the Midcoast System acquisition. 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 98 trucks and trailers and 48 rail cars used for transporting NGLs, crude oil and carbon dioxide, product treating and handling equipment and over 400,000 gallons of NGL storage facilities. In addition, a CO₂ plant was recently constructed with 250 tons per day of capacity, which takes excess CO₂ from a supplier 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 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 are affected by the demand for NGLs and crude oil by large industrial and similar customers in the regions they serve.

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 segment of the trucking operations has numerous competitors, including marketers of all types and sizes, affiliates of pipelines and independent aggregators.

The natural gas marketing operation 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 operation makes natural gas purchases from producers connected to the Partnership's gathering systems and from other producers and marketers and then makes natural gas sales to wholesale customers on the Partnership's transmission and wholesale customer pipelines. The marketing operation also arranges transportation for wholesale customers.

Natural gas purchased and sold by the marketing operation is most 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 operation has numerous competitors, including the large marketing companies, marketing affiliates of pipelines, major oil and gas producers, independent aggregators and regional marketing companies.

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.

The volume of shipments on the Lakehead System depends on the supplies of western Canadian crude oil. Crude oil deliveries on the Lakehead System have declined from the prior year in each of the last three calendar years, largely because of decreases in crude oil exploration and production activities in western Canada and increased movement of crude oil through other pipeline systems. The volume of crude oil that the Partnership transports 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.

The Partnership's ability to increase deliveries to expand its Lakehead System in the future depends on increased supplies of western Canadian crude oil. The Partnership expects that growth in future supplies of western Canadian crude oil will come from oil sands projects in the Province of Alberta, Canada. Furthermore, full utilization of additional capacity as a result of the Partnership's current and future expansions of the Lakehead System, including Terrace, will largely depend on these anticipated increases in crude oil production from oil sands projects.

Nearly all of the crude oil and other products shipped on the Lakehead System come from the Enbridge System in Canada, and shipments on the Lakehead System are scheduled by Enbridge Pipelines in coordination with the Partnership.

The volume of shipments on the East Texas, Midcoast, Northeast Texas and South Texas 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 shipped on these systems also are affected by the demand for natural gas and NGLs in the markets these systems serve.

The Partnership's long-term financial condition will be dependent on the continued availability of natural gas for transportation to the markets served by the East Texas, Midcoast, Northeast Texas and South Texas systems. Existing customers may not extend their contracts if the availability of natural gas from the Mid-Continent, Gulf Coast and East Texas producing regions was to decline and if the cost of transporting natural gas from other producing regions through other pipelines into the East Texas, Midcoast, Northeast Texas or South Texas systems 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.

The tariff rates charged by several of the Partnership's pipeline systems are regulated by the FERC and/or various state regulatory agencies. If the tariff rates the Partnership is permitted to charge its customers for use of its regulated pipelines are lowered by one of these regulatory 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 tariff rates 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, which delay could further reduce the Partnership's cash flow. 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.

In a 1995 decision involving the Lakehead System, the FERC partially disallowed the inclusion of income taxes in the Partnership's cost of service. In another FERC proceeding involving an unrelated oil pipeline limited partnership, the FERC ruled that the oil pipeline limited partnership could not claim an income tax allowance for income attributable to non-corporate limited partners, both individuals and non-corporate entities. These decisions might adversely affect the Partnership's FERC-regulated pipelines and/or services in connection with future rate increases and in defending its existing rates against challenges by its customers. Any significant difficulty in increasing or defending its rates could adversely affect the results of operations of the Partnership.

The Partnership is involved in two disputes regarding the current tariff rates that it charges shippers on its Kansas pipeline system as well as a rate proceeding before the FERC to establish new tariff rates for that system. These disputes and proceedings are summarized below. Reference is made to "Management's Discussion and Analysis of Financial Condition and Results of Operations—Other Matters—Regulatory Matters" for additional information.

Initial Rate Dispute. When the Kansas pipeline system became subject to FERC jurisdiction in 1998, the FERC established initial rates based upon an annual cost of service of approximately $31 million. Since that time, these initial rates have been the subject of various ongoing challenges that are nearing resolution.

FERC Rate Proceeding The FERC issued an order in September 2002 requiring that the Kansas pipeline system charge rates based on an annual cost of service of approximately $21 million. On March 19, 2003, FERC issued an Order of Rehearing which, except for limited exceptions, affirmed its prior decision. Unless the Kansas pipeline system seeks a court review resulting in the Order being over-turned, the tariff rates that the Partnership will be able to charge for shipments on the Kansas pipeline system, future revenues from this system are anticipated to approximate the level currently being reflected in the financial statements.

Kansas Gas Service Dispute. Kansas Gas Service, a major customer of the Kansas pipeline system, has been making only partial payments of amounts invoiced for service based on its claim that it is contractually entitled to a lower tariff rate. The amount of any underpayment by Kansas Gas Service after October 14, 2002 is the responsibility of the Partnership. This dispute is the subject of ongoing state and federal court proceedings as well as proceedings before the FERC.

The Lakehead System faces competition from other pipelines and other methods of delivering crude oil and refined products for the transportation of western Canadian crude oil. This competition is present when delivering 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 the 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.

The Partnership also encounters competition in its natural gas gathering, processing and transmission businesses. Many of the large wholesale customers served by 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. 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 the Partnership's natural gas marketing competitors have greater financial resources and access to larger supplies of natural gas than those available to the Partnership, which could allow those competitors to price their services more aggressively than the Partnership.

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:

Since 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 all 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.

As part of its gas marketing activities, the Partnership purchases natural gas at prevailing market prices. Following the purchase of natural gas, the Partnership generally resells natural gas at a higher price under a sales contract that has comparable terms to the purchase contract, including any price escalation provisions. The profitability of the Partnership's natural gas marketing operations may be affected by the following factors:

The Partnership's pipeline operations are subject to federal and state laws and regulations relating to environmental protection and operational safety. Pipeline 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 or through higher tariffs.

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, on its operations. The Partnership is encouraged by recent reactions by Western Canadian crude oil producers to Kyoto, particularly their commitment to oil sands development, which support the outlook for the sustainability of supply for the Lakehead System.

Operation of a complex pipeline system involves 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 transport large quantities of natural gas containing hydrogen sulfide, a highly toxic substance. 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 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.

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 model, effective integration of the acquired operations and diversion of management's attention from existing operations. In addition, the Partnership may be unable to identify 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.

With the acquisition of the Midcoast assets, the Partnership acquired the South Texas system, which includes the right to purchase 500 miles of natural gas transmission pipelines for $41 million. The closing of this transaction is subject to, among other things, Transco acquiring from the Partnership capacity in the South Texas system to serve an existing Transco customer. The Partnership may seek to renegotiate the terms of this acquisition or may determine not to complete it.

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:

There are inherent difficulties in quantifying oil measurement losses because physical measurements of volumes are not practical due to the fact that products constantly move through the pipeline and virtually all of the pipeline system is located underground. In the Partnership's case, measuring and quantifying oil measurement losses is especially difficult 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. Accordingly, the Partnership utilizes engineering-based models and operational assumptions to estimate product volumes in its system and associated oil measurement losses.

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 should they act in a way that, were it not for these limitations of liability, would constitute breaches of their fiduciary duties.

State tax legislation resulting in the imposition of a partnership-level tax on the Partnership would 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, the states assessing tax on the Partnership are not significant. However, many states are considering increased taxes, some including partnership-level

taxes, in their current legislative processes. Any projection of tax is preliminary, but the enactment of significant legislation would cause a reduction in the value of our partnership units.

The Partnership currently conducts business and owns properties located in 17 states: Alabama, Arkansas, Illinois, Indiana, Kansas, Louisiana, Michigan, Minnesota, Mississippi, Missouri, Montana, New York, North Dakota, Oklahoma, Texas, Tennessee and Wisconsin. In general, the Lakehead, North Dakota, East Texas and Midcoast 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. An affiliate of the General Partner acquired parcels of property for the benefit of the Partnership to allow for the construction of the SEP II expansion program. The affiliate is continuing to sell these parcels to third parties while retaining an easement for the benefit of the Partnership.

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 Systems under the contribution agreement, certain filings with respect to title records were not made prior to the closing of the transaction. The Partnership or its subsidiaries have made, or will make, these filings as soon as practicable. 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.

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 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 rates set forth in the Partnership's tariffs will be determined based on competitive factors in addition to regulatory considerations.

The Partnership's AlaTenn Pipeline, MidLa Pipeline, Kansas Pipeline and UTOS Pipeline systems are interstate natural gas pipelines regulated by the FERC under the NGA, and the NGPA. Each system operates under separate FERC-approved tariffs that establish rates, terms and conditions under which each system provides service to its customers. In addition, the FERC's authority over natural gas companies that provide natural gas pipeline transportation services in interstate commerce includes:

Tariff changes can only be implemented upon approval by the FERC. There are two primary methods by which the rates, terms and conditions of service of an interstate pipeline may be changed. Under the first method, the company voluntarily seeks a tariff change by making a tariff filing with the FERC, which justifies the proposed tariff change and provides notice, generally 30 days, to the appropriate parties. 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 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.

Commencing in 1992, the FERC issued Order No. 636 and subsequent related orders, which we refer to collectively as "Order No. 636." Order No. 636 requires interstate pipelines to provide transportation and storage services separate, or "unbundled," from the pipelines' sales of natural gas. Also, Order No. 636 requires pipelines to provide open-access transportation and storage services on a basis that is equal for all shippers. The FERC has stated that it intends for Order No. 636 to foster increased competition within all phases of the natural gas industry. The courts largely have affirmed the significant features of Order No. 636 and numerous related orders pertaining to individual pipelines, although the FERC continues to review and modify its open access regulations.

In 2000, the FERC issued Order No. 637 and subsequent orders, which we refer to collectively as "Order No. 637." Order No. 637 imposes a number of additional reforms designed to enhance competition in natural gas markets. Among other things, Order No. 637 revised the FERC pricing policy by waiving price ceilings for short-term released capacity for a two-year period ending September 30, 2002, and effected changes in the FERC regulations relating to scheduling procedures, capacity segmentation, pipeline penalties, rights of first refusal and information reporting. The U.S. Court of Appeals for the District of Columbia Circuit recently issued a decision that either upheld or declared premature for review most major aspects of Order No. 637. Order No. 637 required interstate natural gas pipelines to implement the policies mandated by the order through individual compliance filings. The FERC has now ruled on a number of the individual compliance filings, although its decisions in such proceedings remain subject to the outcome of pending rehearing requests and possible court appeals. The Partnership cannot predict whether the FERC's actions will achieve the goal of increasing competition in markets in which it competes. However, the Partnership does not believe that the effect on the operations of its interstate natural gas pipelines or its other pipeline operations, which indirectly are affected by the extent and nature of the FERC's jurisdiction over activities in interstate commerce, will be affected by any action taken materially differently than other companies with whom it competes.

In addition to its jurisdiction over the UTOS system under the NGA and the NGPA, the FERC also has jurisdiction over the UTOS system and the Partnership' offshore gathering systems under the Outer Continental Shelf Lands Act, or "OCSLA." The OCSLA requires that all pipelines operating on or across the outer continental shelf, which we refer to as the "OCS," provide open-access, non-discriminatory transportation service on their systems. In 2000, the FERC issued Order Nos. 639 and 639-A, which we refer to collectively as "Order No. 639," which required "gas service providers" operating on the OCS to make public their rates, terms and conditions of service. The purpose of Order No. 639 was to provide regulators and other interested parties with sufficient information to detect and to remedy discriminatory conduct by such service providers. In a recent decision, the U.S.

District Court for the District of Columbia Circuit permanently enjoined the FERC from enforcing Order No. 639, on the basis that the FERC did not possess the requisite rule-making authority under the OCSLA for issuing Order No. 639. The FERC's appeal of the court's decision is pending in the U.S. Court of Appeals for the District of Columbia Circuit. The Partnership cannot predict the outcome of this appeal, nor can it predict what further action the FERC will take with respect to this matter.

On September 27, 2001, the FERC issued a Notice of Proposed Rulemaking in Docket No. RM01-10. The proposed rules would expand the FERC's current standards of conduct to include a regulated transmission provider and all of its energy affiliates. It is not known whether the FERC will issue a final rule in this docket and, if it does, whether the Partnership could, as a result, incur increased costs and increased difficulty in its operations.

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 very heavily regulated; therefore, there is no assurance that the less stringent regulatory approach recently pursued by the FERC and Congress will continue especially in-light of alleged market power abuse by marketing affiliates of certain large interstate pipeline companies.

In a 1995 decision involving the Partnership's Lakehead System, the FERC partially disallowed the inclusion of income taxes in the cost of service for the Lakehead System. Subsequent appeals of this ruling were resolved by settlement and were not adjudicated. In another FERC proceeding involving SFPP, L.P., an unrelated pipeline limited partnership, the FERC held that the limited partnership may 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 have appealed the FERC's orders to the U.S. Court of Appeals for the District of Columbia Circuit, which is holding the appeals in abeyance while the FERC resolves requests for rehearing of its orders. The effect of the FERC's policy stated in the Lakehead proceeding (and the results of the ongoing SFPP litigation regarding that policy) on the Partnership is uncertain. Parties may challenge rates on the Partnership' common carrier interstate liquids pipelines or its interstate natural gas pipelines on the basis that its rates are not just and reasonable because the level of income tax allowance in its rates exceeds that permitted under the Lakehead and/or SFPP decisions. While it is not possible to predict the likelihood that parties will assert such challenges or that such challenges would succeed, if such challenges were to be raised and succeeded, application of the Lakehead/SFPP and related rulings would reduce permissible income tax allowance in any cost-of-service based rate, to the extent income tax is attributed to partnership interests held by individual partners rather than corporations.

The Partnership's 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 its intrastate pipeline systems transport natural gas in interstate commerce, the rates, terms and conditions of such transportation service are subject to FERC jurisdiction under Section 311 of the NGPA, which regulates, among other things, the provision of transportation services by an intrastate natural gas pipeline 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.

In connection with the acquisition of the Midcoast System, the entities that own the AlaTenn Pipeline and the MidLa Pipeline were converted from corporations into limited liability companies. These conversions occurred under statutes that provide that the converted entity continues its legal existence as the same entity following conversion and continues to hold all of the same rights and obligations that it held prior to the conversion. The FERC generally has determined that a pipeline owner that converts from a corporation into a limited liability company in accordance with the appropriate statute is not required to seek FERC approval for the conversion. Rather, the FERC recognized the conversions by approving a new tariff for the AlaTenn Pipeline and the Midla Pipeline that reflects those entities new name and organizational form.

In addition, the other subsidiaries, which converted or merged into limited liability companies, could be required to reduce the rates that they charge for interstate transportation or transactions under Section 311 of the NGPA, which are subject to FERC jurisdiction. Such rates can only be changed in the context of a future rate adjustment before the FERC.

The Partnership cannot predict what effect, if any, these conversions will have on the rates the affected pipelines will be allowed to charge in the future.

Section 1(b) of the NGA exempts natural gas gathering facilities from the jurisdiction of the FERC under the NGA. The Partnership owns certain natural gas pipelines that it believes meet the traditional tests the FERC has used to establish a pipeline's status as a gatherer not subject to the FERC jurisdiction. State regulation of gathering facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory take requirements, but generally does not entail rate regulation. Natural gas gathering may receive greater regulatory scrutiny at both the state and federal levels now that the FERC has taken a more light-handed approach to regulation of the gathering activities of interstate pipeline transmission companies and a number of such companies have transferred gathering facilities to unregulated affiliates. For example, the Texas Railroad Commission has approved changes to its regulations governing transportation and gathering services performed by intrastate pipelines and gatherers, which prohibit such entities from unduly discriminating in favor of their affiliates. Many of the producing states have 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. The Partnership's 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. The Partnership's 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. Additional rules and legislation pertaining to these matters are considered or adopted from time to time. The Partnership cannot predict what effect, if any, such changes might have on its operations, but the industry could be required to incur additional capital expenditures and increased costs depending on future legislative and regulatory changes.

The price at which the Partnership sells natural gas currently is not subject to federal or state regulation except for certain systems in Texas. The Partnership's sales of natural gas are affected by the availability, terms and cost of pipeline transportation. As noted above, the price and terms of access to pipeline transportation are subject to extensive federal and state regulation. The FERC is continually proposing and implementing new rules and regulations affecting those segments of the natural gas industry, most notably interstate natural gas transmission companies, that remain subject to the FERC's

jurisdiction. These initiatives also may affect the intrastate transportation of natural gas under certain circumstances. The stated purpose of many of these regulatory changes is to promote competition among the various sectors of the natural gas industry and these initiatives generally reflect more light-handed regulation. The Partnership cannot predict the ultimate impact of these regulatory changes to its natural gas marketing operations, and the Partnership notes that some of the FERC's more recent proposals may adversely affect the availability and reliability of interruptible transportation service on interstate pipelines. The Partnership does not believe that it will be affected by any such FERC action materially differently than other natural gas marketers with whom it competes.

The Partnership's 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 are 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 result in an increase in the cost of transportation service on certain petroleum products pipelines. However, the Partnership does not believe that these regulations affect it any differently than other marketers of these products.

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.

Under published tariffs for transportation on the Lakehead System, the rates for transportation of light crude oil from Neche, North Dakota (unless otherwise stated) to principal delivery points at December 31, 2002 (including the tariff surcharges related to Lakehead System expansions) are set forth below.

	Published Tariff Per Barrel
To Clearbrook, Minnesota	$	0.173
To Superior, Wisconsin	$	0.338
To Chicago, Illinois area	$	0.691
To Marysville, Michigan area	$	0.826
To Buffalo, New York area	$	0.846
Chicago to the international border near Marysville	$	0.306

The rates at December 31, 2002 for medium and heavy crude oils are higher and those for NGLs are lower than the rates set forth in the table to compensate for differences in costs for shipping different types and grades of liquid hydrocarbons. The Partnership periodically adjusts its tariff rates as allowed under the FERC's indexing methodology and the tariff agreement described below.

Under a tariff agreement approved by the FERC in 1999, the Partnership implemented a tariff surcharge for the Terrace expansion of approximately $0.013 per barrel (for light crude oil from the Canadian border to Chicago, Illinois). On April 1, 2001, the surcharge was increased to $0.026 per barrel. Subject to any adjustments permitted under the tariff agreement, this toll will be effective until April 1, 2004, when, absent any agreement from Enbridge stating otherwise, the toll will change to $0.007 per barrel to the Partnership. This new toll will be in effect for the next six years, after which

time it will return to $0.013 per barrel for the Partnership. The tariff surcharge is based on the completion of all three phases of the Terrace expansion.

Tariff rates on the FERC-regulated natural gas pipelines vary by pipeline and by receipt point and delivery point. The rates charged for transmission of natural gas on pipelines not regulated by the FERC or a state agency are established by competitive forces. Please read Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations.

The Partnership's transmission and gathering pipelines and storage and processing facilities are subject to extensive federal and state environmental, operational and safety regulation. Many federal and state agencies are authorized by statute to issue and have issued a variety of rules and regulations that are binding on the pipeline and other activities of the Partnership. The failure to comply with such rules and regulations can result in substantial penalties and/or enforcement actions. The regulatory burden on the pipeline and operational activities increases the Partnership's cost of doing business and, consequently, affects its profitability. However, the Partnership does not believe that it is affected in a significantly different manner by these regulations than its competitors. Due to the myriad and complex federal and state statutes and regulations that may affect the Partnership, directly or indirectly, the following discussion of certain statutes and regulations should not be considered an exhaustive review of all regulatory considerations affecting the Partnership's operations.

The Partnership's transmission and non-rural gathering pipelines are subject to regulation by the U.S. DOT, under the Title 49 United States Code (Pipeline Safety Act) ("PSA") relating to the design, installation, testing, construction, operation, replacement and management of transmission and non-rural gathering pipeline facilities. The PSA requires pipeline operators to comply with regulations issued pursuant to the PSA, to permit access to and allow copying of pipeline records, and to make certain reports and provide information as required by the Secretary of Transportation.

On December 17, 2002 the "Pipeline Safety Improvement Act of 2002" (Act) was signed into legislation amending the PSA in several important respects. The PSA is subject to periodic reauthorization and the December 2002 legislation reauthorizes the PSA through 2006. The Act requires the DOT to issue regulations requiring natural gas pipeline operators to establish written integrity management plans for pipeline segments in high consequence areas, including a mandate to complete baseline integrity testing of such segments within ten years and at intervals of every seven years thereafter. The DOT is also mandated to establish criteria for assuring that pipeline companies conduct a worker-qualification program and conduct a pilot study on the feasibility of the DOT certification of pipeline control center operators. The DOT was also granted broader authority to involve states in assuring compliance with federal rules; increased enforcement authority and issue higher penalties for non-compliance. The Act also requires pipeline operators to submit electronic maps to the DOT; develop and evaluate public awareness plans, refrain from retaliation if workers alert authorities to safety concerns, cooperate with investigations of incidents or face penalties, along with several other mandates.

Following previous mandates in the PSA, the DOT has issued a number of amendments to pipeline safety regulations. Effective April 27, 2001, operators of regulated natural gas and liquids pipeline facilities must have a written operator qualification program. After October 28, 2002, all employees performing covered tasks on these pipeline facilities must be qualified under this written

program. Effective March 31, 2002, operators of hazardous liquid pipelines subject to the regulations are required to assess, evaluate, repair and validate through a comprehensive analysis the integrity of hazardous liquid pipeline segments that, in the event of a leak or failure, could effect a high consequence areas defined as populated areas, areas unusually sensitive to environmental damage or commercially navigable waterways. The DOT regulations require the integrity testing of hazardous liquid pipelines in high consequence areas through internal inspection, hydrostatic testing or other equally effective assessment means. On January 28, 2003, the DOT proposed similar rules requiring development of integrity management plans and integrity testing of natural gas pipelines in high consequence areas. The definition of high consequence areas for natural gas pipelines is focused on places of high population, nearby buildings of persons of limited mobility or places of congregation. Natural gas pipelines in such areas will have ten years to complete integrity testing and must undergo a prescribed future interval of integrity testing. Final rules are expected to be issued by mid-2003.

The DOT has proposed or has announced intentions to propose additional regulations requiring annual reports for liquid pipelines, revised standards for public awareness plans by pipeline operators and is evaluating the need to regulate all gathering pipelines rather than non-rural gathering lines currently under the jurisdiction of the PSA. Pending specific proposed regulations, the Partnership is not certain of the effect or costs new requirements may have on its operations.

Although states are largely preempted by federal law from regulating the design, operation and safety of interstate pipelines, some states have assumed responsibility for enforcing federal pipeline regulations and have established a program of regulating and inspecting intrastate pipelines.

Specifically in Texas, effective February 1, 2002, operators of intrastate transmission and non-rural gathering lines are required to have an Integrity Assessment and Management Program in place which requires a prescriptive plan for pressure tests or an operator developed risk-based plan that uses a combination of risk analysis, hydrostatic testing or internal inspections and appropriate risk remedial actions. Management is not aware at this time how the proposed new DOT regulations on integrity management will affect the requirements of the Texas regulations, if at all.

Under the Homeland Security Act passed by Congress in 2002, the DOT's Transportation Safety Agency, who now has oversight over pipeline security, will be transferred to the newly establish Department of Homeland Security. It is expected that the DOT and Homeland Security will enter into a memorandum of understanding, thus that the DOT will retain inspection authority over pipeline security plans and potential new federal regulations.

The Partnership's 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 materials and other materials. The Partnership believes that its pipeline, trucking and railcar operations are in substantial compliance with applicable operational and safety requirements. 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 its current pipeline control system or other safety equipment.

General. The Partnership's 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 the overall cost of doing business, including its capital costs to construct, maintain, and upgrade equipment and facilities. While these laws and regulations affect its maintenance capital expenditures and net

income, the Partnership believes that they do not affect its competitive position since the operations of its competitors are 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. The Partnership believes that its operations are in substantial compliance with applicable environmental laws and regulations. However, these laws and regulations are subject to frequent change at the federal, state and local levels, and the clear trend is to place increasingly stringent limitations on activities that may affect the environment. Therefore, the Partnership is unable to predict the ongoing cost of complying with these laws and regulations or their future impact on its operations.

There are also risks of accidental releases into the environment associated with the Partnership's operations, such as leaks or spills of crude oil, liquids or natural gas or other substances from its pipelines or storage facilities. Such accidental releases could, to the extent not insured, subject the Partnership 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 or penalties for any related violations of environmental laws or regulations.

Although the Partnership is entitled in certain circumstances to indemnification from third parties for environmental liabilities relating to assets that it acquired from those parties, these contractual indemnification rights are limited and, accordingly, the Partnership may be required to bear substantial environmental expenses.

Enbridge Management has managerial control over the operations of the Partnership. The Partnership is primarily responsible for performing duties imposed under environmental laws, such as obligations to clean up hydrocarbons or other materials that are released into the environment. However, to the extent that the Partnership incurs but does not perform or complete obligations imposed under environmental laws, Enbridge Management may be held liable for the costs and liabilities arising from those obligations as the party with managerial control over the operations of the Partnership.

Air Emissions. The Partnership's operations are subject to the federal CAA and comparable state and local statutes. These laws generally require facilities that emit air contaminants into the atmosphere to implement or achieve certain technological or performance-based emissions controls and to comply with various permitting, monitoring and reporting regulations. Amendments to the CAA enacted in 1990, as well as recent or soon to be adopted changes to state implementation plans implementing those amendments, require or will require most industrial operations in the United States to make capital expenditures in order to meet new air emission control standards developed by the U.S. EPA, and state environmental agencies. As a result of these amendments, the Partnership's facilities are subject to increasingly stringent air emissions regulations, including requirements that some facilities install maximum or best achievable control technologies to reduce or eliminate regulated emissions. A number of the Partnership's facilities are currently exempt from these air emissions regulations due to their age. Over the next several years, however, the exemptions for such "grandfathered" facilities are due to expire. The Partnership anticipates, therefore, that it will incur certain capital expenses in the next several years for air pollution control equipment in connection with maintaining existing facilities and obtaining permits and approvals for any new or acquired facilities. For example, the Partnership estimates it will incur up to $3.5 million in capital expenditures to upgrade its air pollution control equipment at the Tilden Gas Plant on the South Texas system. In addition, state and local air quality regulations can be more stringent than federal regulations in some circumstances, particularly in areas where national air quality standards have not been achieved. Although the Partnership can give no assurances, it believes compliance with these CAA requirements will not have a material adverse effect

on its financial condition or results of operations and that such requirements do not affect its competitive position since the operations of its competitors are similarly affected.

Hazardous Substances and Waste Management. The federal 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. CERCLA also authorizes the EPA and, in some cases, third parties to take actions in response to threats to public health or the environment at such disposal sites and to seek recovery of the costs they incur from the responsible classes of persons. Although "petroleum" is currently excluded from CERCLA's definition of a "hazardous substance," in the course of its ordinary operations the Partnership may generate some wastes that fall within the definition of a "hazardous substance." The Partnership 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. The Partnership has not received any notification that it may be potentially responsible for cleanup costs under CERCLA or similar state laws.

The Partnership's operations also generate both hazardous and nonhazardous wastes that are subject to the requirements of the federal RCRA, and comparable state statutes. The Partnership is not currently required to comply with a substantial portion of RCRA's requirements as its operations generate minimal quantities of hazardous wastes. From time to time, however, the EPA has considered making changes in nonhazardous waste standards that would result in stricter disposal requirements for these wastes, including certain petroleum wastes. Furthermore, it is possible that some of the wastes the Partnership generates that are currently classified as nonhazardous may in the future be reclassified as "hazardous wastes," which would trigger more rigorous and costly disposal requirements. In addition, analogous state and local laws may impose more stringent waste disposal requirements or apply to a broader range of wastes. While federal or state regulatory changes could result in an increase in the Partnership's maintenance capital expenditures and operating expenses, the Partnership believes that they would not effect its competitive position since the operations of its competitors would be similarly affected.

Water. The CWA and similar state laws place strict limits on the discharge of contaminants into federal and state waters. Regulations under these laws prohibit such discharges unless authorized by and in compliance with a National Pollutant Discharge Elimination System permit or an equivalent state permit. The CWA and analogous state laws allow significant penalty assessments for unauthorized releases of water pollution and impose substantial liability for the costs of cleaning up spills and leaks into the water. In addition, the CWA and analogous state laws require individual permits or coverage under general permits for discharges of stormwater runoff from certain types of facilities. State laws may also place restrictions and cleanup requirements on the release of pollution into groundwater. The Partnership believes that it will be able to obtain, or be covered under, any required CWA permits and that compliance with the conditions of those permits will not have a material effect on its operations.

The 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, the Partnership could be subject to strict, joint and potentially unlimited liability for removal costs and other consequences of an oil spill from its 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 the Partnership's 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 the Partnership's pipeline facilities, the OPA imposes requirements for emergency plans to be prepared, submitted and approved by the DOT. The Partnership believes it is in material compliance with these laws and promulgating regulations.

Employee Health and Safety. The workplaces associated with the Partnership operations are subject to the requirements of the federal OSHA and comparable state statutes that regulate worker health and safety. In addition, some states have received authorization to implement their own occupational safety and health programs in lieu of the federal program. the Partnership has an ongoing safety training program for its employees and believes that its operations are in material compliance with applicable occupational health and safety requirements, including general industry standards, record keeping requirements, monitoring of occupational exposure to regulated substances, and hazard communication standards.

Site Remediation. The Partnership owns and operates 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 for many years. Certain facilities, including the Lakehead System, have been operated by the Partnership or its predecessors for more than 50 years. Many of the other facilities of the Partnership were previously owned and operated by third parties whose handling, disposal and release of petroleum and waste materials were not under the Partnership's control. The age of the facilities combined with the past operating and waste disposal practices, which were standard for the industry 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 petroleum industry. Any historical contamination found on, under or originating from the Partnership's properties may be subject to CERCLA, RCRA and analogous state laws as described above. Under these laws, the Partnership could incur substantial expense to remediate any such contamination, including contamination caused by prior owners and operators. In addition, Enbridge Management, as the entity with managerial responsibility for the Partnership, could also be liable for such costs to the extent that the Partnership is unable to fulfill its obligations. The Partnership has conducted site investigations at some of its facilities to assess historical environmental issues, and it is currently addressing soil and groundwater contamination at various facilities through remediation and monitoring programs, with oversight by the applicable government agencies where appropriate.

Most of the environmental site investigations of the Partnership's facilities were performed in connection with the acquisition of assets from third parties. Environmental liabilities identified in these investigations were handled in several ways. In some instances, historical environmental liabilities were assumed upon the acquisition of assets. In connection with one acquisition, the Partnership has been advised that the total cost to remediate environmental contamination at several sites on the Northeast Texas system is estimated to be approximately $7.0 million. In other circumstances, assets were acquired subject to indemnities from the sellers which are intended to protect the Partnership from specific historical environmental liabilities. There are also instances where only parts of assets were acquired, leaving the seller with the portions believed to be more severely affected by historical environmental liabilities. In connection with the Partnership's acquisition of the Midcoast System, Northeast Texas and South Texas systems under the contribution agreement, the General Partner has agreed to indemnify the Partnership and other related persons for certain environmental liabilities of which the General Partner has knowledge but, did not disclose under the contribution agreement. The General Partner will not be required to indemnify the Partnership under the contribution agreement until the aggregate liabilities, including environmental liabilities, exceed $20 million, and the General Partner's aggregate liability under the contribution agreement, including environmental liabilities, may not exceed, with certain exceptions, $150 million. The Partnership will be liable for any environmental conditions related to the acquired systems that were not known to the General Partner or were disclosed under the contribution agreement. In addition, the Partnership will be liable for all removal, remediation and

disposal of all asbestos containing materials and all naturally occurring radioactive materials associated with the Northeast Texas system and for which the General Partner is liable to the prior owner of that system.

Although the Partnership believes these indemnities and carve outs provide valuable protection, it is possible that the sellers from whom these assets were purchased will not be able to satisfy their indemnity obligations or their remedial obligations related to retained liabilities or properties. In this case, it is possible that governmental agencies or third party claimants could assert that the Partnership may be liable or bears some responsibility for such obligations.

The Partnership could also experience future spills or releases from its pipelines, gathering systems, storage facilities, or trucking or rail operations, or it could discover historical releases that were previously unidentified. To guard against these risks, the Partnership maintains an extensive inspection and maintenance program designed to prevent, detect and address such releases promptly, and it has obtained insurance policies designed to provide additional protection against unknown historical environmental liabilities related to certain assets, including the Northeast Texas and East Texas systems. The Partnership could nevertheless incur significant penalties, damages and remedial liabilities arising from future spills or the discovery of previously unknown historical releases. Such liabilities could have a material adverse effect on the Partnership's financial condition and results of operations.

The Partnership, nor Enbridge Management, has any employees. The General Partner has delegated to Enbridge Management, pursuant to the Delegation of Control Agreement, substantially all of the responsibility for the day-to-day management and operation of the Partnership. The General Partner, however, retains, certain functions and approval rights over the operations of the Partnership. To fulfill the 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 will act on Enbridge Management's behalf as its agents. The Partnership is ultimately responsible for reimbursing these service providers based on the costs that they incur in performing these services.

The operations of the Partnership are subject to many hazards inherent in the liquid petroleum and natural gas gathering, processing and transmission industry. The Partnership maintains insurance coverage for its operations and properties considered to be customary in the industry. There can be no assurance, however that insurance coverages maintained by the Partnership will be available or adequate for any particular risk or loss or that it will be able to maintain adequate insurance in the future at rates it considers reasonable. Although management believes that the assets of the Partnership are adequately covered by insurance, a substantial uninsured loss could have a material adverse effect on the Partnership's financial position, results of operations or cash flows.

In 2002, the Partnership made capital expenditures of $214.7 million, of which $23.0 million was for pipeline system enhancements, $14.2 million for core maintenance activities and $177.5 million for the Terrace expansion program. These amounts do not include the acquisition costs for the Midcoast System. See "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations."

For U.S. federal and state income tax purposes, the Partnership is not a taxable entity. Federal and state income taxes on Partnership taxable income are borne by the individual partners through the allocation of Partnership taxable income. Such taxable income may vary substantially from net income reported in the statement of income.

In October 2002, the Partnership acquired the Midcoast, Northeast Texas, and South Texas systems from the General Partner (the "Acquisition"). A committee of independent members of the Board of Directors of the General Partner negotiated the purchase price and terms of the Acquisition on behalf of the Partnership's public unitholders and recommended that the Board approve the acquisition. The independent committee retained their own expert financial and legal advisors to assist in this process and the financial advisor rendered a fairness opinion in connection with the Acquisition.

In November 2002, the staff of the SEC advised the Partnership, Enbridge Management, the General Partner and Enbridge (the "Enbridge Group"), that they had commenced an informal inquiry into the Acquisition and the initial public offering by Enbridge Management. The SEC staff has advised the Partnership that their principal focus includes the financial forecast made in connection with the Acquisition and the price paid for the assets. The SEC staff has not asserted that the Partnership or the other Enbridge entities has acted improperly or illegally, and it has not indicated an intention to seek a formal order of investigation. The Partnership is cooperating fully with SEC staff.

Based on a recently completed internal review of the forecast and terms of the Acquisition, the Enbridge Group continues to believe that the financial forecast had a reasonable basis and the price paid for the assets was fair to the Partnership. The Partnership believes that the informal investigation will not have a material adverse effect on the financial condition of the Partnership.

The Partnership is a party in a limited number of legal proceedings arising in the ordinary course of business. The Partnership believes that the outcome of these matters will not, individually or in the aggregate, have a material adverse effect on the financial condition of the Partnership.

Item 5. Market for Registrant's Common Equity and Related Stockholder Matters

The Partnership's Class A Common Units are listed and traded on the New York Stock Exchange, the principal market for the Class A Common Units, under the symbol EEP. The quarterly price range

per Class A Common Unit and cash distributions paid per unit for 2002 and 2001 are summarized as follows:

	First		Second		Third		Fourth
2002 Quarters
High	$	46.25	$	46.75	$	46.25	$	44.00
Low	$	41.00	$	43.15	$	35.68	$	37.80
Cash distributions paid	$	0.90	$	0.90	$	0.90	$	0.90
2001 Quarters
High	$	46.90	$	46.50	$	49.60	$	48.90
Low	$	41.25	$	43.80	$	39.50	$	38.90
Cash distributions paid	$	0.875	$	0.875	$	0.875	$	0.875

On March 26, 2003, the last reported sales price of the Class A Common Units on the New York Stock Exchange was $45.23. At March 26, 2003, there were approximately 48,000 Class A Common Unitholders of which there were approximately 2,300 registered Class A Common Unitholders of record. There is no established public trading market for the Partnership's Class B Common Units, all of which are held by the General Partner, or the i-units, all of which are held by Enbridge Management.

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

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

The following discussion and analysis should be read in conjunction with the consolidated financial statements and accompanying notes of the Partnership listed in the Index to Financial Statements on page F-1 of this report. Material period-to-period variances in the consolidated statements of income are discussed by business segment under "Results of Operations". The "Liquidity and Capital Resources" section analyzes cash flow and financial position. "Other Matters" addresses future prospects, regulatory matters and recent accounting developments.

The Partnership had a pivotal year in 2002. The growth strategy that was initiated in 2001, with the acquisitions of the North Dakota and East Texas systems, was further enhanced by the acquisition of the Midcoast System in the fourth quarter of 2002. In addition, a new source of capital was made available to the Partnership with the issuance of a new class of limited partner units called "i-units," concurrent with the acquisition of the Midcoast System. On the Lakehead System, expansion work continued on the Terrace Phase III project, along with construction of additional pipeline facilities in the Chicago area to improve delivery flexibility, in anticipation of future increased volumes from the Alberta oil sands projects in western Canada. Deliveries on the Lakehead System were impacted by pressure restrictions on one of the lines following a leak in Minnesota in July 2002. However, the effect on its customers was minimized due to efforts taken to advance the in-service date on a portion of the Terrace Phase III project in the affected area. Active clean-up measures at the leak site were completed prior to winter, and it is expected that final remediation efforts will take place in the spring of 2003.

As a result of the Midcoast System acquisition in October 2002, the Partnership changed its internal management organization effective in the fourth quarter of 2002. The Partnership now conducts its business through five business segments: Liquids Transportation, Natural Gas Transportation, Gathering and Processing, Marketing and Corporate. These segments are strategic business units established by senior management to facilitate the achievement of the Partnership's long-term objectives, to aid in resource allocation decisions and to assess operational performance.

Liquids Transportation includes the operations of the Lakehead System, which consists of crude oil and liquid petroleum transportation and storage assets in the Great Lakes and Midwest regions of 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. Liquids Transportation also includes the operations of the North Dakota System, which includes crude oil gathering lines connected to a transportation line that interconnects directly with the Lakehead System in the State of Minnesota.

Natural Gas Transportation consists of four FERC regulated natural gas transmission pipeline systems and 35 intrastate natural gas transmission and wholesale customer pipeline systems located in the Mid-Continent and Gulf Coast regions of the United States. These pipeline systems form part of the Midcoast System assets that were acquired from the General Partner in October 2002.

Gathering and Processing includes the East Texas System, acquired on November 30, 2001, and, the Northeast Texas System, the South Texas System and certain other assets of the Midcoast System, all of which were acquired from the General Partner in October 2002. Collectively, these systems

include natural gas gathering and transmission pipelines, twelve natural gas treating plants and eleven natural gas processing plants. The Midcoast System assets also include trucks, trailers and rail cars used for transporting NGLs, crude oil and carbon dioxide. These assets are largely located in the mid-continent and Gulf Coast regions of the United States.

Marketing primarily provides natural gas supply, transmission and sales services for producers and wholesale customers using the Partnership's pipelines as well as other interconnected pipeline systems. Natural gas marketing activities are primarily undertaken to increase pipeline utilization, realize incremental margins on gas purchased at the wellhead, and provide value added services to customers.

Corporate consists of costs of financing, interest income, minority interest and certain other costs such as franchise taxes, that are not allocated to the other business segments.

The Partnership's financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America. The preparation of these financial statements requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses and related disclosures with respect to contingent assets and liabilities. The basis for these estimates is historical experience, consultation with experts and various other assumptions that are believed to be reasonable, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results could differ from these estimates under different assumptions or conditions. Any effects on the Partnership's business, financial position or results of operations resulting from revisions to these estimates are recorded in the period in which the facts that give rise to the revision become known. The Partnership believes the critical accounting policies discussed in the following paragraphs affect the more significant judgments and estimates used in the preparation of its consolidated financial statements.

Revenues of the Liquids Transportation segment are derived from interstate transportation of crude oil and liquid petroleum under tariffs regulated by the FERC. The tariffs specify the amounts to be paid by shippers for service between receipt and delivery locations and the general terms and conditions of transportation service on the respective pipeline systems. Revenues are recorded upon delivery. The Partnership does not own the crude oil and liquid petroleum that it transports, and therefore does not assume the related commodity risk.

Revenues of the Natural Gas Transportation segment are generally derived from 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. Revenues are recognized as natural gas is delivered to customers.

Revenues of the Gathering and Processing segment are derived from gathering and processing services under the following types of arrangements:

Fee-Based Arrangements: Under a fee-based contract, the Partnership receives a set fee for gathering, treating, processing and transmission of raw natural gas and providing other gathering

services. These revenues correlate with volumes and types of service, and do not depend directly on commodity prices.

Other Arrangements: The Partnership also utilizes other types of arrangements in its natural gas gathering and processing business:

Some of these arrangements expose the Partnership to commodity price risk, which is substantially mitigated by offsetting physical purchases and sales and financial derivative instruments. Revenues are recognized upon delivery of natural gas to customers or upon services rendered.

Revenues of the Marketing segment are derived from providing supply, transmission and sales service for producers and wholesale customers on the Partnership's natural gas gathering, transmission and customer pipelines, as well as other interconnected pipeline systems. Natural gas marketing activities are primarily undertaken to increase pipeline utilization, realize incremental margins on gas purchased at the wellhead, and provide value-added services to customers. In general, natural gas purchased and sold by the Marketing business 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 the request of some customers, the Partnership will enter into long-term fixed price purchase or sale contracts with its customers and usually will enter into offsetting positions under the same or similar terms. Revenues are recognized upon delivery of natural gas to customers or upon services rendered.

Property, plant and equipment is recorded at cost and is depreciated based on the estimated useful lives of the assets, which requires various assumptions to be made, including the supply of and demand for hydrocarbons in the markets served by assets, normal wear and tear of the facilities, and the extent and frequency of maintenance programs. Changes in any of these assumptions may impact the rate at which depreciation is recognized in the financial statements. Additionally, if it is determined that an asset's undepreciated cost may not be recoverable due to economic obsolescence, the business climate, legal and other factors, the asset would be reviewed for impairment and any necessary reduction in its value would be recorded as a charge against earnings. If there are changes to any of the estimates and assumptions, actual results may differ.

The Partnership's goodwill and intangible assets include values assigned to goodwill associated with the acquisitions of the East Texas and Midcoast Systems, as well as values assigned to contract-based assets that have a fixed or determinate term.

Goodwill represents the excess of the purchase price over the fair value of net tangible and intangible assets upon the acquisition of a business. Goodwill is tested for impairment at least annually and written down if the recorded value exceeds fair value. Fair value is assessed based on an estimate of future cash flows from the related assets. These cash flow estimates require the Partnership to make projections and assumptions for many years into the future for pricing, demand, competition, operating costs, legal and regulatory issues and other factors. Actual results can, and often do, differ from the projections and assumptions. These changes can have a negative impact on the estimates of impairment which would result in charges to income. In addition, further changes in the economic and business environment can impact the Partnership's original and ongoing assessments of potential impairment.

Other intangible assets, primarily consisting of customer contracts, are amortized on a straight-line basis over the life of the underlying assets. The Partnership tests other intangible assets periodically to determine whether impairment has occurred related to the underlying assets. Impairment occurs when the carrying amount exceeds the fair value of the recognized intangible asset. If there are changes to any of the estimates and assumptions relating to goodwill and other intangible assets, actual results may differ.

The Partnership recognizes all derivative financial instruments as assets and liabilities and measures them at fair value. Hedges of cash flow exposures are entered into to hedge a forecasted transaction or the variability of cash flows to be received or paid related to a recognized asset or liability. On the date that the Partnership enters into the derivative, it is designated as a cash flow hedge. Changes in the derivative fair values that are designated as cash flow hedges are deferred to the extent that the hedges are deemed highly effective and 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 value is recognized immediately in earnings.

The Partnership formally documents all derivative relationships between hedging instruments and hedged items, as well as its risk management objectives, strategies for undertaking various hedge transactions and its methods for assessing and testing correlation and hedge effectiveness. The Partnership also assesses, both at the inception of the hedge and on an on-going basis, whether the derivatives that are used in its hedging transactions are highly effective in offsetting changes in cash flows of the hedged item. If the Partnership determines that a derivative is no longer highly effective as a hedge, it discontinues hedge accounting prospectively by including changes in the fair value of the derivative in current earnings.

All financial instruments are employed in connection with an underlying asset, liability and/or anticipated transaction and are not used for speculative purposes. The fair value of all derivative financial instruments reflects the Partnership's best estimate and is based upon exchange-traded prices, published market prices or over-the-counter market price quotations, whenever they are available. Quoted valuations may not be available due to location differences or terms that extend beyond the period for which quotations are available. Where quotes are not available, the Partnership utilizes other valuation techniques or models to estimate market values. These modeling techniques require the Partnership to make estimations of future prices, price correlation and market volatility and liquidity. The estimates also reflect factors for time value and volatility 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. If there are changes

to these estimates and assumptions, actual results may differ and these differences may be positive or negative.

The oil shortage balance is recorded by the Partnership based on measurement estimates. These estimates are based on mathematical calculations and physical measurement and include assumptions related to the type of crude oil, its market value, normal physical losses due to evaporation and capacity limitations of the system. If there is a material change in these assumptions, it may result in a change to the carrying value of the oil overage balance or revision of oil measurement loss estimates.

Payables and receivables associated with the activity on natural gas pipeline operational balancing agreements and imbalances are booked monthly. These balances are either settled on a cash basis or are carried by the pipelines and shippers on an in-kind basis. Accruals associated with these in-kind balances are derived from the best available third party and internal documentation and are valued on a published third party index. If there is a change to these estimates and assumptions, actual results may differ.

AlaTenn, MidLa, UTOS and Kansas Pipeline systems are subject to the provisions of SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation." Regulatory assets represent probable future revenue to these pipelines associated with certain costs which will be recovered from customers through the regulatory or rate-making process. The FERC regulates the interstate transportation and certain sales of natural gas, including among other things, rates and charges allowed natural gas companies, extensions and abandonment of facilities and service, rates of depreciation and amortization and certain accounting methods utilized by the pipelines.

In the normal course of preparing the periodic financial statements, revenue and expense accruals are made to ensure amounts are complete and accurate on periodic basis. Judgments and estimates are necessary to prepare these accruals. Actual results are not expected to differ materially from these estimates.

Net income for 2002 was $78.1 million ($1.76 per unit) on revenues of $1,185.5 million, compared with $38.9 million ($0.98 per unit) on revenues of $342.3 million for 2001 and net income of $60.2 million ($1.78 per unit) on revenues of $307.0 million in 2000. The Partnership's consolidated operating income was $138.0 million in 2002, $97.8 million in 2001 and $117.9 million in 2000. Operating expenses, consisting of the cost of power, natural gas, operating and administrative and depreciation and amortization expenses, were $1,047.5 million in 2002, $244.5 million in 2001, and $189.1 million in 2000.

Increases in revenue, expenses and net income in 2002 compared to 2001 resulted from the full-year contribution of the East Texas System acquired in December 2001 and the partial year contribution from the Midcoast System acquired in October 2002. Increases in revenue and expenses and a decrease in net income in 2001 compared to 2000 relate to the acquisition of the East Texas System in December 2001 and two non-recurring charges for costs in 2001 for the Lakehead System related to the relocation of the Partnership's head office and an adjustment to oil measurement losses.

The following table reflects operating income by business segment and corporate charges for each of the years ended December 31, 2002, 2001 and 2000.

		2002			2001			2000
		(dollars in millions)
Operating Income
	Liquids Transportation	$	112.1		$	97.7		$	117.9
	Natural Gas Transportation		3.9			—			—
	Gathering and Processing		20.2			0.1			—
	Marketing		1.8			—			—

Total Operating Income			138.0			97.8			117.9
	Corporate		(59.9	)		(58.9	)		(57.7	)

Net Income		$	78.1		$	38.9		$	60.2

The Lakehead and North Dakota systems largely consist of FERC-regulated interstate crude oil and liquid petroleum pipelines. These systems generate most of their revenues by charging shippers a per barrel tariff rate to transport crude oil and liquid petroleum.

The Lakehead System links crude oil production from western Canada to markets in the Great Lakes and Midwest regions of the United States and the province of Ontario, Canada. Western Canadian crude oil production comes from two sources, conventional drilling and oil sands extraction projects. Currently, conventional drilling produces the majority of the supply, however, with the number of new oil sands construction projects in progress, this stable source of supply is expected to increase significantly over the next ten years.

Deliveries on the North Dakota System are impacted by the willingness of crude oil producers to maintain their crude oil production and exploration activities in North Dakota, Montana and the Province of Saskatchewan, Canada. Similar to the Lakehead System, the North Dakota System depends upon demand for crude oil in the Great Lakes and Midwest regions of the United States.

Operating income. Operating income for 2002 was $112.1 million compared with $97.7 million for 2001 and $117.9 million for 2000. Operating income was higher in 2002 compared with 2001 primarily due to higher revenues, partially offset by higher operating expenses. Operating income for 2002 includes the full year results of the North Dakota acquisition, whereas 2001 includes the results from the date of acquisition of May 18, 2001. Operating income for 2001 was lower than 2000 due to higher operating expenses, partially offset by higher revenue.

Operating revenue. Operating revenue for 2002 was $334.3 million compared with $313.3 million in 2001 and $307.0 million in 2000. Operating revenue was higher in 2002 compared to 2001 due to increased average tariffs, partially offset by lower deliveries on the Lakehead System, and a full year contribution from the North Dakota System. Average tariffs were higher due to positive adjustments calculated under FERC regulations and agreements with customers. As well, the amount of heavy oil transported on the Lakehead System, which attracts a higher tariff, was higher in 2002 compared to 2001. Operating revenue for 2001 was higher than 2000 due to increased average tariffs, partially offset by lower deliveries on the Lakehead System. Average tariffs were higher in 2001 primarily due to the tariff associated with the Terrace expansion that increased effective April 1, 2001.

Deliveries. Deliveries averaged 1.302 million bpd on the Lakehead System in 2002, compared to 1.315 million bpd in 2001 and 1.338 million bpd in 2000. Western Canadian crude oil production was comparable over the three years, however, volumes delivered on the Lakehead System declined over the period as western Canadian crude oil was delivered to other markets.

Operating and administrative expenses. Operating and administrative expenses were $104.7 million in 2002, $102.7 million in 2001 and $80.6 million in 2000. Operating and administrative expenses were higher in 2002 compared to 2001 due to higher workforce costs and expenses related to the Lakehead System pipeline leak in July, 2002, partially offset by lower oil measurement losses and the non-recurring charge in 2001 related to the relocation of the Partnership's head office to Houston. Operating and administrative expenses were higher in 2001 compared with 2000 due to higher oil measurement losses and head office relocation costs.

Depreciation expense. Depreciation expense was $64.8 million in 2002, $63.0 million in 2001 and $61.1 million in 2000. Depreciation expense was higher in 2002 compared to 2001 due to plant additions from the prior year and a full year impact of the North Dakota System. Depreciation was higher in 2001 compared to 2000 due to plant additions from the prior year.

The Partnership's FERC-regulated interstate natural gas transmission pipeline systems generally derive their revenue from capacity reservation fees charged for transmission of natural gas, while its intrastate pipelines generally derive their revenue from the bundled sales of natural gas and from transmission services. Customers of the Partnership's 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. In some cases, the Partnership's marketing operation uses the capacity on these pipeline systems to sell natural gas it owns to its customers, such as local distribution companies or industrial facilities.

The table below indicates the fourth quarter 2002 average daily volume, as well as total capacity reserved at December 31, 2002, for the major assets in the Partnership's Natural Gas Transportation segment in million British thermal units per day.

The Natural Gas Transportation segment was established upon the acquisition of the Midcoast System on October 17, 2002. Its results of operations are included in the Partnership's results since that date and therefore, there is no comparative data for prior periods.

The Partnership receives revenues for its gathering and processing services under the following types of arrangements:

Fee-Based Arrangements: Under a fee-based contract, the Partnership receives a set fee for gathering, treating, processing and transmission of raw natural gas and providing other gathering services. These revenues correlate with volumes and types of service, and do not depend directly on commodity prices. The Partnership prefers fee-based contracts because they produce relatively stable cash flows.

Other Arrangements: While the Partnership prefers fee-based contracts, it also utilizes other types of arrangements in its natural gas gathering and processing business, including:

Some of these other arrangements expose the Partnership to commodity price risk, which is mitigated by offsetting physical purchases and sales and the use of financial derivative instruments. In addition, the Partnership occasionally takes title to natural gas and NGLs for other reasons, such as to sell these products to customers. The Partnership will continue to hedge a significant amount of this commodity price risk to support the stability of cash flows. [Please read "Item 7A Quantitative and Qualitative Disclosures about Market Risk—Commodity Price Risk" for more information].

The table below indicates the average daily volume for each of the major systems in the Partnership's Gathering and Processing segment during the fourth quarter of 2002, in million British thermal units per day.

Gathering Systems		Mmbtu/d
East Texas System		429
Anadarko		222
Northeast Texas System		138
Tilden		30

Total		819

The East Texas System was acquired on November 30, 2001, and the remaining systems were purchased as part of the Midcoast System on October 17, 2002. Therefore, comparative results for 2001 include only one month of operations from the East Texas System and 2002 includes less than 3 months of operation of the Midcoast System.

The Partnership's marketing operation provides supply, transmission and sales service for producers and wholesale customers on its gathering, transmission and customer pipelines as well as other interconnected pipeline systems. Marketing activities are primarily undertaken to realize incremental margins on gas purchased at the wellhead, increase pipeline utilization and provide value added services to customers.

In general, natural gas purchased and sold by Marketing 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 the request of the customer, the Partnership will enter into long-term fixed price purchase or sales contracts with its customers and generally will enter into offsetting hedged positions under the same or similar terms.

The Marketing segment was established upon the acquisition of the Midcoast System on October 17, 2002. Its results of operation are included in the Partnership's results since that date, and therefore, there is no comparative data for prior periods.

Corporate consists of costs of financing, interest and other income, minority interest and certain other costs such as franchise taxes, which are not allocated to the other business segments.

Interest expense was $59.2 million in 2002 compared to $59.3 million in 2001 and $60.4 million in 2000. Increased interest expense from higher average debt balances was more than offset by lower

interest rates and higher interest capitalized on construction projects due to the Terrace expansion in 2002.

The Partnership believes that it will continue to have adequate liquidity to fund future recurring operating and investing activities. The primary cash requirements for the Partnership consist of normal operating expenses, maintenance and expansion capital expenditures, debt service payments, distributions to partners and acquisitions of new businesses. Short-term cash requirements, such as operating expenses, maintenance capital expenditures and quarterly distributions to partners, are expected to be funded by operating cash flows. Long-term cash requirements for expansion projects and acquisitions are expected to be funded through several sources, including cash flows from operating activities, borrowings under bank credit facilities, i-unit payment-in-kind distributions in lieu of cash and the issuance of additional debt and equity securities, including common units and i-units. The Partnership's ability to complete future debt and equity offerings will depend on various factors, including prevailing market conditions, interest rates and its financial condition and credit rating at the time.

During 2002, working capital increased by $110.2 million to ($61.1) million, primarily due to the decrease in the short-term loans from the General Partner. These loans were partially repaid with the net proceeds of the March, 2002 Class A Common Unit issuance and the balance was refinanced as part of the October, 2002 Midcoast acquisition from the General Partner. The remaining working capital deficit at December 31, 2002 of ($61.1) million is expected to be funded from operating cash flow.

At December 31, 2002, cash and cash equivalents totaled $60.3 million, up $20.1 million from December 31, 2001. Of this amount, $45.9 million was used for the cash distribution paid to unitholders on February 14, 2003 ($0.925 per unit), including $8.5 million of cash in respect of the i-units that was retained by the Partnership for use in its business. The net cash payment to Class A and Class B unitholders and the General Partner is $37.4 million. The remaining $14.4 million is available for future cash distributions, capital expenditures and other business needs.

Cash flows from operating activities for 2002 were $200.6 million, compared to $125.3 million for 2001. Cash flows from operating activities primarily reflect the effects of increased net income due to increased revenue on the Lakehead System, the incorporation of a full year of operating results from the North Dakota and East Texas systems, which were acquired in 2001, and the impact of the acquisition of the Midcoast System in October 2002.

Cash outflows used in investing activities were $557.2 million, compared with $302.1 million in 2001. In October 2002, the Partnership acquired the Midcoast System for a total purchase price of approximately $875.5 million after working capital and other adjustments. As of December 31, 2002, approximately $344.4 million in cash consideration had been paid for the assets with the remaining purchase price being comprised of assumed debt, a working capital amount payable and equity issued to the General Partner. For additional information regarding the Midcoast System acquisition, see Note 3 to the Partnership's Consolidated Financial Statements.

In 2003, the Partnership anticipates spending approximately $54 million for system enhancements, $27 million for core maintenance activities, $42 million for Lakehead System expansion projects and $41 million related to the acquisition of a natural gas transmission system connected to the South Texas System. Excluding major expansion projects and acquisitions, ongoing capital expenditures are expected to average approximately $60 million annually (approximately 45% for core maintenance and 55% for system enhancements). Core maintenance activities, such as the replacement of equipment and planned major maintenance activities, are undertaken to enable the Partnership's systems to operate at their maximum operating capacity. Enhancements to the systems are expected to extend the life of the

systems, reduce costs or enhance revenues, and permit the Partnership to respond to developing industry and government standards and the changing service expectations of its customers.

Cash flows from financing activities were $376.7 million in 2002 compared to $179.8 million in 2001. These cash flows are affected primarily by proceeds of unit issuances, fixed rate and variable rate financing, distributions to partners, and borrowings from affiliates. During 2002, the acquisition of the Midcoast System was financed primarily with net proceeds of $330.8 million from an issuance of i-units and the assumption of debt from affiliates of Enbridge.

At December 31, 2002, the Partnership had outstanding $279.0 million aggregate principal amount of First Mortgage Notes bearing interest at a rate of 9.15% per annum, payable semi-annually. The notes are due and payable in ten equal annual installments of $31.0 million, the first of which was made in December 2002, through the use of operating cash flow and variable rate financing. The remaining payments are expected to be funded by operating cash flows and refinancing arrangements.

At December 31, 2002, the Partnership had two unsecured revolving credit facilities, a $300.0 million three-year term facility and a $300.0 million 364-day facility. The Partnership and the Lakehead Partnership had borrowed $147 million and $317 million, respectively, under the two facilities. As of December 31, 2002, $212 million was drawn on the 364-day facility at a weighted average interest rate of 2.28% and $252 million was drawn on the three-year term facility at a weighted average interest rate of 2.81%.

On January 24, 2003, the Partnership amended and restated the terms of its two unsecured revolving credit facilities. The new facilities consist of the amended and restated $300 million three-year facility, which matures in 2006, subject to extension as provided in the facility, and the amended and restated $300 million 364-day facility, which matures in 2004, subject to a one-year term out option and extension as provided in the facility. The Partnership is the sole borrower under the new facilities and there are no guarantees of the obligations under either facility. The amended and restated terms of the facilities are substantially similar to the original facilities with the exception of certain amendments to the covenants. Among other changes, under the new facilities, the Partnership must maintain a certain interest coverage ratio as of the end of each fiscal quarter and is no longer required to maintain a particular credit rating. Although subsidiaries may incur debt with certain restrictions and limitations under the new facilities, the Partnership expects to provide funding to its subsidiaries, including the Lakehead Partnership. As at January 24, 2003, $180.0 million related to the 364-day facility and $237.0 million related to the three-year facility were transferred to the amended and restated facilities.

As of December 31, 2002, the Partnership had $444.1 million in debt outstanding under four notes to affiliates of the General Partner. These notes largely evidence debt assumed by the Partnership in connection with the acquisition of the Midcoast System in October 2002. The notes mature in 2007 and have cross-default provisions that are triggered by events of default under the First Mortgage Notes issued by the Lakehead Partnership or defaults under the Partnership's three-year term facility and 364-day facility. The notes are subordinate to the Partnership's credit facilities and other senior indebtedness. The Partnership anticipates refinancing these notes during 2003. For additional information regarding the amounts and interest rates associated with the affiliate notes see Note 9 to the Partnership's Consolidated Financial Statements.

The Lakehead Partnership's secured First Mortgage Notes are rated A- by Standard & Poors and A2 by Moody's, and its senior unsecured notes are rated BBB+ by Standard & Poors and A3 by Moody's. The ratings by Moody's are currently under review and are likely to change.

On March 4, 2002, the Partnership issued 2.2 million Class A Common Units at $42.75 per unit. The net proceeds from the offering were $90.8 million and were used to repay indebtedness. On April 4, 2002, 60,000 Class A Common Units were issued in connection with the underwriter's exercise

of the over-allotment option granted in connection with the issuance on March 4, 2002. Net proceeds from the units issued from the over-allotment totaled $2.5 million.

On October 17, 2002, the Partnership issued 9,000,001 i-units to Enbridge Management for net proceeds of $330.8 million. The Partnership used the net proceeds to repay debt owed to affiliates that was assumed in connection with the acquisition of the Midcoast System.

The Partnership has on file with the SEC a $500 million shelf registration statement for the issuance of Class A Common Units. The purpose of this registration statement is to give the Partnership flexibility to respond quickly to attractive financing opportunities in the capital markets as it pursues its growth strategy and manages its debt obligations. Approximately $308 million in Class A Common Units are available for issuance under this registration statement.

The Partnership distributes quarterly to the General Partner and the holders of its common units an amount equal to its "available cash", which generally is defined to mean for any calendar quarter the sum of all of the cash receipts of the Partnership plus net reductions to reserves less all of its cash disbursements and net additions to reserves. These reserves are retained to provide for the proper conduct of the Partnership's business, to stabilize distributions of cash to unitholders and the General Partner and, as necessary, to comply with the same terms of any agreement or obligation of the Partnership. Enbridge Management, as the delegate of the General Partner under the Delegation of Control Agreement, computes the amount of the Partnership's available cash. Enbridge Management, as owner of the i-units, however, does not receive distributions in cash. Instead, each time that the Partnership makes a cash distribution to the General Partner and the holders of its common units, the number of i-units owned by Enbridge Management and the percentage of total units in the Partnership owned by Enbridge Management will increase automatically under the provisions of the Partnership's partnership agreement with the result that the number of i-units owned by Enbridge Management will equal the number of Enbridge Management's shares and voting shares that are then outstanding. The amount of this increase per i-unit 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-day period immediately preceding the ex-dividend date for Enbridge Management's shares. For purposes of calculating the sum of all distributions of available cash, the cash equivalent amount of the additional i-units that are issued when a distribution of cash is made to the general partner and owners of common units are treated as distributions of available cash, even though the i-unit holder will not receive cash. The Partnership will retain and use that cash in its business.

The following table summarizes the Partnership's obligations and commitments at December 31, 2002 (dollars in millions):

The Partnership believes that its financial performance will continue to improve in 2003 as a result of increased capacity utilization on the Lakehead System, combined with full year contributions from the recently acquired Midcoast System and related acquisition activity.

Average daily crude oil deliveries on the Lakehead System are expected to increase substantially during 2003 from approximately 1.302 million barrels per day in 2002 to between 1.37 and 1.47 million bpd in 2003. A majority of the growth in deliveries is expected to come from three major oil sands projects being completed in Alberta. The largest, the AOSP, is sponsored by two multinational integrated oil companies and an independent oil and gas company. AOSP and two smaller oil sands SAGD extraction projects will add more than 100,000 bpd to the crude oil supply in western Canada. Most of this new supply is expected to be routed via the Lakehead System for delivery in the Midwest U.S. These new oil sands projects are expected to significantly increase crude oil production beyond that currently produced from the two major oil sands projects that have been in operation for over a decade.

Future prospects for the Lakehead System are dependent upon increased crude oil production from western Canada. While conventional oil supplies in this area are declining, Canada's oil sands supply is largely untapped. Estimated recoverable crude oil reserves from the oil sands, using existing technology, represent only 10% of the volume in place, of approximately 1.6 trillion barrels. To put this in perspective, this total volume in western Canada exceeds the estimated reserves of Saudi Arabia. Therefore this resource is expected to be an important crude oil supply for North America in the coming decades. Recognizing this, a number of major oil companies have announced projects requiring investments of approximately $35 billion over the next decade. This level of investment is expected to drive increased production of crude oil and enhanced utilization of the capacity available on the Lakehead System. As oil sands production increases, additional capacity expansions of the Lakehead System are anticipated later in the decade. Recognizing the need to expand beyond the Lakehead System's traditional markets, Enbridge and the Partnership are exploring alternative markets for Canadian oil sands production in southern PADD II, and potentially, in other market areas.

Other major oil sands projects are scheduled for completion during 2003 through 2005 including expansions of existing oil sands projects as well as new developments. In addition to the oil sands, Canada has substantial conventional crude oil resources. Conventional crude production will remain sensitive to the price of crude oil and the level of crude oil drilling activity. For a complete discussion of supply and demand for crude oil, please see "Items 1 and 2. Business and Properties."

The Partnership expects to significantly benefit from a full-year's contribution from the recently acquired Midcoast System, supplemented by improved asset performance and minor acquisitions in the area of the Partnership's existing assets.

The Partnership's 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 of the United States. As a result, there are many opportunities to connect new natural gas supplies either by installing new facilities or acquiring adjacent third-party gathering 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. During 2003, new and expanded wholesale customer connections are expected

to improve financial performance together with capital expenditures targeted to increase the processing and treating capability of our natural gas gathering assets.

Results of the Partnership's natural gas gathering and processing business depend upon the drilling activities of natural gas producers in the areas served by the Partnership. During 2002, drilling activity resulted in increased volumes on certain systems relative to the prior year. However, in some instances, volume on certain of the Partnership's gathering systems decreased. Based on discussions with producers, access to capital and certainty of commodity prices are causing a number of the independent natural gas producers to scale back their development activity.

Small acquisitions are expected to play a role in the achievement of financial targets of the Partnership for 2003. In general, these acquisitions are in or near areas where the Partnership already operates. These acquisitions present the best opportunities for consolidation savings and enhancing the Partnership's market position. Approximately $150 million of capital has been targeted for this type of activity in 2003. The amount includes approximately $41 million that has been earmarked for a previously announced acquisition in South Texas that remains subject to regulatory and other customary closing conditions. The Partnership is not certain when, or if, the South Texas acquisition will be closed.

The Partnership also will evaluate more significant acquisitions. Enbridge has a history of pursuing and consummating acquisitions and, subject to financing capability, plans to use the Partnership as its primary vehicle for acquiring mature energy delivery assets, particularly in the Gulf Coast region of the United States. The Partnership will continue to pursue strategic acquisitions from unaffiliated parties. The Partnership could also make additional acquisitions directly from Enbridge or its subsidiaries in the future. The Partnership anticipates an increased availability of attractive acquisition targets and believes that it is well-positioned to acquire additional assets. While there are currently no unannounced purchase agreements or ongoing negotiations for the acquisition of any material business or assets, such transactions can be effected relatively quickly and may occur at any time.

A settlement has been reached with Kansas Gas Services ("KGS"), Kansas Corporation Commission ("KCC") and the Partnership to resolve all disputes between the parties relating to the rates KGS is paying the Partnership. Under the settlement on November 1, 2002, KGS began paying negotiated rates based on a cost of service of $21 million. This represents a reduction from the annual rates approved by the FERC in 1998. The settlement was filed for approval at FERC and the KCC on February 28, 2003. Upon approval of the settlement, KGS and KCC will dismiss appeals relating to these disputes pending in the Kansas Court of Appeals, the United States Court of Appeals for the District of Columbia and the United States Court of Appeals for the 10^th Circuit.

The Partnership's UTOS pipeline system is required to periodically file new rates with the FERC. The Partnership has initiated a proceeding at the FERC regarding transportation rates that will be effective in 2003. The Partnership does not expect a rate case on the UTOS pipeline system to have a material effect on its results of operations on a consolidated basis.

Since 1995, FERC-regulated liquid petroleum pipelines have been generally subject to an indexed ceiling rate methodology under which the annual change in the ceiling rate is the annual change in the

Producers Price Index for Finished Goods minus 1% (PPI-1%). In December 2000, FERC affirmed this methodology and the existing index. The petroleum industry appealed this decision and on February 24, 2003 the FERC issued an Order on Remand, replacing the PPI-1% index by removing the 1% reduction. As this order revisits the FERC's decision to continue with the PPI-1% index in December 2000, the FERC has agreed to the recalculation of current ceiling levels to reflect the revised PPI index as at July 1, 2002 and 2001. The Partnership has filed for a change in its tariff rates for its Lakehead and North Dakota Systems that reflect these higher ceilings.

In June 2001, the FASB issued SFAS No. 143, Accounting for Asset Retirement Obligations, which must be adopted in years beginning after June 15, 2002. This standard requires legal obligations associated with the retirement of long-lived tangible assets to be recognized at fair value. When the liability is initially recorded, the cost is capitalized by increasing the asset's carrying value, which is subsequently depreciated over its useful life. The Partnership adopted the new standard effective January 1, 2003 and it did not have a material impact on its financial position, results of operations or cash flows.

On January 24, 2003, the Partnership experienced a crude oil leak on the Lakehead System from tank farm terminal piping at the Superior, Wisconsin terminal. Approximately 4,500 barrels of crude oil were released into the terminal ditch and containment system with approximately 450 barrels of the released oil breaching the containment system and flowing onto the frozen Nemadji River. Free oil was removed from the ice, and monitoring has confirmed no evidence of oil reaching the river's waters. Cleanup and remediation continues under the oversight of the state environmental agency. No long term environmental damage is anticipated. Mainline service was only partially interrupted for 12 hours. The release was attributed to the failure of an end-cap on a section of station piping and the Partnership has submitted an assessment and prevention action plan to the Federal Office of Pipeline Safety (OPS). Total costs of cleanup, recovery and remediation is estimated at $2 million to $3 million. The Partnership does not expect environmental fines, however a fine of up to the newly raised maximum of $100,000 could be imposed by OPS, although the Partnership has not been made aware of OPS's intent to propose fines or pursue further enforcement actions.

To the extent the amounts drawn under its revolving credit facilities carry a floating rate of interest, the Partnership's earnings and cash flow are exposed to changes in interest rates. This exposure is managed through periodically refinancing floating rate bank debt with long-term fixed rate debt and through the use of interest rate risk management hedge contracts. The Partnership does not have any material exposure to movements in foreign exchange rates as virtually all of its revenue and expense is denominated in U.S. dollars. To the extent that a material foreign exchange exposure arises, the Partnership intends to hedge such exposure using forward or other derivative contracts.

The table below summarizes as of December 31, 2002, the Partnership's derivative financial instruments and other financial instruments that are sensitive to changes in interest rates, including interest rate swaps and debt obligations. For debt obligations, the table presents principal cash flows and related weighted average interest rates by expected maturity dates. For interest rate swaps, the table presents notional amounts and weighted average fixed interest rates by expected (contractual) maturity dates. Notional amounts are used to calculate the contractual payments to be exchanged under the contract.

The Partnership's earnings and cash flows associated with its Liquids Transportation systems are not significantly impacted by changes in commodity prices, as the Partnership does not own the crude oil and NGLs it transports. However, the Partnership has commodity risk related to degradation losses associated with fluctuating differentials between the price of heavy crude oil relative to light crude oil. Commodity prices have a significant impact on the underlying supply of, and demand for, crude oil and NGLs that the Partnership transports.

With the Partnership's acquisition of the East Texas system on November 30, 2001, and the Midcoast System on October 17, 2002, a portion of the Partnership's earnings and cash flows are exposed to movements in the prices of natural gas and NGLs. The Partnership has entered into hedge transactions to substantially mitigate exposure to movements in these prices. Pursuant to policies approved by the Board of Directors of its General Partner, the Partnership may not enter into derivative instruments for speculative purposes. All financial derivative transactions must be undertaken with creditworthy counterparties. As at December 31, 2002, all financial counterparties were rated at least "A" by all major credit rating agencies.

Natural gas financial derivative transactions are entered into by the Partnership in order to hedge the purchase or sales price of natural gas. The following table outlines the Partnership's hedge positions as at December 31, 2002 and 2001 (all figures in millions):

			Fair Value
	Maturity Date	Remaining Notional	Fair Value
	Maturity Date	Remaining Notional	2002			2001
		MMBtu
East Texas System	2011	29.6	$	(6.1	)	$	8.5
Northeast Texas System	2012	48.2	$	(19.1	)		—
Midcoast System	2004	1.7	$	(0.3	)		—
Marketing	2004	17.7	$	1.7			—
East Texas System	2004	0.4	$	0.4		$	6.8

NGL financial derivative transactions are entered into by the Partnership in order to hedge the sale of NGLs. The following table outlines the Partnership's hedge positions as at December 31, 2002 and 2001 (all figures in millions):

			Fair Value
	Maturity Date	Remaining Notional	Fair Value
	Maturity Date	Remaining Notional	2002			2001
		Bbl
Northeast Texas System	2003	0.8	$	(2.5	)		—
Midcoast System	2003	0.1	$	(0.1	)		—
East Texas System	2002	0.0		N/A		$	(1.5	)

The Partnership also enters into financial derivative transactions in order to hedge the sale of condensate volumes. The following table outlines the Partnership's hedge positions as at December 31, 2002 and 2001 (all figures in millions):

			Fair Value
	Maturity Date	Notional Barrels	Fair Value
	Maturity Date	Notional Barrels	2002		2001
Northeast Texas System	2003	0.2	$	0.0	—

The consolidated financial statements of the Partnership, together with the notes thereto and the independent accountants' report thereon, and unaudited supplementary information, appear on pages F-2 through F-20 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

The Partnership is 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, 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 by, and may be removed by, Enbridge Pipelines, as the sole stockholder of the General Partner. All directors of Enbridge Management are elected annually by, and may be removed by, the General Partner as the sole holder of the 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
J.A. Connelly	56	Director
P.D. Daniel	56	Director
E.C. Hambrook	65	Director
G.K. Petty	61	Director
C.A. Russell	70	Director
D.P. Truswell	59	Director
D.C. Tutcher	54	President and Director
J.R. Bird	53	Group Vice President — Liquids Transportation
G.L.Sevick	47	Vice President — Liquids Transportation Operations
M.A. Maki	38	Vice President — Finance
A. Monaco	43	Treasurer
J.L. Balko	37	Controller
E.C. Kaitson	46	Corporate Secretary

J.A. Connelly was elected a director of the General Partner in January 2003. Mr. Connelly served as 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.

P.D. Daniel was elected a director of the General Partner in July 1996 and served as its President from July 1996 through October 1997. Mr. Daniel has served as President of Enbridge since September 2000 and as Chief Executive Officer of Enbridge since January 2001. Prior to that time Mr. Daniel also served as President & Chief Operating Officer—Energy Delivery of Enbridge from June 1998 to December 2000. Prior to that time Mr. Daniel served as Executive Vice President & Chief Operating Officer—Energy Transportation Services of Enbridge from September 1997 through June 1998.

E.C. Hambrook was elected a director of the General Partner in January 1992 and serves on its Audit, Finance and Risk Committee. Mr. Hambrook served as Chairman of the General Partner from July 1996 until July 1999. Mr. Hambrook has served as President of Hambrook Resources, Inc. since its inception in 1991. Hambrook Resources, Inc. is a real estate investment, marketing and sales company.

G.K. Petty was elected a director of the General Partner on February 22, 2001 and serves on its 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 is a business consultant providing executive management consulting services to the telecommunications industry.

C.A. Russell was elected a director of the General Partner in October 1985 and serves as the Chairman of its Audit, Finance & Risk Committee. Mr. Russell served as Chairman and Chief Executive Officer of Norwest Bank Minnesota North, N.A. (now known as Wells Fargo Bank), from January through December 1995. He also served as a director of Minnesota Power and Light Co. (now known as Allete) until May 1996. Other than in his service as a director of the Enbridge Management and the General Partner, Mr. Russell is retired.

D.P. Truswell was elected a director of the General Partner in 1991. Since September 2000, Mr. Truswell has served as Group Vice President & Chief Financial Officer of Enbridge and from May 1994 through August 2000 served as Senior Vice President & Chief Financial Officer of Enbridge.

D.C. Tutcher was elected a director and was appointed President of the General Partner in June 2001. He also currently serves as Group Vice President, Transportation—South of Enbridge. He was previously Chairman of the Board, President and Chief Executive Officer of Midcoast Energy Resources, Inc. from its formation in 1992 until it was acquired by Enbridge on May 11, 2001.

J.R. Bird was appointed Group Vice President, Liquids Transportation of the General Partner in January 2003. He served as a director of the General Partner from September 2000 to January 2003 and served as President from September 2000 until June 2001. Mr. Bird previously served as Treasurer of the General Partner from October 1996 through October 1997. He also currently serves as Group Vice President, Transportation—North of Enbridge since May 2001 and President of Enbridge Pipelines since September 2000. Prior to that time he served as Group Vice President, Transportation from September 2000 through April 2001 and as Senior Vice President, Corporate Planning and Development of Enbridge from August 1997 through August 2000.

G.L. Sevick was appointed Vice President, Liquids Transportation Operations of the General Partner in June 2001. He has served as Vice President, Operations for Enbridge Pipelines since 1999. Prior to that time, he served as Vice President, Engineering & Logistics of Enbridge Consumers Gas from 1998 to 1999.

T.L. McGill was appointed Vice President—Commercial Activity and Business Development of the General Partner in April 2002. Prior to that time, Mr. McGill was President of Columbia Gulf Transmission Company from January 1996 to March 2002.

M.A. Maki was appointed Controller of the General Partner in June 2001 and was appointed Vice President—Finance of the General Partner in July 2002. Prior to that time, he served as Controller, Enbridge Pipelines since September 1999. Prior to that time, he served as Chief Accountant of the General Partner from June 1997 to August 1999.

A. Monaco was appointed Treasurer of the General Partner in February 2002. He currently serves as Vice President, Financial Services of Enbridge and prior to that time as Director, Financial Services since 2000. Prior to that time, he served as Director, Investor Relations from 1996 to 2000.

J.L. Balko was appointed as Chief Accountant of the General Partner in October 1999 and was appointed Controller of the General Partner in July 2002. Prior to that time, she served in managerial positions in accounting with Enbridge Pipelines since January 1998.

E.C. Kaitson has served as Corporate Secretary of the General Partner since November 2001. He also currently serves as Associate General Counsel, Transportation Group South of Enbridge. He was previously Assistant Corporate Secretary and General Counsel of Midcoast Energy Resources, Inc. from 1997 until it was acquired by Enbridge on May 11, 2001.

Section 16(a) of the Exchange Act requires directors, executive officers and 10% beneficial owners to file with the SEC reports of ownership and changes in ownership of the Partnership's equity securities and to furnish the Partnership with copies of all reports filed. The Partnership is a limited partnership and has no officers or directors of its own. Based solely on the review of the reports furnished, the Partnership believes that, during fiscal year 2002, all Section 16(a) filing requirements applicable to the directors and officers of the General Partner, and greater than 10% beneficial owners of the Partnership were met.

The following table sets forth the total annual and long-term compensation for all services rendered in all capacities to the Partnership and Enbridge Management for the fiscal year ended December 31, 2002, of the Chief Executive Officer and the other most highly compensated executive officers (the "Named Executive Officers"). No allocation of compensation is made between the Partnership and Enbridge Management because the Partnership effectively paid for the portion of these officers' total compensation that is approximately equal to the percentage of time each of these officers devoted to Enbridge Management and the Partnership. The other affiliates of Enbridge, to whom these officers rendered services, effectively paid the remainder of the compensation expenses of these officers. Compensation of the Named Executive Officers for years prior to 2002 is not reported because it has previously not been reported.


	Annual Compensation
Name & Principal Position	Salary		Bonus		Other Annual Compensation (1) (2)	All Other Compensation (3)
D.C. Tutcher President	$	296,250		$	300,000	$	40,000	$	11,625	80
T.L. McGill Vice President—Commercial Activity & Business Development	$	182,474		$	50,000	$	16,886	$	4,193	90
E.C.Kaitson Secretary	$	161,250		$	25,000	$	10,000	$	8,990	90
M.A. Maki Vice President-Finance	$	136,762		$	35,000	$	25,978	$	6,950	90

Neither Enbridge Management nor the General Partner have a compensation committee, therefore, all decisions related to executive compensation matters are made by a committee of the Board of Directors of Enbridge.

Enbridge has a Human Resources & Compensation Committee (the "Committee"), which is presently comprised of members of its Board of Directors, which in 2002 included G.K. Petty, who is also a member of the Boards of Enbridge Energy Management, LLC and the General Partner.

No member of the Committee is or has been an Officer, former Officer or employee of Enbridge or any of its subsidiaries, or has had any relationship with Enbridge except as a Director, other than D.J. Taylor, who is a non-executive Officer holding the office of Chair of the Board of Enbridge, and R.W. Martin, who was an employee and Officer of The Consumers' Gas Company Ltd. (now Enbridge Gas Distribution Inc.), an indirect wholly owned subsidiary of Enbridge. Mr. Caillé, who retired as a Director of Enbridge effective January 31, 2002, is President & Chief Executive Officer of Hydro-Québec, a majority owner of shares of Noverco Inc. and party to a transaction, whereby on June 30, 1998, Enbridge acquired preference shares and 32% of Noverco Inc.'s common shares in exchange for 12,000,000 Enbridge Shares and a warrant to purchase an additional 3,000,000 Enbridge Shares which warrant was exercised on November 13, 1998.

Options to purchase shares of Enbridge may from time to time be granted by Enbridge to our Named Executives Officers, but no portion of any such grants is attributable to services performed for the Partnership or Enbridge Management nor are any expense reimbursements made by the Partnership on account of such options.

Messrs. Tutcher and Kaitson have Executive Employment Agreements with Enbridge. The Agreements commenced on May 11, 2001 and continue until the earlier of (i) the date of voluntary retirement in accordance with the retirement policies established for senior employees of Enbridge Inc.,

(ii) the voluntary resignation which is not a constructive dismissal, or (iii) termination based on disability, death, cause or by either party. The Agreements provide that in the event of termination of employment, the Executive agrees to keep confidential all information of a confidential or proprietary nature and further agrees not to use such information for personal advantage. The Agreements also provide for a base salary, annual reviews, discretionary raises, participation in short and long-term incentive plans of Enbridge, and severance payments in the amount of two years compensation in the event of termination by Enbridge.

Enbridge employees that are members of the Board of Directors of the General Partner or Enbridge Management do not receive any additional compensation for serving in those capacities. Non-Enbridge employee members of the Board of Directors of the General Partner and Enbridge Management receive an aggregate annual fee of $20,000, paid quarterly, plus $1,000 per day for meetings of the board of directors or committee of the board of directors attended. In addition, each independent director is reimbursed for out-of-pocket expenses in connection with attending meetings of the board of directors or committees and an additional $500 for meetings requiring out of town travel. The director who serves as chairman of the audit committees is paid an additional $1,000 per year and the director who serves as chairman of the boards is paid and additional $10,000 per year, paid quarterly. The General Partner indemnifies each director for actions associated with being a director to the full extent permitted under Delaware law and maintain errors and omissions insurance.

Messrs. Hambrook and Russell served on a special committee of the Board of Directors of the General Partner in 2002, in its capacity as General Partner of the Partnership. The special committee of the Partnership was empowered to act on behalf of the Partnership in its purchase of the Midcoast Assets. Mr. Hambrook served as chairman of the special committee. As compensation, Messrs. Hambrook and Russell received fees of $20,000 and $15,000, respectively, plus a fee of $1,000 per committee meeting. In addition, each was reimbursed for out-of-pocket expenses in connection with attending special committee meetings and an additional $500 for each meeting requiring out of town travel.

Mr.. Hambrook also served on pricing committees in 2002 in connection with public offerings to sell limited partnership interests in the Partnership. As compensation for serving on the pricing committees, Mr. Hambrook received a fee of $1,000 per meeting.

The following table sets forth information as of the December 31, 2002, with respect to persons known to the Partnership to be the beneficial owners of more than 5% of either 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	9,228,655	100.0
Enbridge Energy Company, Inc. 1100 Louisiana, Suite 3300 Houston, TX 77002	Class B Common Units	3,912,750	100.0
Goldman, Sachs & Co. (1) The Goldman Sachs Group, Inc. 85 Broad St. New York, N.Y. 10004	Class A Common Units	1,851,610	6.54

The following table sets forth information as of February 24, 2003, with respect to each class of the Partnership's units beneficially owned by the Named Executive Officers, directors and nominees for director of the General Partner and all executive officers, directors and nominees for director of the Partnership as a group:

Name	Title of Class	Amount and Nature of Beneficial Ownership(1)	Percent Of Class
E.C. Hambrook	Class A Common Units	1,000	*
G.K. Petty	Class A Common Units	1,000	*
D.C. Tutcher	Class A Common Units	20,200	*
All Officers, directors and nominees as a group (14 persons)	Class A Common Units	22,200	*

As discussed in Part II, Item 7, the Partnership makes quarterly cash distributions of all of its available cash to the General Partner and the holders of its common units. Under the Partnership

Agreement, the General Partner receives incremental incentive cash distributions on the portion of cash distributions on a per unit basis that exceed certain target thresholds as follows:

			General Partner
Quarterly Cash Distribution per Unit:
	Up to Minimum Quarterly Distribution ($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 2002, incentive distributions paid to the General Partner were approximately $12.0 million.

The Partnership, which has no employees, uses the services of Enbridge and its affiliates (the "Group") for management, operating, administrative and payroll services of its business. The management, operating, administrative and payroll services are reimbursed at cost in accordance with service agreements. The Partnership incurred costs totaling $64.7 million (2001-$36.9 million; 2000-$30.3 million) related to these services and are included in operating and administrative expenses. The increase in 2002 of $27.8 million is primarily due to additional costs associated with the full year impact of the East Texas and North Dakota Systems and the partial year impact of the Midcoast System. The Partnership has accounts payable to the Group totaling $13.9 million at December 31, 2002. The Partnership had accounts receivable from the Group of $0.3 million at December 31, 2001.

The Partnership generates operating revenues from the sale of natural gas to, and incurs expense from the purchase of natural gas from, Enbridge and its affiliates. These transactions are entered into at the market price at the date of sale. Included in the results for the twelve months ending December 31, 2002 are operating revenues of $4.6 million and cost of natural gas of $0.1 million. There were no such comparative amounts in 2001 or 2000.

The Partnership has entered into an easement acquisition agreement with Enbridge Holdings (Mustang) Inc. ("Enbridge Mustang"), an affiliate of the General Partner. Enbridge Mustang acquired the certain real property for the purpose of granting pipeline easements to the Partnership for construction of a new pipeline, completed during 1998, by the Partnership from Superior, Wisconsin to Chicago, Illinois. In order to provide for these real property acquisitions by Enbridge Mustang, the Partnership had made non-interest bearing cash advances to Enbridge Mustang. As Enbridge Mustang disposes of the real property, the advances are repaid. The advances amounted to $2.7 million at December 31, 2002 (2001-$2.9 million). Under the terms of the agreement, the Partnership will reimburse Enbridge Mustang the net cost of acquiring, holding and disposing of the real property.

The Partnership has entered into hedge transactions to manage its exposure to movements in commodity prices, which arise from the Partnership's investment in certain of its natural gas assets. Enbridge currently provides a guarantee of the obligations in respect of these hedging transactions. Under the terms of the guarantee, the Partnership has agreed to pay Enbridge a fee, based on a formula consistent with what third party financial institutions would charge for this form of guarantee. In 2002, the guarantee fee was approximately $0.2 million (2001—$nil million).

The Partnership has entered into an agreement with Tidal Energy Marketing Inc. ("Tidal") in which Enbridge has a 50% interest. Tidal is engaged in the business of crude oil and condensate marketing, transportation, storage and trading and providing related services. The agreement gives Tidal the ability to act as the Partnership's agent in leasing of the Partnership's terminaling and storage facility, consisting of nine 100,000 barrels ("bbl") nominal capacity tanks and related facilities. The Partnership pays Tidal a monthly fee, which includes 50% of the distributable proceeds from the tank leases. In 2002, the Partnership paid Tidal $0.5 million, (2001-$0.3 million; 2000-$0.1 million).

The Partnership and its wholly owned subsidiaries have various notes payable with affiliates of Enbridge that totaled $444.1 million at December 31, 2002, (2001—$176.2 million), with a weighted average interest rate of 6.03% (2001—3.87%) that mature in 2007.

Interest expense related to affiliate notes totaled $4.6 million (2001-$1.3 million; 2000-$nil). Interest payable to affiliates totaled $1.3 million (2001-$nil). Interest paid to affiliates totaled $3.3 million in 2002 (2001-$1.3 million; 2000-$nil)

Through a Delegation of Control Agreement with the General Partner and the Partnership, Enbridge Management makes all decisions relating to the management and control of the Partnership's business. 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 Inc., owns all the common stock of the General Partner and elects all of the General Partner's directors. Some of the General Partner's officers and directors 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 the Partnership's uitholders. Certain conflicts of interest could arise as a result of the relationships among Enbridge Management, the General Partner, Enbridge and the Partnership. The Partnership's partnership agreements and Delegation of Control Agreement contain provisions that allow Enbridge Management to take into account the interest of parties in addition to the Partnership in resolving conflicts of interest, thereby limiting its fiduciary duties to the Partnership's unitholders, as well as provisions that may restrict the remedies available to unitholders for actions taken that might, without such limitations, constitute breaches of fiduciary duty.

The Partnership and Enbridge maintain systems of disclosure controls and procedures designed to provide reasonable assurance that the Partnership is able to record, process, summarize and report the information required in the Partnership's annual and quarterly reports under the Securities Exchange Act of 1934. Management of the Partnership has evaluated the effectiveness of our disclosure controls and procedures within 90 days prior to the filing date of this report. 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, management of the Partnership relied on similar evaluations conducted by employees of Enbridge affiliates who provide certain treasury, accounting and other services on behalf of the Partnership. No significant changes were made to our internal controls or other factors that could significantly affect these controls subsequent to the date of their evaluation, nor were any corrective actions with respect to significant deficiencies and material weaknesses necessary subsequent to that date.

(a) As to financial statements, supplementary information and financial statement schedules, reference is made to "Index to Financial Statements, Supplementary Information and Financial Statement Schedules" on page F-1 of this Report.

(b) The Partnership filed the following reports on Form 8-K during the fourth quarter of 2002: A report on Form 8-K was filed on October 10, 2002, attaching the consolidated statement of financial position of the General Partner. A report on Form 8-K was filed on October 15, 2002, attaching a press release dated October 10, 2002 regarding the pricing of the initial public offering of the shares of Enbridge Energy Management, L.L.C. A report on Form 8-K was filed on October 31, 2002, disclosing the acquisition of certain natural gas transportation, gathering and processing assets from the General Partner, including the required financial statements of the business acquired.

(c) The following Exhibits (numbered in accordance with Item 601 of Regulation S-K) are filed or incorporated herein by reference as part of this Report.

Exhibit Number		Description
3.1		Certificate of Limited Partnership of the Partnership (Exhibit 3.1 to the Partnership's Registration Statement No. 33-43425)
3.2		Certificate of Amendment to Certificate of Limited Partnership of the Partnership (Exhibit 3.2 to the Partnership's 2000 Form 10-K/A dated October 9, 2001)
3.3		Third Amended and Restated Agreement of Limited Partnership of the Partnership (Exhibit 3.1 to the Partnership's Quarterly Report on Form 10-Q filed November 14, 2002)
4.1		Form of Certificate representing Class A Common Units (Exhibit 4.1 to the Partnership's 2000 Form 10-K/A dated October 9, 2001)
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. (Exhibit 10.10 to 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. (Exhibit 10.11 to the Partnership's 1991 Form 10-K)
10.3		Contribution Agreement (Exhibit 10.1 to the Partnership's Registration Statement on Form S-3/A filed July 8, 2002)
10.4		First Amendment to Contribution Agreement (Exhibit 10.8 to the Partnership's Registration Statement on Form S-3/A filed September 24, 2002)
10.5		Second Amendment to Contribution Agreement (Exhibit 99.3 to the Partnership's Current Report on Form 8-K filed October 31, 2002)
10.6		Delegation of Control Agreement (Exhibit 10.2 to the Partnership's Quarterly Report on Form 10-Q filed November 14, 2002)
10.7		Amended and Restated Treasury Services Agreement (Exhibit 10.3 to the Partnership's Quarterly Report on Form 10-Q filed November 14, 2002)
10.8		Operational Services Agreement (Exhibit 10.4 to the Partnership's Quarterly Report on Form 10-Q filed November 14, 2002)
10.9		General and Administrative Services Agreement (Exhibit 10.5 to the Partnership's Quarterly Report on Form 10-Q filed November 14, 2002)
10.10		Omnibus Agreement (Exhibit 10.6 to the Partnership's Quarterly Report on Form 10-Q filed November 14, 2002)
10.11		Amended and Restated Credit Agreement, dated January 24, 2003, among Enbridge Energy Partners, L.P., Bank of America, N.A., as administrative agent, and the lenders party thereto.
10.12		Amended and Restated 364-Day Credit Agreement, dated January 24, 2003, among Enbridge Energy Partners, L.P., Bank of America, N.A., as administrative agent, and the lenders party thereto.
10.13		Subordinated Promissory Note, dated as of January 24, 2003, given by Enbridge Energy Partners, L.P., as borrower, to Enbridge Hungary Liquidity Management Limited Liability Company, as lender.
10.14		Subordinated Promissory Note, dated as of January 24, 2003, given by Enbridge Energy Partners, L.P., as borrower, to Enbridge Hungary Liquidity Management Limited Liability Company, as lender.
10.15		Subordinated Promissory Note, dated as of January 24, 2003, given by Enbridge Energy Partners, L.P., as borrower, to Enbridge (U.S.) Inc., as lender.
10.16		Note Agreement and Mortgage, dated December 12, 1991 (Exhibit 10.1 to the Partnership's 1991 Form 10-K)

All Exhibits listed above (with the exception of Exhibits 10.11, 10.12, 10.13, 10.14, 10.15, 10.16, 21.1, 23.1, 99.1 and 99.2 which are filed herewith) are incorporated herein by reference to the documents identified in parentheses.

Copies of Exhibits may be obtained upon written request of any Unitholder to Investor Relations, the General Partner, Inc., 1100 Louisiana, Suite 3300, Houston, Texas 77002.

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.

Pursuant to the requirements of the Securities Exchange Act of 1934, this Report has been signed below on March 28, 2003 by the following persons on behalf of the Registrant and in the capacities indicated with the General Partner.

1. I have reviewed this annual report on Form 10-K of Enbridge Energy Partners, L.P.;

2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which suchstatements were made, not misleading with respect to the period covered by this annual report;

3. Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows ofthe registrant as of, and for, the periods presented in this annual report;

4. The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and have:

5. The registrant's other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing theequivalent functions):

6. The registrant's other certifying officers and I have indicated in this annual report whether there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses

1. I have reviewed this annual report on Form 10-K of Enbridge Energy Partners, L.P.;

INDEX TO FINANCIAL STATEMENTS, SUPPLEMENTARY INFORMATION AND
FINANCIAL STATEMENT SCHEDULES

ENBRIDGE ENERGY PARTNERS L.P.


Financial Statements
	Report of Independent Accountants
	Consolidated Statements of Income for the Years Ended December 31, 2002, 2001, 2000
	Consolidated Statements of Comprehensive Income for the Years Ended December 31, 2002, 2001, 2000
	Consolidated Statements of Cash Flows for the Years Ended December 31, 2002, 2001, 2000
	Consolidated Statements of Financial Position as at December 31, 2002 and 2001
	Consolidated Statements of Partners' Capital for the Years Ended December 31, 2002, 2001, 2000
	Notes to the Consolidated Financial Statements

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

In our opinion, the accompanying consolidated statements of financial position and the related consolidated statements of income, of comprehensive income, of cash flows and of partners' capital present fairly, in all material respects, the financial position of Enbridge Energy Partners, L.P. and its subsidiaries (the Partnership) at December 31, 2002 and 2001, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2002 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Partnership's management; our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with auditing standards generally accepted in the United States of America, which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes 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. We believe that our audits provide a reasonable basis for our opinion.

As discussed in Notes 2 and 6 to the consolidated financial statements, the Partnership changed its method of accounting for goodwill and intangible assets effective January 1, 2002.

The accompanying notes to the Consolidated Financial Statements
are an integral part of these statements.

Enbridge Energy Partners, L.P. (the "Partnership"), including its consolidated subsidiaries, 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 New York Stock Exchange under the symbol "EEP."

The Partnership was formed in 1991 by the General Partner (the "General Partner"), which is an indirect, wholly-owned subsidiary of Enbridge Inc. ("Enbridge") of Calgary, Canada. The Partnership was formed to acquire, own and operate the crude oil and liquid petroleum transportation assets of Enbridge Energy, Limited Partnership (the "Lakehead Partnership").

On October 17, 2002, the Partnership acquired the natural gas gathering, treating, processing, transmission and marketing assets of Enbridge Midcoast Energy, Inc. (comprised of the "Midcoast System", "Northeast Texas System" and the "South Texas System") from the General Partner. During 2001, the Partnership acquired the crude oil and liquid petroleum transportation assets of Enbridge Pipelines (North Dakota) L.L.C. (the "North Dakota System") and natural gas gathering, transportation, processing and marketing assets in east Texas (the "East Texas System"). The assets acquired are held in a series of limited liability companies and limited partnerships owned, directly or indirectly, 100% by the Partnership.

Enbridge Energy Management, L.L.C. ("Enbridge Management"), a Delaware limited liability company, was formed on May 14, 2002. The General Partner owns the voting securities of Enbridge Management.

On October 17, 2002, Enbridge Management bought 9,000,001 i-units from the Partnership. The i-units are a new and separate class of limited partner interests in the Partnership and are issued only to Enbridge Management. Enbridge Management became a limited partner in the Partnership when it purchased the i-units and, pursuant to a delegation of control agreement, manages and controls the business and affairs of the Partnership. Under the Delegation of Control Agreement with the General Partner and the Partnership, the General Partner delegated to Enbridge Management, its power and authority to manage and control the Partnership's business and affairs, except that Enbridge Management cannot take certain specified actions without the approval of the General Partner. In accordance with its limited liability company agreement, Enbridge Management's activities will be restricted to being a limited partner in and managing and controlling the business and affairs of the Partnership.

On October 17, 2002, in connection with the offering described above, the Partnership's ownership of the Lakehead Partnership was restructured such that the Lakehead Partnership is now a wholly-owned subsidiary of the Partnership. As a result of this restructuring, the General Partner holds a 2% general partner interest in the Partnership but no longer holds a direct interest in the Lakehead Partnership.

The Partnership conducts its business through five business segments: Liquids Transportation, Natural Gas Transportation, Gathering and Processing, Marketing, and Corporate. These operating segments are strategic business units established by senior management to facilitate the achievement of the Partnership's long-term objectives, to aid in resource allocation decisions and to assess operational performance.

Liquids Transportation includes the operations of the Lakehead System, which consists of crude oil and liquid petroleum transportation and storage assets in the Great Lakes and Midwest regions of the United States. The Lakehead System, which spans approximately 1,900 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. Liquids Transportation also includes the operations of the North Dakota System, which consists of crude oil gathering lines connected to a transportation line that interconnects directly with the Lakehead System in the state of Minnesota.

The Natural Gas Transportation segment consists of four Federal Energy Regulatory Commission ("FERC") regulated natural gas transmission pipeline systems and 35 intrastate natural gas transmission and wholesale customer pipeline systems located in the Mid-Continent and Gulf Coast regions of the United States. These pipeline systems form part of the Midcoast System assets that were acquired from the General Partner in 2002.

The Gathering and Processing segment includes the East Texas System, acquired on November 30, 2001, and the Midcoast System, the Northeast Texas System and the South Texas System, all of which were acquired from the General Partner on October 17, 2002. The East Texas System includes natural gas gathering and transmission pipelines, four natural gas treating plants and three natural gas processing plants. The Midcoast System assets consist of 35 gathering and processing/treating systems, trucks, trailers, and rail cars used for transporting natural gas liquids ("NGLs"), crude oil and carbon dioxide. The Northeast Texas System includes natural gas gathering pipelines, five natural gas treating plants and four natural gas processing plants. The South Texas System includes natural gas gathering pipelines, a hydrogen sulfide treating plant and a natural gas processing plant.

The Marketing segment primarily provides natural gas supply, transmission and sales services for producers and wholesale customers on the Partnership's pipelines as well as other interconnected natural gas pipeline systems. Natural gas marketing activities are primarily undertaken to increase pipeline utilization, realize incremental margins on gas purchased at the wellhead, and provide value added services to customers.

The Corporate segment consists of costs of financing, interest income, minority interest and certain other costs such as franchise taxes, which are not allocated to the other business segments.

As a result of the purchase of natural gas assets in October 2002, the Partnership changed the organization of its business segments effective in the fourth quarter of 2002. Prior period segment results have been restated to conform to the Partnership's current organization. For more information on the Partnership's reportable business segments, see Note 13.

The consolidated financial statements of the Partnership are prepared in accordance with accounting principles generally accepted in the United States of America. The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses, as well as the disclosure of contingent assets and liabilities in the financial statements. Actual results could differ from those estimates and assumptions.

The financial statements of the Partnership include the accounts of the Partnership and its wholly-owned subsidiaries on a consolidated basis. All significant intercompany items have been eliminated in consolidation. Prior to October 17, 2002, the General Partner's 1.0% interest in the Lakehead Partnership was accounted for by the Partnership as a minority interest.

The Partnership's Liquids Transportation and certain of its Natural Gas Transportation and Gathering and Processing 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 the Natural Gas Transportation 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, certain assets and liabilities that result from the regulated ratemaking process are recorded that would not be recorded for non-regulated entities under accounting principles generally accepted in the United States of America. The Partnership acquired four interstate FERC-regulated natural gas transmission pipeline systems as part of the Midcoast Acquisition (see also Note 3).

Revenues of the Gathering and Processing segment are derived from gathering and processing services under the following types of arrangements:

Other Arrangements: The Partnership also utilizes other types of arrangements in its natural gas gathering and processing business:

customers, the Partnership will enter into long-term fixed price purchase or sale contracts with its customers and usually will enter into offsetting positions under the same or similar terms. Revenues are recognized upon delivery of natural gas to customers or upon services rendered.

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.

The Partnership establishes provisions for losses on accounts receivable if it determines that it 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.

The oil shortage/overage balance represents crude oil and liquid petroleum owed to or receivable from customers of the Liquids Transportation systems. The balance also includes crude oil and liquid petroleum retained by the Partnership under terms of its transportation tariff.

Inventories of materials and supplies, utilized for ongoing replacements and expansions, are carried at the lower of fair value or cost.

To facilitate deliveries of natural gas and provide for operational flexibility, many natural gas transmission companies 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, the difference results in a net receivable or payable balance between the interconnecting pipelines. To the extent that such imbalances are not settled regularly, this receivable or payable balance may increase or decrease in value as a result of movements in natural gas prices.

When an operational balancing agreement is not in place, shippers of natural gas accumulate net receivable or payable balances with a pipeline if the volume of gas actually transported by the pipeline differs from the volume of gas the shipper had scheduled for transportation. This difference is referred to as a shipper imbalance. These transactions result in natural gas imbalance receivables and payables that 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 current assets or current liabilities on the balance sheet using the posted index prices, which approximate market rates, or the Partnership's weighted average cost of gas.

Deferred financing charges are amortized on a straight-line basis over the life of the related debt, which is comparable to results using the effective interest method.

Property, plant and equipment is stated at its original cost of construction or, upon acquisition, at the fair value of the assets acquired. Expenditures for system expansion and major renewals and betterments are capitalized; maintenance and repair costs are expensed as incurred. The Partnership capitalizes direct costs, such as labor and materials, and indirect costs, such as overhead and interest at the Partnership's weighted average cost of debt, and, in its regulated businesses that apply the provisions of SFAS No. 71, an equity return component, during construction. Depreciation of property, plant and equipment is provided on a straight-line basis over estimated service lives. For all segments, on 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.

The Partnership evaluates impairment of long-lived assets whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. An impairment loss will be recognized when the sum of estimated undiscounted future cash flows expected to result from use of the asset and its eventual disposition is less than its carrying amount. If an impairment loss will be recognized, the amount of the impairment would be calculated as the excess of the carrying amount of the asset over the fair value of the assets either through reference to similar asset sales, or by estimating the fair value using a discounted cash flow approach. There have been no impairments recorded in 2002, 2001 and 2000.

Goodwill represents the excess of the purchase price over the fair value of net tangible and intangible assets upon acquisition of a business. Effective January 1, 2002, the Partnership adopted SFAS No. 142, "Goodwill and Other Intangible Assets", whereby goodwill is not amortized but is tested for impairment at least annually and written down if the recorded value exceeds fair value.

The Partnership completed the initial impairment test in June 2002 and determined that its existing goodwill as of January 1, 2002 was not impaired.

The Partnership is not a taxable entity for federal and state income tax purposes. Accordingly, no recognition is given to income taxes for financial reporting purposes. The tax on Partnership net income is borne by the individual partners through the allocation of taxable income. 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 the Partnership Agreement. The aggregate difference in the basis

of the Partnership's net assets for financial and tax reporting purposes cannot be readily determined because information regarding each partner's tax attributes in the Partnership is not available.

Net income and cash flows are subject to volatility stemming from changes in market prices such as interest rates, natural gas prices, natural gas liquids prices and commodity fractionation margins. In order to manage the risks to Partnership unitholders, the General Partner uses a variety of derivative financial instruments to create offsetting positions to specific commodity or interest rate exposures. All of these financial instruments are employed in connection with an underlying asset, liability and/or anticipated transaction and are not used for speculative purposes. In implementing its hedging programs, the General Partner has established a formal analysis execution and reporting framework that requires the approval of the Board of Directors of the General Partner or a committee of senior management.

The Partnership recognizes all derivative financial instruments as assets and liabilities and measures them at fair value. Hedges of cash flow exposures are entered into to hedge a forecasted transaction or the variability of cash flows to be received or paid related to a recognized asset or liability. On the date that the Partnership enters into the derivative, it is designated as a cash flow hedge. Changes in the derivative fair values that are designated as cash flow hedges are deferred to the extent that they are deemed highly effective and 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 value is recognized immediately in earnings as a component of Interest and other income (expense) in our income statement.

The Partnership formally documents all relationships between hedging instruments and hedged items, as well as its risk management objectives, strategies for undertaking various hedge transactions and its methods for assessing and testing correlation and hedge ineffectiveness. All hedging instruments are linked to the hedged asset, liability, firm commitment or forecasted transaction. The Partnership also assesses, both at the inception of the hedge and on an on-going basis, whether the derivatives that are used in its hedging transactions are highly effective in offsetting changes in cash flows of the hedged item. If the Partnership determines that a derivative is no longer highly effective as a hedge, it discontinues hedge accounting prospectively by including changes in the fair value of the derivative in current earnings. All related cash flows from derivatives designed as hedge instruments are classified in the same category as those from the underlying items or transactions being hedged.

The market value of derivative instruments reflects the Partnership's best estimate and is based upon exchange traded prices, published market prices or over-the-counter market price quotations whenever they are available. Quoted valuations may not be available due to location differences or terms that extend beyond the period for which quotations are available. Where quotes are not available, the Partnership utilizes other valuation techniques or models to estimate market values. These modeling techniques require the Partnership to make estimations of future prices, price correlation and market volatility and liquidity. The estimates also reflect factors for time value and volatility 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 our counterparties and operational risk. The Partnership's actual results may differ from its estimates.

The Partnership expenses or capitalizes expenditures for ongoing compliance with environmental regulations that relate to past or current operations as appropriate. Amounts for remediation of existing environmental contamination caused by past operations which do not benefit future periods by preventing or elimination 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, and include estimates of associated legal costs. 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 circumstances and are included on the balance sheet in other current and long-term liabilities at their undiscounted amounts. The Partnership evaluates recoveries from insurance coverage separately from its liability and, when recovery is assured, it records and reports an asset separately from the associated liability in its financial statements.

The Partnership recognizes liabilities for other contingencies when it has 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. When a range of probable loss can be estimated, the Partnership accrues the most likely amount, or at least the minimum of the range of probable loss.

Certain reclassifications have been made to the prior years' reported amounts to conform to the classifications used in the 2002 consolidated financial statements. These reclassifications have no impact on net income.

In June 2001, the FASB issued SFAS No. 143, Accounting for Asset Retirement Obligations, which must be adopted in years beginning after June 15, 2002. This standard requires legal obligations associated with the retirement of long-lived tangible assets to be recognized at fair value. When the liability is initially recorded, the cost is capitalized by increasing the asset's carrying value, which is subsequently depreciated over its useful life. The new standard was adopted effective January 1, 2003 and did not have a material impact on the Partnership's financial position, results of operations or cash flows.

The primary strategy of the Partnership is to grow cash distributions through the profitable expansion of existing assets and through development and acquisition of complementary businesses with similar risk profiles to the Partnership's current business. During 2001 and 2002, the Partnership completed several significant acquisitions. Each of the acquisitions was accounted for using the purchase method and the assets acquired and liabilities assumed were recorded at their estimated fair

market values as determined by independent appraisals. The results of operations from these acquisitions are included in earnings from the effective date of acquisition.

Effective October 17, 2002, the Partnership acquired assets from the General Partner for approximately $875.5 million, including transaction costs of $4.9 million and post-closing adjustments of approximately $50.6 million. The following assets were purchased:

The Partnership funded this acquisition through the assumption of $472.3 million in debt related to the acquired systems, the issuance to the General Partner of an additional $8.2 million equity interest in the Partnership, $332.7 million of proceeds from the issuance of i-units to EEM and the payment to the General Partner of $11.7 million in cash, which was funded by the Partnership with borrowings under its 364-day revolving credit facility. In addition, there is approximately $50.6 million of post closing adjustments payable to the General Partner estimated to be settled in the second quarter of 2003. A committee of independent members of the Board of Directors of the General Partner negotiated the purchase price and the terms of the acquisition on behalf of the Partnership and recommended that the Board of Directors of the General Partner approve the acquisition on behalf of the Partnership. The value allocated to the assets was determined by agreement between the parties and supported by an independent appraisal. Included in the acquired current assets of $51.3 is a $3.7 million reserve for doubtful accounts. Goodwill associated with the acquisition was $226.0 million, and is allocated to the Gathering and Processing, Marketing, and Natural Gas Transportation segments. Intangible assets acquired of $16.1 million relate to customer contracts for gas purchases and sales and are recorded in the Gathering and Processing and Natural Gas Transportation segments. Other liabilities consist primarily of amounts payable for gas, NGL and interest rate swaps of $14.6 million and an environmental contingency of $5.9 million.

		(dollars in millions)
Purchase Price:
	Debt assumed	$	472.3
	Issuance of equity interest to the General Partner		8.2
	Cash paid, including transaction costs		344.4
	Working capital and other adjustments		50.6

	Total purchase price	$	875.5

Allocation of purchase price:
	Current assets	$	51.3
	Property, plant and equipment		626.7
	Goodwill		226.0
	Other assets and intangibles		19.1
	Current liabilities		(26.4	)
	Other liabilities		(21.2	)

Total		$	875.5

On November 30, 2001, the Partnership acquired natural gas gathering, transportation, processing and marketing assets in east Texas. The assets were purchased for cash of $230.0 million, including transaction costs of $0.6 million. The purchase was funded by the issuance of Class A Common Units with total net proceeds of $91.4 million and a short-term loan at market rates from the General Partner. The value allocated to the assets was determined by agreement between the parties and supported by an independent appraisal. Goodwill associated with the acquisition was $15.1 million, and is allocated entirely to the Gathering and Processing segment. Customer contracts are comprised entirely of natural gas purchase and sale contracts and are recorded to the Gathering and Processing segment.

	(dollars in millions)
Purchase price:
Class A Common units issued		91.4
Cash paid, including transaction costs		138.6

Total purchase price	$	230.0

Allocation of purchase price:
Property, plant and equipment	$	200.5
Other assets, net of liabilities		14.4
Goodwill		15.1

Total	$	230.0

On May 18, 2001, the Partnership completed its acquisition of the assets of Enbridge Pipelines (North Dakota) L.L.C. for cash of $35.4 million, including working capital and transaction costs. No goodwill or intangible assets were recognized on acquisition. The acquisition was funded by a short-term loan from the General Partner.

Purchase price:
Cash paid, including transaction costs	$	35.4

Allocation of purchase price:
Current assets	$	2.8
Other assets		0.1
Property, plant and equipment		32.8
Current liabilities		(0.3	)

Total	$	35.4

The following summarized unaudited Pro Forma Consolidated Income Statement information for the twelve months ended December 31, 2002 and 2001 assumes the 2002 and 2001 acquisitions occurred as of January 1, 2001. These unaudited Pro Forma financial results have been prepared for comparative purposes only. These unaudited Pro Forma financial results may not be indicative of the results that would have occurred if the Partnership had completed the 2002 and 2001 acquisitions as of January 1, 2001 or the results that will be attained in the future.

	Pro Forma Year Ended December 31,
	2002		2001
	(dollars in millions, except per unit amounts) (Unaudited)
Revenues	$	1,989.6	$	2,000.2
Net Income		69.8		41.4
Net Income per Unit		1.25		0.73

Net income per unit is computed by dividing net income, after deduction of the General Partner's allocation, by the weighted average number of Class A and B Common Units and i-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 incentive distributions and an amount required to reflect

depreciation on the General Partne's historical cost basis for assets contributed on formation of the Partnership. Net income per unit was determined as follows:

In certain instances, depreciation rates have been approved by the FERC or derived from FERC orders, including those of the Lakehead System approved by the FERC effective January 1, 1999, coinciding with the in-service date for the Partnership's system expansion programs.

Depreciation rates for the pipeline systems are based on the lesser of the estimated remaining service lives of the properties or the estimated remaining life of crude oil or natural gas production in the basins served by the pipelines.

		December 31,
		2002		2001
		(dollars in millions)
Customer Contracts		$	31.1	$	15.0
Accumulated Amortization			0.7		0.0

	Net Intangibles		30.4		15.0
Other			12.6		17.6

Other assets, net		$	43.0	$	32.6

Customer contracts are comprised entirely of natural gas purchase and sale contracts and are recorded in the Gathering and Processing, Marketing and Natural Gas Transportation segments. Customer contracts are amortized over the estimated useful life of the underlying pipeline systems. The weighted average amortization period for these contracts is approximately 25 years. Amortization expense for the year ending December 31, 2002 was $0.7 million. Estimated amortization expense, based on current customer contracts for 2003 and each of the next four years is $1.2 million per year.

The changes in the carrying amount of goodwill for the year ended December 31, 2002 are as follows:

	(dollars in millions)
Balance as of December 31, 2000	$	—
Acquired during the year in conjunction with the East Texas Acquisition		15.1

Balance as of December 31, 2001	$	15.1
Acquired during the year in conjunction with the Midcoast Acquisition		226.0

Balance as of December 31, 2002	$	241.1

Net income and earnings per unit, as reported for the years ending December 31, 2001 and 2000, would have been unaffected by our adoption of SFAS No. 142 as the balance of goodwill at January 1, 2002 was acquired on November 30, 2001 and did not result in the recognition of material amortization expense for the year ending December 31, 2001.

The First Mortgage Notes ("Notes") are secured by a first mortgage on substantially all of the property, plant and equipment of the Lakehead Partnership and are due and payable in ten equal annual installments, the first of which was made in December 2002. The Notes contain various restrictive covenants applicable to the Partnership, and restrictions on the incurrence of additional indebtedness, including compliance with certain issuance tests. The Partnership believes these issuance tests will not negatively impact the Partnership's ability to finance future expansion projects. Under the Note Agreements, the Partnership cannot make cash distributions more frequently than quarterly in an amount not to exceed Available Cash (Note 8) for the immediately preceding calendar quarter. If the notes were to be paid prior to their stated maturities, the Note Agreements provide for the payment of a redemption premium by the Partnership.

The Lakehead Partnership has issued a total of $300.0 million of senior unsecured notes. The notes pay interest semi-annually and have varying maturities and terms as outlined below. The senior unsecured notes do not contain any covenants restricting the issuance of additional indebtedness.

In January 2002, the Partnership established two new unsecured credit facilities, a $300.0 million three-year term facility and a $300.0 million 364-Day facility, which replaced an existing $350.0 million

Revolving Credit Facility. Under the terms of these new facilities, the Partnership and the Lakehead Partnership may borrow funds up to a combined maximum of $300.0 million under the three-year term facility and a combined maximum of $300.0 million under the 364-Day Facility. In addition, when no default exists, the Partnership may designate any of its subsidiaries that is a material subsidiary to borrow under either or both the facilities and, subject to complying with certain administrative procedures, it will be permitted to borrow. Any borrowings under either facility are guaranteed by the Partnership, the Lakehead Partnership and any of its material subsidiaries, unless it is the borrower. The facilities contain various restrictive covenants, including maintaining a specified consolidated leverage ratio and restrictions on the incurrence of additional indebtedness. The facilities provide for borrowing at variable interest rates and a facility fee of 0.10% (2001—0.10%) per annum exists on the entire $300.0 million (2001—$350.0 million) for the three-year term facility and a facility fee of 0.15% per annum exists on the entire $300.0 million for the 364-Day Facility. At December 31, 2002, the Partnership and Lakehead Partnership had borrowed approximately $252.0 million under the three-year term facility and $212.0 million under the 364-Day facility (2001—$137.0 million).

Interest expense is net of amounts capitalized of $7.9 million (2001—$0.3 million; 2000—$0.3 million). In 2002, total interest paid was $59.2 million (2001—$57.0 million; 2000—$59.4 million).

Under the terms of the First Mortgage Notes, the Partnership is required to establish, at the end of each quarter, a debt service reserve amount. This reserve includes an amount equal to 50% of the prospective First Mortgage Note interest payments for the immediate following quarter and an amount for First Mortgage Note sinking fund repayments. At December 31, 2002, the debt service reserve was $nil (2001—$1.0 million). The debt service reserve at December 31, 2001, was $1.0 million, primarily due to the inclusion of the Revolving Credit Facility that was terminated in January, 2002.

The aggregate long-term maturities for the five years ending December 31, 2003 through 2007 are $31.0 million per year related to the First Mortgage Notes.

During the second quarter of 2001, the Partnership issued 1,813,634 Class A Common Units, which generated proceeds, net of issue expenses, of approximately $79.9 million. Proceeds from this offering were used to repay debt. On November 26, 2001, the Partnership completed the issuance of 2,250,000 Class A Common Units for net proceeds of $91.4 million. Proceeds from this offering were used to fund a portion of the East Texas System acquisition.

On March 4, 2002, the Partnership issued 2.2 million Class A Common Units, which generated proceeds, net of underwriters' discounts and commissions and issuance expenses, of approximately $90.8 million. Proceeds from this offering were used to repay indebtedness. On April 4, 2002, the Partnership issued 60,000 Class A Common Units to the underwriters in the above offering upon exercise by underwriters of the over-allotment option, resulting in additional proceeds to the Partnership, net of underwriters' discount and commissions and issuance expenses of approximately $2.5 million.

At December 31, 2002 the Partnership had 3,912,750 Class B Common Units outstanding, which are owned by the General Partner.

In October 2002, the General Partner received an allocation of the proceeds from i-unit issuance of approximately $8.2 million. In conjunction with the restructuring of the Partnership's subsidiaries immediately following the acquisition of the Midcoast system, the Partnership contributed its 1.0101% interest in Lakehead Partnership to the Partnership at its carrying value of approximately $3.3 million.

In October 2002, the Partnership received net proceeds of approximately $330.8 million from Enbridge Management for the issuance of 9,000,001 i-units. The Partnership used the net proceeds to repay debt owed to affiliates that was assumed in connection with the acquisition of the assets of Enbridge Midcoast Energy, Inc. and its subsidiaries.

The i-units are a separate class of limited partner interests in the Partnership. All of the 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 the i-units will at all times be equal.

Enbridge Management, as the owner of the 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 of owners of Enbridge Management's shares vote or refrain from voting their shares. Furthermore, under the terms of the Partnership Agreement, the Partnership agrees that it 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.

The Partnership Agreement requires that the Partnership distribute 100% of its "Available Cash", which is generally defined in the Partnership Agreement as cash receipts less cash disbursements and net additions to reserves for future requirements. These reserves are retained to provide for the proper conduct of the Partnership business and as necessary to comply with the terms of any agreement or obligation of the Partnership (including any reserves required under debt instruments for future principal and interest payments). The distributions are made to its partners within 45 days following the end of each calendar quarter in accordance with their respective percentage interests.

The General Partner is granted discretion by the 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 the quarterly distributions, it considers current and expected reserve needs along with current and expected cash flows to identify the appropriate sustainable distribution level.

Distributions by the Partnership of its Available Cash generally are made 98.0% to the Class A and B Common unitholders and the i-unitholder and 2.0% to the General Partner. The Partnership will not distribute the cash related to the i-units but instead will retain that cash and use it in the business. Distributions are subject to the payment of incentive distributions to the General Partner to the extent that certain target levels of cash distributions to the unitholders are achieved. The incremental incentive distributions payable to the General Partner are 15.0%, 25.0% and 50.0% of all quarterly distributions of Available Cash that exceed target levels of $0.59, $0.70, and $0.99 per Class A and B Common Units and i-units, respectively. Typically, the General Partner and owners of common units will receive distributions in cash. Enbridge Management, as the delegate of the General Partner under the Delegation of Control Agreement, computes the amount of the Partnership's available cash. Enbridge Management, as owner of the i-units, however, does not receive distributions in cash. Instead, each time that the Partnership makes a cash distribution to the General Partner and the holders of its common units, the number of i-units owned by Enbridge Management and the percentage of total units in the Partnership owned by Enbridge Management will increase automatically under the provisions of the Partnership's partnership agreement with the result that the number of i-units owned by Enbridge Management will equal the number of Enbridge Management's shares and voting shares that are then outstanding. The amount of this increase per i-unit 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-day period immediately preceding the ex-dividend date for Enbridge Management's shares. The cash equivalent amount of the additional i-units will be treated as if it had

actually been distributed for purposes of determining the distributions to be made to the General Partner.

In 2002, the Partnership paid cash distributions of $3.60 per unit, consisting of $0.90 per unit paid in February, May, August and November. In 2001 and 2000, the Partnership paid cash distributions of $3.50 per unit, consisting of $0.875 per unit paid in February, May, August and November.

Enbridge and its affiliates provide management, operating, administrative and payroll services to the Partnership and Enbridge Management (collectively, the "Group"). Employees of Enbridge and its affiliates are assigned to work for one or more members of the Group. The direct costs of all compensation, benefits, expenses and employee expenses for these employees are charged by Enbridge and its affiliates to the appropriate members of the Group. There is no profit or margin charged by Enbridge and its affiliates to members of the Group. The Partnership incurred costs totaling $64.7 million (2001-$36.9 million; 2000-$30.3 million) related to these services and are included in operating and administrative expenses. The Partnership has net amounts due to the General Partner and affiliates of $13.9 million at December 31, 2002 and net amounts due from the General Partner and affiliates of $0.3 million at December 31, 2001.

The Partnership generates operating revenues from the sale of natural gas to and incurs expense from the purchase of natural gas from Enbridge and its affiliates. These transactions are entered into at the market price at the date of sale. Included in the results for the twelve months ending December 31, 2002 are operating revenues of $4.6 million and cost of natural gas of $0.1 million. There were no such comparative amounts in 2001 or 2000.

The Partnership has entered into an easement acquisition agreement with Enbridge Holdings (Mustang) Inc. ("Enbridge Mustang"), an affiliate of the General Partner. Enbridge Mustang acquired the certain real property for the purpose of granting pipeline easements to the Partnership for construction of a new pipeline, completed during 1998, by the Partnership from Superior, Wisconsin to Chicago, Illinois. In order to provide for these real property acquisitions by Enbridge Mustang, the Partnership had made non-interest bearing cash advances to Enbridge Mustang. As Enbridge Mustang disposes of the real property, the advances are repaid. The advances amounted to $2.7 million at December 31, 2002 (2001-$2.9 million) and are included in the balance of amounts due from and due to the General Partner and affiliates, respectively. Under the terms of the agreement, the Partnership will reimburse Enbridge Mustang the net cost of acquiring, holding and disposing of the real property.

Tidal the ability to act as the Partnership's agent in leasing of the Partnership's terminalling and storage facility, consisting of nine 100,000 barrels ("bbl") nominal capacity tanks and related facilities. The Partnership pays Tidal a monthly fee, which includes 50% of the distributable proceeds from the tank leases. In 2002, the Partnership paid Tidal $0.5 million (2001-$0.3 million; 2000-$0.1 million).

The Partnership and its wholly owned subsidiaries have various notes payable with affiliates of Enbridge that totaled $444.1 million at December 31, 2002, (2001-$176.2 million), with a weighted average interest rate of 6.03% (2001-3.8%) and that mature in 2007.

Through a Delegation of Control Agreement with the General Partner and the Partnership, Enbridge Management makes all decisions relating to the management and control of the Partnership's business. 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 Inc., owns all the common stock of the General Partner. Some of the General Partner's officers and directors 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 the Partnership's uitholders. Certain conflicts of interest could arise as a result of the relationships among Enbridge Management, the General Partner, Enbridge and the Partnership. The partnership agreements and Delegation of Control Agreement for the Partnership and its subsidiaries contain provisions that allow Enbridge Management to take into account the interest of parties in addition to the Partnership in resolving conflicts of interest, thereby limiting its fiduciary duties to the Partnership's unitholders, as well as provisions that may restrict the remedies available to unitholders for actions taken that might, without such limitations, constitute breaches of fiduciary duty.

The Partnership is subject to federal and state laws and regulations relating to the protection of the environment. Environmental risk is inherent to liquid and gas pipeline operations and the Partnership could, at times, be subject to environmental cleanup and enforcement actions. The Partnership manages this environmental risk through appropriate environmental policies and practices to minimize any impact. To the extent that the Partnership is unable to recover environmental liabilities associated with the Lakehead System assets prior to the transfer to the Partnership in 1991, to the extent not recovered through insurance, the General Partner has agreed to indemnify the Partnership from and against any costs relating to environmental liabilities associated with the Lakehead System assets prior to the transfer to the Partnership in 1991. This excludes any liabilities resulting from a change in laws after such transfer. The Partnership continues to voluntarily investigate past leak sites on its 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 connection with the Partnership's acquisition of Midcoast, Northeast Texas and South Texas systems, the General Partner has agreed to indemnify the Partnership and other related persons for certain environmental liabilities of which the General Partner has knowledge and which it did not disclose. The General Partner will not be required to indemnify the Partnership until the aggregate liabilities, including environmental liabilities, exceed $20 million, and the General Partner's aggregate liability, including environmental liabilities, may not exceed, with certain exceptions, $150 million. The Partnership will be liable for any environmental conditions related to the acquired systems that were not known to the General Partner or were disclosed.

As at December 31, 2002, the Partnership has recorded $1.1 million in current liabilities and $5.6 million in contingencies to address remediation of asbestos containing materials, management of hazardous waste material disposal, and outstanding air quality measures for certain of its Gathering and Processing assets.

The Partnership's Liquids Transportation assets transport crude oil and NGLs owned by its customers for a fee. The volume of liquid hydrocarbons in the Partnership's pipeline system at any one time approximates 14 million barrels, virtually all of which is owned by the Partnership's customers. Under terms of the Partnership's tariffs, losses of crude oil not resulting from direct negligence of the Partnership may be apportioned among its customers. In addition, the Partnership maintains adequate property insurance coverage with respect to crude oil and NGLs in the Partnership's custody.

Approximately 60% of the natural gas volumes on the Natural Gas Transportation and Gathering and Processing assets are transported for customers on their contract, with the remaining 40% purchased by the Partnership and sold to third parties downstream of the purchase point. The value of customers' natural gas in custody of the Natural Gas Transportation systems is not material to the Partnership.

The Partnership, as part of its pipeline construction process, must obtain certain right-of-way agreements from landowners whose property the pipeline will cross. The Partnership recorded expenses for these right-of-way agreements of $1.2 million during 2002 (2001—$1.2 million, 2000—$1.0 million). As of December 31, 2002, future minimum right-of-way payments due under these agreements are approximately $1.6 million, $1.6 million, $1.7 million, $1.6 million and $1.6 million for the years ended 2003, 2004, 2005, 2006 and 2007, respectively. Thereafter, the payments due are estimated to be fairly constant and approximately $1.6 million per year for the remaining life of the pipelines.

The future minimum commitments having remaining non-cancelable terms in excess of one year are as follows:

Year Ending December 31, (dollars in millions)	Power		Other Operating Leases
2003	$	4.4	$	3.8
2004		1.5		3.3
2005		—		2.1
2006		—		2.1
2007		—		0.5

Total	$	5.9	$	11.8

At December 31, 2002, the Partnership did not have an external customer that amounted to 10 percent or more of its operating revenues. The customers listed below were all attributable to the Partnership's Liquids Transportation segment. For 2001 and 2000, operating revenue received from major customers was as follows:

	Year ended December 31,
	2001		2000
	(dollars in millions)
BP Canada Energy Company	$	73.4	$	69.6
ExxonMobil Canada Energy	$	59.7	$	48.3
PDV Midwest	$	21.4	$	33.7
Imperial Oil Limited	$	24.0	$	23.3

The Partnership has a concentration of trade receivables from companies operating in the oil and gas industry. These receivables are collateralized by the crude oil and other products contained in the Partnership's pipeline and storage facilities.

The carrying amounts of cash equivalents approximate fair value because of the short term to maturity of these investments.

Based on the borrowing rates currently available for instruments with similar terms and remaining maturities, the carrying value of borrowings under the credit facilities approximates fair value.

At December 31, 2002, the fair value of the First Mortgage Notes approximates $334.1 million (2001—$342.6 million) and the fair value of the Senior Unsecured Notes approximates $326.1 million (2001—$291.4 million). Due to defined contractual make-whole arrangements, refinancing of the First

Mortgage Notes and Senior Unsecured Notes would not result in any financial benefit to the Partnership.

The Partnership enters into interest rate swaps to manage the effect of future interest rate movements on its interest costs. The following table summarizes the interest rate financial derivatives outstanding at December 31 (dollars in millions):

						Fair Value
Reference	Notional Principal					Fair Value
Reference	Notional Principal		Coupon		Maturity Date	2002			2001
Swap #1	$	100.0	5.95	%	October 13, 2003	$	(4.6	)		—
Swap #2	$	40.0	4.48	%	November 3, 2003	$	(1.2	)		—
Swap #3	$	50.0	6.23	%	July 21, 2002		—		$	(1.9	)

These agreements meet the criteria for hedge accounting and are accounted for as cash flow hedges. Realized gains and losses on financial instruments used to hedge the Partnership's exposure to changes in future interest rates are recognized in the same period as the related interest expense.

The earnings and cash flows of the Partnership are sensitive to changes in the price of natural gas, NGLs, condensate, and to fractionation margins (the relative price differential between NGL sales and offsetting natural gas purchases). This market price exposure exists on the East Texas System, Northeast Texas System, and certain of the Midcoast Systems and within the Marketing operations. To mitigate the volatility of cash flows, the exposed entity enters into derivative financial instruments to manage the purchase and sales prices of the commodity. This transaction may be executed directly with an external financial counterparty (when an International Swap Dealers Association ("ISDA") Master Agreement exists) or by the Partnership on behalf of the exposed entity along with an inter-company swap agreement.

Natural gas financial derivative transactions are entered into by the Partnership in order to hedge the forecasted purchases or sales of natural gas. The following table details the outstanding derivatives at December 31 (dollars in millions):

			Fair Value
System	Maturity Date	Notional MMBtu	Fair Value
System	Maturity Date	Notional MMBtu	2002			2001
East Texas System	2011	29.6	$	(6.1	)	$	8.5
Northeast Texas System	2012	48.2	$	(19.1	)		—
Midcoast System	2004	1.7	$	(0.3	)		—
Marketing	2004	17.3	$	1.7			—
East Texas System	2004	0.4	$	0.4		$	6.8

NGL financial derivative transactions are entered into by the Partnership to hedge the forecasted sales of NGLs. The following table details the outstanding derivatives at December 31(dollars in millions):

			Fair Value
System	Maturity Date	Notional Barrels (millions)	Fair Value
System	Maturity Date	Notional Barrels (millions)	2002			2001
Northeast Texas System	2003	0.8	$	(2.5	)		—
Midcoast System	2003	0.1	$	(0.1	)		—
East Texas System	2002	0.0		—		$	(1.5	)

The Partnership also enters into financial derivatives transactions in order to hedge the forecasted sales of condensate volumes. The following table details the outstanding derivatives at December 31 (dollars in millions):

			Fair Value
System	Maturity Date	Notional Barrels (millions)	Fair Value
System	Maturity Date	Notional Barrels (millions)	2002			2001
Northeast Texas System	2003	0.2	$	(0.0	)	—

At December 31, 2002, no material credit risk exposure existed as the Partnership enters into financial instruments only with creditworthy institutions that possess investment grade ratings.

The gains and losses included in Accumulated other comprehensive income will be reclassified into earnings as the hedged sales and purchases take place. Approximately $2.5 million of the Accumulated other comprehensive loss balance of $16.3 million representing unrecognized net losses on derivative activities at December 31, 2002 is expected to be reclassified into earnings during the next twelve months. For each of the years ended December 31, 2002 and 2001, we did not reclassify any gains or losses into earnings as a result of the discontinuance of cash flow hedges due to a determination that the forecasted transactions will no longer occur by the end of the originally specified time period. Also, for each of the years ended December 31, 2002 and 2001, we did not recognize any material amounts in earnings as a result of ineffective hedges nor did we exclude any component of the derivative instruments' gain or loss from the assessment of hedge effectiveness.

The differences between the current market value and the original physical contracts value associated with our hedging activities are included at their fair values in the statement of financial position as follows:

	December 31,
	2002			2001
	(dollars in millions)
Accounts receivable and other	$	3.5		$	8.4
Other assets, net		—			8.5
Accounts payable and other		(13.1	)		(5.0	)
Deferred credits		(22.2	)		—

	$	(31.8	)	$	11.9

The Partnership's business is divided into operating segments, defined as components of the enterprise about which financial information is available and evaluated regularly by the Partnership in deciding how to allocate resources to an individual segment and in assessing performance of the segment.

The Partnership's reportable segments are based on the type of business activity and management control. Each segment is managed separately because each business requires different operating strategies. The Partnership has five reportable business segments, Liquids Transportation, Natural Gas Transportation, Gathering and Processing, Marketing and Corporate (see Note 1). Each segment uses accounting policies as described in the Summary of Significant Accounting Policies (see Note 2).

Due to the purchase of natural gas assets in October 2002, the Partnership changed the organization of its business segments effective in the fourth quarter of 2002. Prior to the fourth quarter of 2002, the Partnership reported Transportation as one segment, which consisted of receipt and delivery of crude oil, liquid hydrocarbons, natural gas and natural gas liquids. These activities are now reported within 3 segments—Liquids Transportation, Natural Gas Transportation and Gathering and Processing. Prior period segment results have been restated to conform to the Partnership's current organization.

The following table presents certain financial information relating to the Partnership's business segments as of or for the year ended December 31, 2002. As discussed in Note 3 to the Consolidated Financial Statements, the results from the Midcoast Acquisition were included since October 17, 2002. Comparative segment information for 2001 includes the results of the East Texas Acquisition since

November 30, 2001 and the North Dakota System Acquisition since May 18, 2001. Comparative segment information for 2000 is not shown since the Partnership had only one segment in that year.

ý	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended DECEMBER 31, 2002
OR
o	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from to

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 Class A Common Units		Name of each exchange on which registered New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act: NONE

Act		Pipeline Safety Act
ADOE		Alberta Department of Energy
AOSP		Alberta Oil Sands Project
Bbl		Barrel of liquids (approximately 42 U.S. gallons)
Bpd		Barrels per day
CAA		Clean Air Act
CAPP		Canadian Association of Petroleum Producers
CERCLA		Comprehensive Environmental Response, Compensation, and Liability Act
Cdn.		Amount denominated in Canadian dollars
CWA		Clean Water Act
DNR		Department of Natural Resources
DOT		Department of Transportation
East Texas System		Gathering, treating and processing natural gas assets in East Texas
Enbridge		Enbridge Inc., of Calgary, Alberta, Canada, the ultimate parent of the General Partner
Enbridge Management		Enbridge Energy Management, L.L.C.
Enbridge Mustang		Enbridge Holdings (Mustang) Inc.
Enbridge System		Canadian portion of the System
Enbridge Pipelines		Enbridge Pipelines Inc.
Enbridge U.S.		Enbridge (U.S.) Inc.
Energy Policy Act.		Energy Policy Act of 1992
EES		Enbridge Employee Services, Inc.
EPA		Environmental Protection Agency
Epu		Earnings per unit
Exchange Act		Securities Exchange Act of 1934
Equilon		Equilon Pipeline Company L.L.C.
Express Pipeline		Express Pipeline Ltd.
FASB		Financial Accounting Standards Board
FERC		Federal Energy Regulatory Commission
General Partner		Enbridge Energy Company, Inc.
HLPSA		Hazardous Liquid Pipeline Safety Act
ICA		Interstate Commerce Act
Lakehead Partnership		Enbridge Energy, Limited Partnership, a subsidiary operating partnership 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
Line 9		A section of the Enbridge System that extends from Sarnia, Ontario to Montreal, Quebec
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 comprised of the Midcoast System, Northeast Texas System and South Texas System.
Mobil		Mobil Pipe Line Company
Mustang		Mustang Pipe Line Partners
NEB		National Energy Board
NGA		Natural Gas Act
NGL or NGLs		Natural gas liquids
NGPA		Natural Gas Policy Act
North Dakota System		Liquids petroleum pipeline system owned in the Upper Midwest
NYSE		New York Stock Exchange
OBA		Operational balancing agreement
OPA		Oil Pollution Act
OPS		Office of Pipeline Safety
OSHA		Occupational Safety and Health Administration
PADD		Petroleum Administration for Defense Districts
PADD 2		Consists of Illinois, Indiana, Iowa, Kansas, Kentucky, Michigan, Minnesota, Missouri, Nebraska, North Dakota, Ohio, Oklahoma, South Dakota, Tennessee and Wisconsin
PADD 3		Consists of Alabama, Arkansas, Louisiana, Mississippi, New Mexico and Texas
Partnership Agreement		Third Amended and Restated Agreement of Limited Partnership of the Partnership
Partnership		Enbridge Energy Partners, L.P. and subsidiaries
PPIFG-1		Producer Price Index for Finished Goods minus 1%
RCRA		Resource Conservation and Recovery Act
RSPA		Research and Special Programs Administration
SAGD		Steam Assisted Gravity Drainage
SEC		Securities and Exchange Commission
SEP II		System Expansion Program II
Settlement Agreement		A FERC approved settlement agreement, signed October 1996
SFAS		Statement of Financial Accounting Standards
SFPP		Santa Fe Pacific Pipelines, L.P.
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
Tidal		Tidal Energy Marketing Inc.
WCSB		Western Canadian Sedimentary Basin
SPCC		Spill Prevention, Control and Countermeasure

		Deliveries
		2002	2001	2000	1999	1998
		(Thousands of bpd)
United States
	Light crude oil	266	292	321	299	338
	Medium and heavy crude oil	665	663	630	575	627
	NGL	6	5	25	24	27

	Total United States	937	960	976	898	992

Ontario
	Light crude oil	171	174	174	282	366
	Medium and heavy crude oil	83	77	85	87	97
	NGL	111	104	103	102	107

	Total Ontario	365	355	362	471	570

Total Deliveries		1,302	1,315	1,338	1,369	1,562

Barrel miles (billions per year)		341	333	341	350	391

		Average Mmbtu/d	Capacity	Reserved
Major Natural Gas Transportation Systems:
	MidLa Pipeline	60	200	89	%
	AlaTenn Pipeline(a)	52	200	71	%
	UTOS Pipeline	242	1,200	0	%
	Kansas Pipeline	48	160	97	%
	Bamagas Pipeline	5	450	61	%
Other Major Intrastates:		193	625	Up to 48	%

	Total	600	2,835

		Payment Due By Period
		Total		Less Than 1 Year		1-3 Years		4-5 Years		After 5 Years
Contractual Obligations
	Long-Term Debt	$	1,043.0	$	31.0	$	274.0	$	314.0	$	424.0
	Right-of-way (1)		48.1		1.6		3.3		3.2		40.0
	Operating Leases		11.8		3.8		5.4		2.6		—
	Purchase Commitments		5.9		4.4		1.5		—		—

Total Contractual Cash Obligations		$	1,108.8	$	40.8	$	284.2	$	319.8	$	464.0

		2003			2004			2005			2006			2007			There- after			Total		Fair Value
		Value (in millions)
Liabilities
Fixed Rate:
	First Mortgage Notes	$	31.0		$	31.0		$	31.0		$	31.0		$	31.0		$	124.0		$	279.0	$	334.1
	Interest Rate		9.15	%		9.15	%		9.15	%		9.15	%		9.15	%		9.15	%		—		—
	Senior Unsecured Notes		—			—			—			—			—		$	300.0		$	300.0	$	326.1
	Average Interest Rate		—			—			—			—			—			7.34	%		—		—
Variable Rate:
	Revolving Credit Facility				$	212.0					$	252.0			—					$	464.0	$	464.0
	Average Interest Rate					2.28	%					2.81	%		—						—		—
Interest Rate Derivatives
Interest Rate Swaps:
	Variable to Fixed	$	140.0			—			—			—			—			—		$	140.0	$	(5.8	)
	Average Pay Rate		5.53	%		—			—			—			—			—			—		—

10.17		Assumption and Indemnity Agreement, dated December 18, 1992, between Interprovincial Pipe Line Inc. and Interprovincial Pipe Line System Inc. (Exhibit 10.4 to the Partnership's 1992 Form 10-K)
10.18		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 (Exhibit 10.17 to the Partnership's 1996 Form 10-K)
10.19		Tariff Agreement as filed with the Federal Energy Regulatory Commission for the System Expansion Program II and Terrace Expansion Project (Exhibit 10.21 to the Partnership's 1998 Form 10-K)
10.20		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 (Exhibit 10.19 to the Partnership's 1998 Form 10-K)
10.21		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. (Exhibit 10.26 to the Partnership's 1999 Form 10-K)
10.22		Indenture dated September 15, 1998, between Lakehead Pipe Line Company, Limited Partnership and the Chase Manhattan Bank (Exhibit 4.1 to the 1998 Form 8-K of Lakehead Pipe Line Company, Limited Partnership dated October 20, 1998)
10.23		First Supplemental Indenture dated September 15, 1998, between Lakehead Pipe Line Company, Limited Partnership and the Chase Manhattan Bank (Exhibit 4.2 to the 1998 Form 8-K of Lakehead Pipe Line Company, Limited Partnership dated October 20, 1998)
10.24		Second Supplemental Indenture dated September 15, 1998, between Lakehead Pipe Line Company, Limited Partnership and the Chase Manhattan Bank (Exhibit 4.3 to the 1998 Form 8-K of Lakehead Pipe Line Company, Limited Partnership dated October 20, 1998)
10.25		Third Supplemental Indenture dated November 21, 2000, between Lakehead Pipe Line Company, Limited Partnership and the Chase Manhattan Bank (Exhibit 4.2 to the 2000 Form 8-K of Lakehead Pipe Line Company, Limited Partnership dated November 16, 2000)
10.26		Indenture dated September 15, 1998, between Lakehead Pipe Line Company, Limited Partnership and the Chase Manhattan Bank (Exhibit 4.4 to the 1998 Form 8-K of Lakehead Pipe Line Company, Limited Partnership dated October 20, 1998)
*10.27		Executive Employment Agreement, dated May 11, 2001, between Dan C. Tutcher, as Executive, and Enbridge Inc., as corporation.
*10.28		Executive Employment Agreement, dated May 11, 2001, between E. Chris Kaitson, as Executive, and Enbridge Inc., as corporation.
21.1		Subsidiaries of the Registrant
23.1		Consent of PricewaterhouseCoopers LLP
99.1		Certificate of Principal Executive Officer
99.2		Certificate of Principal Financial Officer

	ENBRIDGE ENERGY PARTNERS, L.P. (Registrant)
	By:	Enbridge Energy Management, L.L.C., as delegate of the General Partner
Date: March 28, 2003	By:	/s/ DAN C. TUTCHER Dan C. Tutcher (President)


/s/ DAN C. TUTCHER Dan C. Tutcher President and Director (Principal Executive Officer)		/s/ E.C. HAMBROOK E.C. Hambrook Director
/s/ J.A. CONNELLY J.A. Connelly Director		/s/ M.A. MAKI M.A. Maki Vice President — Finance (Principal Financial Officer)
/s/ C.A. RUSSELL C.A. Russell Director		/s/ P.D. DANIEL P.D. Daniel Director
/s/ G.K. PETTY G.K. Petty Director		/s/ D.P. TRUSWELL D.P. Truswell Director

		Date: March 28, 2003

		/s/ MARK A. MAKI Mark A. Maki Vice President, Finance and Principal Financial Officer

		December 31, 2002			December 31, 2001
		(dollars in millions)
ASSETS
Current assets
	Cash and cash equivalents	$	60.3		$	40.2
	Due from General Partner and affiliates		—			3.2
	Accounts receivable and other		20.7			9.9
	Trade receivables, net of allowance for doubtful accounts of $3.7 in 2002		206.9			53.2
	Materials and supplies		9.6			8.5

			297.5			115.0
Property, plant and equipment, net (Note 5)			2,253.3			1,486.6
Goodwill (Note 6)			241.1			15.0
Other assets, net (Note 6)			43.0			32.6

		$	2,834.9		$	1,649.2

LIABILITIES AND PARTNERS' CAPITAL
Current liabilities
	Due to General Partner and affiliates	$	12.5		$	—
	Accounts payable and other		146.5			48.5
	Oil shortage balance		3.2			9.4
	Accrued gas purchases		142.1			—
	Interest payable		7.0			6.8
	Property and other taxes payable		16.3			14.4
	Loans from General Partner		—			176.2
	Current maturities and short-term debt (Note 7)		31.0			31.0

			358.6			286.3
Long-term debt (Note 7)			1,011.4			715.4
Loans from General Partner and affiliates (Note 9)			444.1			—
Commitments and contingencies (Note 10)			5.6			—
Deferred credits			23.2			—
Minority interest			0.4			3.3

			1,843.3			1,005.0
Partners' capital (Note 8)
	Class A common units (Units authorized and issued — 31,313,634 in 2002 and 29,053,634 in 2001)		604.8			577.0
	Class B common units (Units authorized and issued — 3,912,750 in 2002 and 2001)		48.7			48.8
	i-units (Units authorized and issued — 9,228,655 in 2002)		335.6			—
	General Partner		18.8			6.5
	Accumulated other comprehensive (loss)/income		(16.3	)		11.9

			991.6			644.2

		$	2,834.9		$	1,649.2

		2002				2001				2000
		Units	Amount			Units	Amount			Units	Amount
		(dollars in millions)
Class A Units:
	Beginning balance	29,053,634	$	577.0		24,990,000	$	488.6		24,990,000	$	533.1
	Net income allocation	—		52.3		—		24.4		—		43.0
	Allocation of net proceeds from unit issuance	2,260,000		86.2		4,063,634		154.6		—		—
	Distributions to partners	—		(110.7	)	—		(90.6	)	—		(87.5	)

	Ending balance	31,313,634		604.8		29,053,634		577.0		24,990,000		488.6
Class B Units:
	Beginning balance	3,912,750		48.8		3,912,750		42.1		3,912,750		47.4
	Net income allocation	—		7.9		—		5.4		—		8.4
	Allocation of net proceeds from unit issuance	—		6.1		—		15.0		—		—
	Distributions to partner	—		(14.1	)	—		(13.7	)	—		(13.7	)

	Ending balance	3,912,750		48.7		3,912,750		48.8		3,912,750		42.1
i-units:
	Beginning balance	—		—		—		—		—		—
	Net income allocation	—		4.8		—		—		—		—
	Allocation of net proceeds from unit issuance	9,000,001		330.8		—		—		—		—
	Distributions to partner	228,654		—		—		—		—		—

	Ending balance	9,228,655		335.6		—		—		—		—
General Partner:
	Beginning balance	—		6.5		—		5.2		—		5.6
	Net income allocation	—		13.1		—		9.1		—		8.8
	Allocation of net proceeds from unit issuance	—		1.0		—		1.7		—		—
	General Partner contribution	—		11.5		—		—		—		—
	Distributions to partner	—		(13.3	)	—		(9.5	)	—		(9.2	)

	Ending balance	—		18.8		—		6.5		—		5.2
Accumulated other comprehensive income (loss):
	Beginning balance	—		11.9		—		—		—		—
	Unrealized (loss) gain on derivative financial instruments	—		(28.2	)	—		11.9		—		—

	Ending balance	—		(16.3	)	—		11.9		—		—

Partners capital at December 31,		44,455,039	$	991.6		32,966,384	$	644.2		28,902,750	$	535.9

		December 31,
	Depreciation Rates	December 31,
	Depreciation Rates	2002			2001
		dollars in millions)
Land	—	$	10.4		$	7.8
Rights-of-way	3.33% — 4.35%		192.5			132.4
Pipeline	1.52% — 5.63%		1,576.1			1,111.5
Pumping equipment, buildings and tanks	1.60% — 10.41%		520.1			482.4
Compressors, meters, and other operating equipment	1.52% — 14.29%		114.5			15.6
Vehicles, office furniture and equipment	4.00% — 33.33%		62.1			38.7
Processing and treater plants	4.00%		96.4			41.8
Construction in progress	—		130.1			25.9

			2,702.2			1,856.1

Accumulated depreciation			(448.9	)		(369.5	)

		$	2,253.3		$	1,486.6

				December 31,
	Weighted Average Interest Rate			December 31,
	Weighted Average Interest Rate		Maturity	2002			2001
				(dollars in millions)
First Mortgage Notes	9.15	%	2011	$	279.0		$	310.0
Senior Unsecured Notes	7.34	%	2012-2028		299.4			299.4
Three-year Term Facility	2.81	%	2006		252.0			—
364-Day Facility	2.28	%	2004		212.0			—
Revolving Credit Facility	4.48	%	2002		—			137.0

				$	1,042.4		$	746.4
Current maturities and other short-term debt					(31.0	)		(31.0	)

Long-Term debt				$	1,011.4		$	715.4

			December 31,
Senior Unsecured Notes	Interest Rate		December 31,
Senior Unsecured Notes	Interest Rate		2002			2001
Notes maturing in 2012	7.900	%	$	100.0		$	100.0
Notes maturing in 2018	7.000	%		100.0			100.0
Notes maturing in 2028	7.125	%		100.0			100.0
Unamortized Discount				(0.6	)		(0.6	)

			$	299.4		$	299.4

	As at and for the Year Ended December 31, 2002
	Liquids Transportation		Natural Gas Transportation		Gathering and Processing		Marketing		Corporate			Total
	(dollars in millions)
Operating revenues	$	334.3	$	19.8	$	702.2	$	129.2		—		$	1,185.5
Power		52.7		—		—		—		—			52.7
Cost of natural gas		—		8.6		635.2		126.9		—			770.7
Operating and administrative		104.7		4.5		34.5		0.5		—			144.2
Depreciation and amortization		64.8		2.8		12.3		—		—			79.9

Operating income		112.1		3.9		20.2		1.8		—			138.0
Interest and other income		—		—		—		—		(0.2	)		(0.2	)
Interest expense		—		—		—		—		(59.2	)		(59.2	)
Minority interest		—		—		—		—		(0.5	)		(0.5	)

Net income	$	112.1	$	3.9	$	20.2	$	1.8	$	(59.9	)	$	78.1

Total assets	$	1,502.4	$	426.7	$	730.9	$	134.9	$	40.0		$	2,834.9

Goodwill	$	—	$	73.5	$	147.2	$	20.4		—		$	241.1

Capital expenditures (excluding acquisitions)	$	202.6	$	0.6	$	11.1		—	$	0.4		$	214.7

	First		Second		Third		Fourth		Total
2002 Quarters
Operating revenue(2)	$	181.8	$	223.1	$	237.7	$	542.9	$	1,185.5
Operating income	$	32.5	$	30.4	$	31.8	$	43.3	$	138.0
Net income	$	17.7	$	16.8	$	17.6	$	26.0	$	78.1
Net income per unit(1)	$	0.43	$	0.39	$	0.42	$	0.52	$	1.76

	First		Second		Third		Fourth		Total
2001 Quarters
Operating revenue(2)	$	72.2	$	81.7	$	76.4	$	112.0	$	342.3
Operating income	$	25.0	$	26.5	$	21.1	$	25.2	$	97.8
Net income	$	10.1	$	11.6	$	6.6	$	10.6	$	38.9
Net income per unit(1)	$	0.27	$	0.32	$	0.13	$	0.26	$	0.98