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

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

FORM 10-K

Commission File Number: 1-10934

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

        Indicate by check mark whether the Registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the Registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ý    No o

        Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of the Registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. 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.

        DOCUMENTS INCORPORATED BY REFERENCE: NONE

TABLE OF CONTENTS

        This Annual Report on Form 10-K contains forward-looking statements. These forward-looking statements are identified as any statement that does not relate strictly to historical or current facts. They use words such as "anticipate," "believe," "continue," "estimate," "expect," "forecast," "intend," "may," "plan," "position," "projection," "strategy" 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.

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Glossary

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

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PART I

Items 1 & 2. Business and Properties

Overview

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

        The Partnership was formed in 1991 by the General Partner to own and operate the Lakehead System, which is the U.S. portion of a crude oil and liquid petroleum pipeline system extending from western Canada through the upper and lower Great Lakes region of the United States to eastern Canada. 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.

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Liquids Transportation includes the operation of a common carrier pipeline and a feeder pipeline which transport crude oil and other liquid hyrdocarbons.



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



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



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



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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 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

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

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natural gas transmission and wholesale customer pipelines;



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natural gas gathering, treating and processing systems, including its trucking operations; and



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marketing activities.

        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").

Business Strategy

        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.

Available Information

        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.

Liquids Transportation Segment

Lakehead System

        The Lakehead System in the United States and the Enbridge System in Canada, which is owned by Enbridge Pipelines, a wholly-owned subsidiary of Enbridge, together form the System. The System, which spans 3,100 miles, is the longest liquid petroleum pipeline system in the world and transports crude oil and other liquid petroleum products for third parties. The System is the primary transporter

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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

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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:

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



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U.S. production at Lewiston, Michigan; and



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

        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

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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.

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Phase I of the Terrace expansion was completed in 1999 and included construction of new 36-inch diameter pipeline facility from Kerrobert, Saskatchewan to Clearbrook, Minnesota that added approximately 170,000 bpd of capacity to the System. The Partnership's share of the cost of Phase I was approximately $140 million.



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



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Phase III of the Terrace expansion is designed primarily to increase heavy oil transportation capacity on the Lakehead System between Clearbrook, Minnesota and Superior, Wisconsin by approximately 140,000 bpd. The estimated cost to the Partnership of Phase III is approximately $210 million, and the new facilities are expected to be fully in service by mid 2003.



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CAPP has also requested that the Partnership construct additional pipeline facilities at an estimated cost of $35 million to enhance crude oil delivery and operational flexibility into the Chicago market. Subject to receipt of necessary governmental approvals, the Partnership expects these additional facilities to be in service in 2003.

        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.

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        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.

North Dakota System

        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.

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Natural Gas Transportation Segment

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

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the Kansas Pipeline, MidLa Pipeline, AlaTenn Pipeline, and UTOS Pipeline systems, which are FERC regulated interstate pipelines; and



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

        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.

        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

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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.

Gathering and Processing Segment

East Texas System

        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.

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        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.

Other Gathering and Processing Systems

        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.

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The Anadarko system consists of 730 miles of pipeline in southwest Oklahoma and the Texas panhandle, one natural gas treating plant and three natural gas processing plants, two of which are inactive.

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The Northeast Texas System is a natural gas gathering system located just north of and adjacent to the area served by the Partnership's East Texas System. A substantial portion of the Northeast Texas System's pipeline infrastructure and the Partnerships' East Texas System previously were owned and operated as a single system.

The Northeast Texas System purchases natural gas directly from producers and/or provides natural gas gathering, treating and processing services to intrastate and interstate pipelines and other owners of natural gas. The Northeast Texas System is capable of handling sour gas, which has a high hydrogen sulfide and/or carbon dioxide and water content and which requires specialized treating processes before it can be delivered for transportation on downstream pipelines.

The Northeast Texas System includes natural gas processing operations where NGLs are separated from raw natural gas and either sold and transported as NGL raw mix or further separated through fractionation into ethane, propane, butane and natural gasoline and sold as components. Residue gas is delivered to wholesale customers and to interstate and intrastate pipelines.

The Northeast Texas System includes approximately 1,200 miles of natural gas gathering pipelines and five natural gas treating plants with a combined capacity of 310 million cubic feet per day, four of which are currently active, and represent a treating capacity of 285 million cubic feet per day. These treating plants are capable of producing approximately 1,100 long tons of sulfur per day. The Northeast Texas System also includes four natural gas processing plants with a combined capacity of 165 million cubic feet per day, two of which are currently active, and represent a processing capacity of 120 million cubic feet per day, and two nitrogen rejection plants with a capacity of 75 million cubic feet per day. The Partnership idled a processing and treating plan in November 2002 to achieve operational efficiencies. Approximately 140 million cubic feet of natural gas per day flows into the gathering pipelines from approximately 525 gathering points.

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The South Texas System is a natural gas gathering and treating system that purchases and/or gathers natural gas at the wellhead, delivers it to plants for treating and/or processing and then delivers it to interstate and intrastate transmission pipelines for transmission. The South Texas System currently includes approximately 175 miles of natural gas gathering pipelines, one active hydrogen sulfide treating facility and one inactive natural gas processing plant. Approximately 30 million cubic feet of natural gas per day flows into the gathering pipelines from approximately 40 gathering points.

In connection with the acquisition of the South Texas System, the Partnership obtained the ("Transco") right, under asset purchase agreements with each of Transcontinental Gas Pipe Line Corporation, Williams Field Services and Goebel Gathering Company, to acquire for approximately $41 million, a 500 mile natural gas transmission pipeline system that interconnects with the South Texas gathering and treating system. These assets consist of two mainlines that run from South Texas near Laredo and McAllen to a point of interconnection in Wharton County, Texas and a 38-mile lateral line connecting the two mainlines. The closing of this acquisition 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

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The Harmony system consists of 155 miles of pipeline in southeast Mississippi, and it includes an active natural gas treating plant and processing plant.

        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

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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.

Trucking Operations

        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.

Marketing Segment

        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.

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        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.

Risk Factors

Transportation Volumes

        The Partnership's financial performance depends to a large extent on the volume of products transported on its pipeline systems. Decreases in the volume of products transported by the Partnership's systems, whether caused by supply and demand factors in the markets these systems serve, or otherwise, can directly and adversely affect the Partnership's revenues and results of operations.

Lakehead System

        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.

Other Systems

        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.

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Regulation

        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.

Lakehead System

        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.

Midcoast System

        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.

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Competition

Lakehead System

        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.

Other Systems

        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.

Competition with Enbridge

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

•

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



•

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



•

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



•

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

        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

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

Market Risk

        As part of its 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 ability to negotiate, on a timely basis, natural gas purchase and sales agreements in changing markets;



•

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



•

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



•

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



•

the ability of its customers to make timely payment.

Environmental and Safety Regulations

        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.

Kyoto Protocol

        In December 2002, Canada ratified the Kyoto Protocol, a 1997 treaty designed to reduce greenhouse gas emissions to 6% below 1990 levels. The Partnership and Enbridge are assessing and evaluating the Canadian federal government's approach to implementation. Until these plans become certain, the Partnership will not be able to quantify the impact, if any, 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.

Transportation of Hazardous Materials

        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.

Growth Strategy

        The acquisition of complementary energy delivery assets is a focus of the Partnership's strategic plan. Acquisitions may present various risks and challenges, including the risks of incorrect assumptions

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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

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

•

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



•

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



•

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

        There are inherent difficulties in quantifying oil measurement losses because physical measurements of volumes are not practical 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.

Conflicts of Interest

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

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

        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

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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.

Title to Properties

        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.

Regulation

Regulation by the FERC of Interstate Common Carrier Liquids Pipelines

        The Lakehead and North Dakota Systems are interstate common carrier liquids pipelines subject to regulation by the FERC under the ICA. As interstate common carriers, these pipelines provide service to any shipper who requests transportation services, provided that products tendered for transportation satisfy the conditions and specifications contained in the applicable tariff. The ICA requires the Partnership to maintain tariffs on file with the FERC that set forth the rates it charges for providing transportation services on its interstate common carrier pipelines, as well as the rules and regulations governing these services.

        The ICA gives the FERC the authority to regulate the rates the Partnership charges for service on its interstate common carrier pipelines. The ICA requires, among other things, that such rates be "just and reasonable" and nondiscriminatory. The ICA permits interested persons to challenge new or proposed changes to existing rates and authorizes the FERC to suspend the effectiveness of such rates for a period of up to seven months and to order a hearing concerning such rates. If, upon completion of an investigation, the FERC finds that the new or changed rate is unlawful, it is authorized to require the carrier to refund the revenues in excess of the prior tariff during the term of the investigation. The FERC also may investigate, upon complaint or on its own motion, rates that are already in effect and may order a carrier to change its rates prospectively. Upon an appropriate showing, a shipper may obtain reparations for damages sustained for a period of up to two years prior to the filing of a complaint.

        On October 24, 1992, Congress passed the Energy Policy Act, which deemed petroleum pipeline rates that were in effect for the 365-day period ending on the date of enactment and had not been

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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 pipeli