Use these links to rapidly review the documentTABLE OF CONTENTS INDEX TO FINANCIAL STATEMENTS, SUPPLEMENTARY INFORMATION AND FINANCIAL STATEMENT SCHEDULES ENBRIDGE ENERGY PARTNERS L.P.

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UNITED STATES
SECURITIES AND EXCHANGE COMMISSIONWashington, D.C. 20549

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FORM 10-K

|ý                                           | ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934    
|------------------------------------------- | ----------------------------------------------------------------------------------------
|For the fiscal year ended DECEMBER 31, 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         

Commission File Number: 1-10934

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

|Delaware(State or other jurisdiction of
incorporation or organization)                              |  | 39-1715850(I.R.S. Employer Identification No.)                   
|--------------------------------------------------------------------------------------------------- |  | -----------------------------------------------------------------
|1100 Louisiana
Suite 3300
Houston, Texas 77002(Address of principal executive offices and zip code)
|(713) 821-2000(Registrant's telephone number, including area code)                                 
|Securities registered pursuant to Section 12(b) of the Act:                                        
|Title of each class 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                                   

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

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TABLE OF CONTENTS



|                                                                                           |  |                                                                                         
|------------------------------------------------------------------------------------------ |  | ----------------------------------------------------------------------------------------
|                                                                                           |  | 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.

2

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Glossary

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

|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                                                                                      

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|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                                                                                                                       

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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.



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:



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



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:



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.



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.

|                                |                            | Deliveries
|------------------------------- | -------------------------- | ----------
|
|
|United States                   |                            |           
|                                | Light crude oil            |           
|                                | Medium and heavy crude oil |           
|                                | NGL                        |           
|                                |                            |           
|                                | Total United States        |           
|                                |                            |           
|Ontario                         |                            |           
|                                | Light crude oil            |           
|                                | Medium and heavy crude oil |           
|                                | NGL                        |           
|                                |                            |           
|                                | Total Ontario              |           
|                                |                            |           
|Total Deliveries                |                            | 1,302     
|                                |                            |           
|Barrel miles(billions per year) |                            | 341       
|                                |                            |           



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:



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, 2002Kansas 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

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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



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.



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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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.



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 ProceedingThe 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:



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:



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:



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



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 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:



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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.

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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.

24

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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

25

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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.

Tariffs and Rate Cases



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 BarrelTo Clearbrook, Minnesota

$
0.173To Superior, Wisconsin

$
0.338To Chicago, Illinois area

$
0.691To Marysville, Michigan area

$
0.826To Buffalo, New York area

$
0.846Chicago 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

26

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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.

Environmental and Safety Regulation



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

27

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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

28

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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

29

---

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

30

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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

31

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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.

Employees

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.

Insurance

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.

Capital Expenditures

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."

32

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Taxation

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.

Other Matters

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.

Item 3. Legal Proceedings

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 4. Submission of Matters to a Vote of Security Holders

No matters were submitted to a vote of security holders during 2002.

PART II

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

33

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

First

Second

Third

Fourth2002 QuartersHigh

$
46.25

$
46.75

$
46.25

$
44.00Low

$
41.00

$
43.15

$
35.68

$
37.80Cash distributions paid

$
0.90

$
0.90

$
0.90

$
0.902001 QuartersHigh

$
46.90

$
46.50

$
49.60

$
48.90Low

$
41.25

$
43.80

$
39.50

$
38.90Cash 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.

34

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Item 6. Selected Financial Data

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.

|                                       |                                                                        | Year Ended December 31,           |      
|-------------------------------------- | ---------------------------------------------------------------------- | --------------------------------- | -----
|
|
|Income Statement Data:                 |                                                                        |                                   |      
|                                       | Operating revenue                                                      |                                   | $    
|                                       | Operating expenses                                                     |                                   |      
|                                       |                                                                        |                                   |      
|                                       | Operating income                                                       |                                   |      
|                                       | Interest and other income                                              |                                   |      
|                                       | Interest expense                                                       |                                   |      
|                                       | Minority interest                                                      |                                   |      
|                                       |                                                                        |                                   |      
|                                       | Net income                                                             |                                   | $    
|                                       |                                                                        |                                   |      
|                                       | Net income per unit (1)                                                |                                   | $    
|                                       |                                                                        |                                   |      
|                                       | Cash distributions paid per unit                                       |                                   | $    
|                                       |                                                                        |                                   |      
|Financial Position Data (at year end): |                                                                        |                                   |      
|                                       | Property, plant and equipment, net                                     |                                   | $    
|                                       | Total assets                                                           |                                   | $    
|                                       | Long-term debt                                                         |                                   | $    
|                                       | Loans from General Partner and affiliates                              |                                   | $    
|                                       | Partners' capital                                                      |                                   |      
|                                       |                                                                        | Class A common units              |      
|                                       |                                                                        | Class B common units              |      
|                                       |                                                                        | i-units                           |      
|                                       |                                                                        | General Partner                   |      
|                                       |                                                                        | Other comprehensive (loss) income |      
|                                       |                                                                        |                                   |      
|                                       |                                                                        | $                                 | 991.6
|                                       |                                                                        |                                   |      
|Cash Flow Data:                        |                                                                        |                                   |      
|                                       | Cash flows from operating activities                                   |                                   | $    
|                                       | Cash flows used in investing activities                                |                                   |      
|                                       | Cash flows from (used in) financing activities                         |                                   |      
|                                       | Acquisitions and capital expenditures included in investing activities |                                   |      
|Operating Data  Lakehead System       |                                                                        |                                   |      
|                                       | Barrel miles (billions)                                                |                                   |      
|                                       | Lakehead Systems Deliveries
(thousands of bpd)                         |                                   |      
|                                       |                                                                        | United States                     |      
|                                       |                                                                        | Province of Ontario               |      
|                                       |                                                                        |                                   |      
|                                       |                                                                        |                                   | 1,302
|                                       |                                                                        |                                   |      

---

35

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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.

Highlights

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.

Businesses

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

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

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

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

36

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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

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

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.

Critical Accounting Policies and Estimates

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.

Revenue Recognition

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

37

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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

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.

38

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Goodwill and Other Intangible Assets

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.

Accounting for Derivative Financial Instruments

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

39

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

Oil Shortage Balance and Oil Measurement Losses

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.

Operational Balancing Agreements

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.

Regulated Natural Gas Pipelines

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.

Periodic Accounting Accruals

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.

Results of Operations

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.

40

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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 IncomeLiquids Transportation

$
112.1

$
97.7

$
117.9Natural Gas Transportation


3.9





Gathering and Processing


20.2


0.1


Marketing


1.8





Total Operating Income


138.0


97.8


117.9Corporate


(59.9
)

(58.9
)

(57.7
)Net Income

$
78.1

$
38.9

$
60.2


Liquids Transportation

Description

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.

Results of Operations

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.

41

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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.

Natural Gas Transportation

Description

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.

|                                          |                     | 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 |          |   
|                                          |                     |                 |     |          |       |          |   

---



42

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Results of Operations

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.

Gathering and Processing

Description

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].

43

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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/dEast Texas System

429Anadarko

222Northeast Texas System

138Tilden

30Total

819


Results of Operations

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.

Marketing

Description

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.

Result of Operations

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

Description

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.

Results of Operations

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

44

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

Liquidity and Capital Resources

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

45

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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

46

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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.

Summary of Obligations and Commitments

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

|                                   |                      | Payment Due By Period
|---------------------------------- | -------------------- | ---------------------
|
|Contractual Obligations            |                      |                      
|                                   | Long-Term Debt       |                      
|                                   | Right-of-way (1)     |                      
|                                   | Operating Leases     |                      
|                                   | Purchase Commitments |                      
|                                   |                      |                      
|Total Contractual Cash Obligations |                      | $                    
|                                   |                      |                      

---

47

---

Other Matters

Future Prospects

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.

Liquids Transportation

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."

Natural GasGathering and Processing, Transportation and Marketing

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

48

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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.

Growth by Acquisitions

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.

Regulatory Matters

Kansas Pipeline

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 10th Circuit.

UTOS Pipeline

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.

Liquids Petroleum Pipelines

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

49

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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.

Recent Accounting Developments

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.

Subsequent Event

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.

Item 7a. Quantitative and Qualitative Disclosures About Market Risk

Interest Rate and Foreign Exchange Risk

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.

50

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Expected Maturity Date

|                          |                           | 2003 |   | 2004  |   | 2005 |       | 2006 |   | 2007 |   | There-
after |       | Total |   | Fair
Value |  
|------------------------- | ------------------------- | ---- | - | ----- | - | ---- | ----- | ---- | - | ---- | - | ------------ | ----- | ----- | - | ---------- | -
|
|Liabilities               |                           |      |   |       |   |      |       |      |   |      |   |              |       |       |   |            |  
|Fixed Rate:               |                           |      |   |       |   |      |       |      |   |      |   |              |       |       |   |            |  
|                          | First Mortgage Notes      |      | $ | 31.0  |   | $    | 31.0  |      | $ | 31.0 |   | $            | 31.0  |       | $ | 31.0       |  
|                          | Interest Rate             |      |   | 9.15  | % |      | 9.15  | %    |   | 9.15 | % |              | 9.15  | %     |   | 9.15       | %
|                          | Senior Unsecured Notes    |      |   |      |   |      |      |      |   |     |   |              |      |       |   |           |  
|                          | Average Interest Rate     |      |   |      |   |      |      |      |   |     |   |              |      |       |   |           |  
|Variable Rate:            |                           |      |   |       |   |      |       |      |   |      |   |              |       |       |   |            |  
|                          | Revolving Credit Facility |      |   |       |   | $    | 212.0 |      |   |      |   | $            | 252.0 |       |   |           |  
|                          | Average Interest Rate     |      |   |       |   |      | 2.28  | %    |   |      |   |              | 2.81  | %     |   |           |  
|Interest Rate Derivatives |                           |      |   |       |   |      |       |      |   |      |   |              |       |       |   |            |  
|Interest Rate Swaps:      |                           |      |   |       |   |      |       |      |   |      |   |              |       |       |   |            |  
|                          | Variable to Fixed         |      | $ | 140.0 |   |      |      |      |   |     |   |              |      |       |   |           |  
|                          | Average Pay Rate          |      |   | 5.53  | % |      |      |      |   |     |   |              |      |       |   |           |  

Commodity Price Risk

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 ValueMaturity
Date

Remaining
Notional2002

2001MMBtuEast Texas System

2011

29.6

$
(6.1
)
$
8.5Northeast 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


51

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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 ValueMaturity
Date

Remaining
Notional2002

2001BblNortheast 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 ValueMaturity
Date

Notional
Barrels2002

2001Northeast Texas System

2003

0.2

$
0.0




Item 8. Financial Statements and Supplementary Data

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

None.

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PART III

Item 10. Directors and Executive Officers of the Registrant

(a) Directors and Executive Officers of the Registrant

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

PositionJ.A. Connelly

56

DirectorP.D. Daniel

56

DirectorE.C. Hambrook

65

DirectorG.K. Petty

61

DirectorC.A. Russell

70

DirectorD.P. Truswell

59

DirectorD.C. Tutcher

54

President and DirectorJ.R. Bird

53

Group Vice President  Liquids TransportationG.L.Sevick

47

Vice President  Liquids Transportation OperationsM.A. Maki

38

Vice President  FinanceA. Monaco

43

TreasurerJ.L. Balko

37

ControllerE.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

53

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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.

54

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(b) Section 16(a) Beneficial Ownership Reporting Compliance

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.

11. Executive Compensation

Executive Compensation

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.

Summary
Compensation Table

|                                                                      |  |   |         |  |   |         |  |   |        | Approximate
Percentage
of Time
Devoted to
Enbridge
Management
and the
Partnership
|--------------------------------------------------------------------- |  | - | ------- |  | - | ------- |  | - | ------ | ---------------------------------------------------------------------------------
|
|
|D.C. Tutcher
President                                                |  | $ | 296,250 |  | $ | 300,000 |  | $ | 40,000 |                                                                                  
|T.L. McGill
Vice PresidentCommercial Activity & Business Development |  | $ | 182,474 |  | $ | 50,000  |  | $ | 16,886 |                                                                                  
|E.C.Kaitson
Secretary                                                 |  | $ | 161,250 |  | $ | 25,000  |  | $ | 10,000 |                                                                                  
|M.A. Maki
Vice President-Finance                                      |  | $ | 136,762 |  | $ | 35,000  |  | $ | 25,978 |                                                                                  

Notes:

55

---



Composition Committee Interlocks and Insider Participation

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.

Stock Options

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.

Employment Agreements

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.,

56

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(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.

Director Compensation

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.

Item 12. Security Ownership of Certain Beneficial Owners and Management



57

---



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 ClassEnbridge Energy Management, L.L.C.
1100 Louisiana, Suite 3300
Houston, TX 77002

i-units

9,228,655

100.0Enbridge Energy Company, Inc.
1100 Louisiana, Suite 3300
Houston, TX 77002

Class B Common Units

3,912,750

100.0Goldman, 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 ClassE.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

*


*
Less than 1%

Item 13. Certain Relationships and Related Transactions

Interest of the General Partner in the Partnership

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

58

---

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:

|                                      |                                                                   | Unitholders |    | 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.

Enbridge Inc.

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).

59

---

Affiliate Notes

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)

Conflicts of Interest

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.

Item 14. Controls and Procedures

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.

PART IV

Item 15. Exhibits, Financial Statement Schedules and Reports on Form 8-K

(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.

60

---

(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)                                                                                                                                                                                          

61

---

|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                                                                                                                                                                                                               

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.

*
Managment Compensation or Incentive Plan

62

---



SIGNATURES

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

|                     |  | ENBRIDGE ENERGY PARTNERS, L.P. (Registrant)
|-------------------- |  | -------------------------------------------
|                     |  | By:                                        
|Date: March 28, 2003 |  | By:                                        

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.

|                                                                                     |  |                                                                             
|------------------------------------------------------------------------------------ |  | ----------------------------------------------------------------------------
|/s/DAN C. TUTCHERDan C. Tutcher
President and Director
(Principal Executive Officer) |  | /s/E.C. HAMBROOKE.C. Hambrook
Director                                      
|/s/J.A. CONNELLYJ.A. Connelly
Director                                               |  | /s/M.A. MAKIM.A. Maki
Vice President  Finance
(Principal Financial Officer)
|/s/C.A. RUSSELLC.A. Russell
Director                                                 |  | /s/P.D. DANIELP.D. Daniel
Director                                          
|/s/G.K. PETTYG.K. Petty
Director                                                     |  | /s/D.P. TRUSWELLD.P. Truswell
Director                                      

63

---



Sarbanes-Oxley Section 302(a) Certification

I,
Dan C. Tutcher, certify that:

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

| |  | Date: March 28, 2003                                                      |  | 
| |  | ------------------------------------------------------------------------- |  | 
| |  |                                                                           |  | 
| |  | /s/DAN C. TUTCHERDan C. Tutcher
President and Principal Executive Officer |  | 

64

---



Sarbanes-Oxley Section 302(a) Certification

I,
Mark A. Maki, certify that:

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

| |  | Date: March 28, 2003                                                                 |  | 
| |  | ------------------------------------------------------------------------------------ |  | 
| |  |                                                                                      |  | 
| |  | /s/MARK A. MAKIRMark A. Maki
Vice President, Finance and
Principal Financial Officer |  | 

65

---

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



|                    
|--------------------
|Financial Statements
|                    
|                    
|                    
|                    
|                    
|                    
|                    

FINANCIAL STATEMENT SCHEDULES

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.

F-

---



Report of Independent Accountants

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

In
our opinion, the accompanying consolidated statements of financial position and the related consolidated statements of income, 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.

PricewaterhouseCoopers
LLP

Houston,
Texas
January 27, 2003

F-2

---



ENBRIDGE ENERGY PARTNERS, L.P.    CONSOLIDATED STATEMENTS OF INCOME

|                                              |                               | Year ended December 31, |        
|--------------------------------------------- | ----------------------------- | ----------------------- | -------
|
|
|Operating revenue                             |                               | $                       | 1,185.5
|Expenses                                      |                               |                         |        
|                                              | Power                         |                         |        
|                                              | Cost of natural gas           |                         |        
|                                              | Operating and administrative  |                         |        
|                                              | Depreciation and amortization |                         |        
|                                              |                               |                         |        
|                                              |                               |                         | 1,047.5
|                                              |                               |                         |        
|Operating income                              |                               |                         | 138.0  
|Interest and other income (expense)           |                               |                         | (0.2   
|Interest expense                              |                               |                         | (59.2  
|Minority interest                             |                               |                         | (0.5   
|                                              |                               |                         |        
|Net income                                    |                               | $                       | 78.1   
|                                              |                               |                         |        
|Net income per unit (Note 4)                  |                               | $                       | 1.76   
|                                              |                               |                         |        
|Weighted average units outstanding (millions) |                               |                         | 36.7   
|                                              |                               |                         |        
|Cash distributions paid per unit              |                               | $                       | 3.60   
|                                              |                               |                         |        

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

F-3

---



ENBRIDGE ENERGY PARTNERS, L.P.    CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

|                                                           |  | Year ended December 31,
|---------------------------------------------------------- |  | -----------------------
|
|
|Net income                                                 |  | $                      
|Unrealized (loss) gain on derivative financial instruments |  |                        
|                                                           |  |                        
|Comprehensive income                                       |  | $                      
|                                                           |  |                        

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

F-4

---



ENBRIDGE ENERGY PARTNERS, L.P.    CONSOLIDATED STATEMENTS OF CASH FLOWS

|                                                     |                                                                                 | Year ended December 31,       |                                                                             
|---------------------------------------------------- | ------------------------------------------------------------------------------- | ----------------------------- | ----------------------------------------------------------------------------
|
|
|Cash provided from operating activities              |                                                                                 |                               |                                                                             
|                                                     | Net income                                                                      |                               | $                                                                           
|                                                     | Adjustments to reconcile net income to cash provided from operating activities: |                               |                                                                             
|                                                     |                                                                                 | Depreciation and amortization |                                                                             
|                                                     |                                                                                 | Other                         |                                                                             
|                                                     |                                                                                 |                               | Changes in operating assets and liabilites, net of acquired working capital:
|                                                     |                                                                                 |                               | Accounts receivable and other                                               
|                                                     |                                                                                 |                               | Oil (shortage) overage balance                                              
|                                                     |                                                                                 |                               | Materials and supplies                                                      
|                                                     |                                                                                 |                               | General Partner and affiliates                                              
|                                                     |                                                                                 |                               | Accounts payable and other                                                  
|                                                     |                                                                                 |                               | Interest payable                                                            
|                                                     |                                                                                 |                               | Property and other taxes                                                    
|                                                     |                                                                                 |                               |                                                                             
|                                                     |                                                                                 |                               | 200.6                                                                       
|                                                     |                                                                                 |                               |                                                                             
|Investing activities                                 |                                                                                 |                               |                                                                             
|                                                     | Additions to property, plant and equipment                                      |                               |                                                                             
|                                                     | Changes in construction payable                                                 |                               |                                                                             
|                                                     | Asset acquisitions, net of cash acquired (Note 3)                               |                               |                                                                             
|                                                     |                                                                                 |                               |                                                                             
|                                                     |                                                                                 |                               | (557.2                                                                      
|                                                     |                                                                                 |                               |                                                                             
|Financing activities                                 |                                                                                 |                               |                                                                             
|                                                     | Proceeds from unit issuances, net (Note 8)                                      |                               |                                                                             
|                                                     | (Repayments of) / loans from General Partner and affiliates                     |                               |                                                                             
|                                                     | Distributions to partners                                                       |                               |                                                                             
|                                                     | Revolving Credit Facility                                                       |                               |                                                                             
|                                                     | 364-Day Facility                                                                |                               |                                                                             
|                                                     | Three-year term facility                                                        |                               |                                                                             
|                                                     | Fixed rate financing, net                                                       |                               |                                                                             
|                                                     | Other                                                                           |                               |                                                                             
|                                                     |                                                                                 |                               |                                                                             
|                                                     |                                                                                 |                               | 376.7                                                                       
|                                                     |                                                                                 |                               |                                                                             
|Net increase (decrease) in cash and cash equivalents |                                                                                 |                               | 20.1                                                                        
|Cash and cash equivalents at beginning of year       |                                                                                 |                               | 40.2                                                                        
|                                                     |                                                                                 |                               |                                                                             
|Cash and cash equivalents at end of year             |                                                                                 |                               | 60.3                                                                        
|                                                     |                                                                                 |                               |                                                                             

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

F-5

---



ENBRIDGE ENERGY PARTNERS, L.P.    CONSOLIDATED STATEMENTS OF FINANCIAL POSITION

|                                                   |                                                                                                | December 31,
2002 |         | December 31,
2001
|-------------------------------------------------- | ---------------------------------------------------------------------------------------------- | ----------------- | ------- | -----------------
|
|ASSETS                                             |                                                                                                |                   |         |                  
|Current assets                                     |                                                                                                |                   |         |                  
|                                                   | Cash and cash equivalents                                                                      |                   | $       | 60.3             
|                                                   | Due from General Partner and affiliates                                                        |                   |         |                 
|                                                   | Accounts receivable and other                                                                  |                   |         | 20.7             
|                                                   | Trade receivables,
net of allowance for doubtful accounts of $3.7 in 2002                      |                   |         | 206.9            
|                                                   | Materials and supplies                                                                         |                   |         | 9.6              
|                                                   |                                                                                                |                   |         |                  
|                                                   |                                                                                                |                   | 297.5   |                  
|Property, plant and equipment, net (Note 5)        |                                                                                                |                   | 2,253.3 |                  
|Goodwill (Note 6)                                  |                                                                                                |                   | 241.1   |                  
|Other assets, net (Note 6)                         |                                                                                                |                   | 43.0    |                  
|                                                   |                                                                                                |                   |         |                  
|                                                   |                                                                                                | $                 | 2,834.9 |                  
|                                                   |                                                                                                |                   |         |                  
|LIABILITIES AND PARTNERS' CAPITAL                  |                                                                                                |                   |         |                  
|Current liabilities                                |                                                                                                |                   |         |                  
|                                                   | Due to General Partner and affiliates                                                          |                   | $       | 12.5             
|                                                   | Accounts payable and other                                                                     |                   |         | 146.5            
|                                                   | Oil shortage balance                                                                           |                   |         | 3.2              
|                                                   | Accrued gas purchases                                                                          |                   |         | 142.1            
|                                                   | Interest payable                                                                               |                   |         | 7.0              
|                                                   | Property and other taxes payable                                                               |                   |         | 16.3             
|                                                   | Loans from General Partner                                                                     |                   |         |                 
|                                                   | Current maturities and short-term debt (Note 7)                                                |                   |         | 31.0             
|                                                   |                                                                                                |                   |         |                  
|                                                   |                                                                                                |                   | 358.6   |                  
|Long-term debt (Note 7)                            |                                                                                                |                   | 1,011.4 |                  
|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     |                  
|                                                   |                                                                                                |                   |         |                  
|                                                   |                                                                                                |                   | 1,843.3 |                  
|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            
|                                                   | Class B common units (Units authorized and issued  3,912,750 in 2002 and 2001)                |                   |         | 48.7             
|                                                   | i-units (Units authorized and issued  9,228,655 in 2002)                                      |                   |         | 335.6            
|                                                   | General Partner                                                                                |                   |         | 18.8             
|                                                   | Accumulated other comprehensive (loss)/income                                                  |                   |         | (16.3            
|                                                   |                                                                                                |                   |         |                  
|                                                   |                                                                                                |                   | 991.6   |                  
|                                                   |                                                                                                |                   |         |                  
|                                                   |                                                                                                | $                 | 2,834.9 |                  
|                                                   |                                                                                                |                   |         |                  

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

F-6

---



ENBRIDGE ENERGY PARTNERS, L.P.    CONSOLIDATED STATEMENTS OF PARTNERS' CAPITAL

|                                               |                                                            | 2002       |            | 2001 |       | 2000   |           
|---------------------------------------------- | ---------------------------------------------------------- | ---------- | ---------- | ---- | ----- | ------ | ----------
|
|
|Class A Units:                                 |                                                            |            |            |      |       |        |           
|                                               | Beginning balance                                          |            | 29,053,634 |      | $     | 577.0  |           
|                                               | Net income allocation                                      |            |           |      |       | 52.3   |           
|                                               | Allocation of net proceeds from unit issuance              |            | 2,260,000  |      |       | 86.2   |           
|                                               | Distributions to partners                                  |            |           |      |       | (110.7 | )         
|                                               |                                                            |            |            |      |       |        |           
|                                               | Ending balance                                             |            | 31,313,634 |      |       | 604.8  |           
|Class B Units:                                 |                                                            |            |            |      |       |        |           
|                                               | Beginning balance                                          |            | 3,912,750  |      |       | 48.8   |           
|                                               | Net income allocation                                      |            |           |      |       | 7.9    |           
|                                               | Allocation of net proceeds from unit issuance              |            |           |      |       | 6.1    |           
|                                               | Distributions to partner                                   |            |           |      |       | (14.1  | )         
|                                               |                                                            |            |            |      |       |        |           
|                                               | Ending balance                                             |            | 3,912,750  |      |       | 48.7   |           
|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    |           
|                                               | Net income allocation                                      |            |           |      |       | 13.1   |           
|                                               | Allocation of net proceeds from unit issuance              |            |           |      |       | 1.0    |           
|                                               | General Partner contribution                               |            |           |      |       | 11.5   |           
|                                               | Distributions to partner                                   |            |           |      |       | (13.3  | )         
|                                               |                                                            |            |            |      |       |        |           
|                                               | Ending balance                                             |            |           |      |       | 18.8   |           
|Accumulated other comprehensive income (loss): |                                                            |            |            |      |       |        |           
|                                               | Beginning balance                                          |            |           |      |       | 11.9   |           
|                                               | Unrealized (loss) gain on derivative financial instruments |            |           |      |       | (28.2  | )         
|                                               |                                                            |            |            |      |       |        |           
|                                               | Ending balance                                             |            |           |      |       | (16.3  | )         
|                                               |                                                            |            |            |      |       |        |           
|Partners capital at
December 31,               |                                                            | 44,455,039 |            | $    | 991.6 |        | 32,966,384
|                                               |                                                            |            |            |      |       |        |           

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

F-7

---



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

1. PARTNERSHIP ORGANIZATION AND NATURE OF OPERATIONS

General

Enbridge Energy Partners, L.P. (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 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.

F-8

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Business Segments

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

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.

Natural Gas Transportation

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.

Gathering and Processing

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.

Marketing

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.

F-9

---

Corporate

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.

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

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.

Basis of Presentation and Principles of Consolidation

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.

Regulation

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).

Revenue Recognition

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.

F-10

---

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 or as transportation services are rendered.

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

F-11

---

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 and Cash Equivalents

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

Allowance for Doubtful Accounts

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.

Oil Shortage/Overage Balance

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.

Materials and Supplies

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

Operational Balancing Agreements and Natural Gas Imbalances

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.

F-12

---

Deferred Financing Charges

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

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 and Other Intangible Assets

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.

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. Impairment occurs when the carrying amount of an asset exceeds the fair value of the recognized intangible asset.

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

Income Taxes

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

F-13

---

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.

Derivative Financial Instruments

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.

F-14

---

Environmental Costs and Other Contingencies

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.

Comparative Amounts

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.

New Accounting Pronouncements

Accounting for Asset Retirement Obligations

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.

3. ACQUISITIONS

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

F-15

---

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

Midcoast 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.

F-16

---

The
purchase price and the allocation to assets acquired was as follows:

(dollars in millions)Purchase Price:Debt assumed

$
472.3Issuance of equity interest to the General Partner


8.2Cash paid, including transaction costs


344.4Working capital and other adjustments


50.6Total purchase price

$
875.5Allocation of purchase price:Current assets

$
51.3Property, plant and equipment


626.7Goodwill


226.0Other assets and intangibles


19.1Current liabilities


(26.4
)Other liabilities


(21.2
)Total

$
875.5


East Texas System Acquisition

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.

The
purchase price and allocation to assets acquired was as follows.

(dollars in millions)Purchase price:Class A Common units issued


91.4Cash paid, including transaction costs


138.6Total purchase price

$
230.0Allocation of purchase price:Property, plant and equipment

$
200.5Other assets, net of liabilities


14.4Goodwill


15.1Total

$
230.0


F-17

---

North Dakota System Acquisition

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.

The
purchase price and allocation to assets acquired was as follows:

Purchase price:Cash paid, including transaction costs

$
35.4Allocation of purchase price:Current assets

$
2.8Other assets


0.1Property, plant and equipment


32.8Current liabilities


(0.3
)Total

$
35.4


Pro Forma Information (Unaudited)

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

$
2,000.2Net Income


69.8


41.4Net Income per Unit


1.25


0.73


4. NET INCOME PER UNIT

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

F-18

---

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:

|                                                                     |  | Year ended December 31, |      
|-------------------------------------------------------------------- |  | ----------------------- | -----
|
|
|Net income                                                           |  | $                       | 78.1 
|Net income allocated to General Partner                              |  |                         | (1.1 
|Incentive distributions and historical cost depreciation adjustments |  |                         | (12.0
|                                                                     |  |                         |      
|                                                                     |  |                         | (13.1
|                                                                     |  |                         |      
|Net income allocable to Common Units and i-units                     |  | $                       | 65.0 
|                                                                     |  |                         |      
|Weighted average units outstanding                                   |  |                         | 36.7 
|                                                                     |  |                         |      
|Net income per unit                                                  |  | $                       | 1.76 
|                                                                     |  |                         |      

5. PROPERTY, PLANT AND EQUIPMENT

|                                                   |  |                |  | December 31, |        
|-------------------------------------------------- |  | -------------- |  | ------------ | -------
|
|
|
|Land                                               |  |               |  | $            | 10.4   
|Rights-of-way                                      |  | 3.33%  4.35%  |  |              | 192.5  
|Pipeline                                           |  | 1.52%  5.63%  |  |              | 1,576.1
|Pumping equipment, buildings and tanks             |  | 1.60%  10.41% |  |              | 520.1  
|Compressors, meters, and other operating equipment |  | 1.52%  14.29% |  |              | 114.5  
|Vehicles, office furniture and equipment           |  | 4.00%  33.33% |  |              | 62.1   
|Processing and treater plants                      |  | 4.00%          |  |              | 96.4   
|Construction in progress                           |  |               |  |              | 130.1  
|                                                   |  |                |  |              |        
|                                                   |  |                |  |              | 2,702.2
|                                                   |  |                |  |              |        
|Accumulated depreciation                           |  |                |  |              | (448.9 
|                                                   |  |                |  |              |        
|                                                   |  |                |  | $            | 2,253.3
|                                                   |  |                |  |              |        

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.

F-19

---

6. GOODWILL, INTANGIBLES AND OTHER ASSETS

December 31,2002

2001(dollars in millions)Customer Contracts

$
31.1

$
15.0Accumulated Amortization


0.7


0.0Net Intangibles


30.4


15.0Other


12.6


17.6Other 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


15.1Balance as of December 31, 2001

$
15.1Acquired during the year in conjunction with the Midcoast Acquisition


226.0Balance 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.

F-20

---

7. DEBT

|                                             |  |      |   |           |  | December 31, |        
|-------------------------------------------- |  | ---- | - | --------- |  | ------------ | -------
|
|
|
|First Mortgage Notes                         |  | 9.15 | % | 2011      |  | $            | 279.0  
|Senior Unsecured Notes                       |  | 7.34 | % | 2012-2028 |  |              | 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      |  |              |       
|                                             |  |      |   |           |  |              |        
|                                             |  |      |   |           |  | $            | 1,042.4
|Current maturities and other short-term debt |  |      |   |           |  |              | (31.0  
|                                             |  |      |   |           |  |              |        
|Long-Term debt                               |  |      |   |           |  | $            | 1,011.4
|                                             |  |      |   |           |  |              |        

First Mortgage Notes

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.

Senior Unsecured Notes

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.

|                       |  |       |   | December 31, |      
|---------------------- |  | ----- | - | ------------ | -----
|
|
|Notes maturing in 2012 |  | 7.900 | % | $            | 100.0
|Notes maturing in 2018 |  | 7.000 | % |              | 100.0
|Notes maturing in 2028 |  | 7.125 | % |              | 100.0
|Unamortized Discount   |  |       |   |              | (0.6 
|                       |  |       |   |              |      
|                       |  |       |   | $            | 299.4
|                       |  |       |   |              |      

Three-year Term Facility and 364-Day Facility

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

F-21

---

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).

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.

Interest

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).

Debt Service Reserve

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.

F-22

---

8. PARTNERS' CAPITAL

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:



F-23

---



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

F-24

---

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.

9. RELATED PARTY TRANSACTIONS

Enbridge Inc.

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.

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

F-25

---

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).

Affiliate Notes

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.

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).

Conflicts of Interest

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.

10. COMMITMENTS AND CONTINGENCIES

Environmental

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.

F-26

---

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.

Oil and Gas in Custody

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.

Commitments

Right-of-Way

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.

F-27

---

Power and Other Operating Leases

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
Leases2003

$
4.4

$
3.82004


1.5


3.32005





2.12006





2.12007





0.5Total

$
5.9

$
11.8


11. MAJOR CUSTOMERS

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

$
69.6ExxonMobil Canada Energy

$
59.7

$
48.3PDV Midwest

$
21.4

$
33.7Imperial 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.

12. FINANCIAL INSTRUMENTS

Fair Value of Financial Instruments

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

F-28

---

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

Interest rate risk:

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 ValueReference

Notional
PrincipalCoupon

Maturity Date

2002

2001Swap #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.

Commodity price risk:

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 ValueSystem

Maturity
Date

Notional MMBtu2002

2001East Texas System

2011

29.6

$
(6.1
)
$
8.5Northeast 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


F-29

---

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 ValueSystem

Maturity
Date

Notional Barrels (millions)2002

2001Northeast 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 ValueSystem

Maturity
Date

Notional Barrels (millions)2002

2001Northeast 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

$
8.4Other assets, net





8.5Accounts payable and other


(13.1
)

(5.0
)Deferred credits


(22.2
)

$
(31.8
)
$
11.9


F-30

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13. SEGMENT INFORMATION

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

F-31

---

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.

|                                              |  | As at and for the Year Ended December 31, 2002 |        
|--------------------------------------------- |  | ---------------------------------------------- | -------
|
|
|Operating revenues                            |  | $                                              | 334.3  
|Power                                         |  |                                                | 52.7   
|Cost of natural gas                           |  |                                                |       
|Operating and administrative                  |  |                                                | 104.7  
|Depreciation and amortization                 |  |                                                | 64.8   
|                                              |  |                                                |        
|Operating income                              |  |                                                | 112.1  
|Interest and other income                     |  |                                                |       
|Interest expense                              |  |                                                |       
|Minority interest                             |  |                                                |       
|                                              |  |                                                |        
|Net income                                    |  | $                                              | 112.1  
|                                              |  |                                                |        
|Total assets                                  |  | $                                              | 1,502.4
|                                              |  |                                                |        
|Goodwill                                      |  | $                                              |       
|                                              |  |                                                |        
|Capital expenditures (excluding acquisitions) |  | $                                              | 202.6  
|                                              |  |                                                |        

|                                              |  | As of or for the Year Ended December 31, 2001 |        
|--------------------------------------------- |  | --------------------------------------------- | -------
|
|
|Operating revenues                            |  | $                                             | 313.3  
|Power                                         |  |                                               | 49.9   
|Cost of natural gas                           |  |                                               |       
|Operating and administrative                  |  |                                               | 102.7  
|Depreciation and amortization                 |  |                                               | 63.0   
|                                              |  |                                               |        
|Operating Income                              |  |                                               | 97.7   
|Interest and other                            |  |                                               |       
|Interest expense                              |  |                                               |       
|Minority interest                             |  |                                               |       
|                                              |  |                                               |        
|Net income                                    |  | $                                             | 97.7   
|                                              |  |                                               |        
|Total Assets                                  |  | $                                             | 1,372.6
|                                              |  |                                               |        
|Goodwill                                      |  |                                               |       
|                                              |  |                                               |        
|Capital Expenditures (excluding acquisitions) |  | $                                             | 34.9   
|                                              |  |                                               |        

F-32

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14. QUARTERLY FINANCIAL DATA (unaudited)

(Dollars in Millions, Except Per Unit Amounts)

|                       |  | First |       | Second |   | Third |  | Fourth |       | Total
|---------------------- |  | ----- | ----- | ------ | - | ----- |  | ------ | ----- | -----
|2002 Quarters          |  |       |       |        |   |       |  |        |       |      
|Operating revenue(2)   |  | $     | 181.8 |        | $ | 223.1 |  | $      | 237.7 |      
|Operating income       |  | $     | 32.5  |        | $ | 30.4  |  | $      | 31.8  |      
|Net income             |  | $     | 17.7  |        | $ | 16.8  |  | $      | 17.6  |      
|Net income per unit(1) |  | $     | 0.43  |        | $ | 0.39  |  | $      | 0.42  |      

|                       |  | First |      | Second |   | Third |  | Fourth |      | Total
|---------------------- |  | ----- | ---- | ------ | - | ----- |  | ------ | ---- | -----
|2001 Quarters          |  |       |      |        |   |       |  |        |      |      
|Operating revenue(2)   |  | $     | 72.2 |        | $ | 81.7  |  | $      | 76.4 |      
|Operating income       |  | $     | 25.0 |        | $ | 26.5  |  | $      | 21.1 |      
|Net income             |  | $     | 10.1 |        | $ | 11.6  |  | $      | 6.6  |      
|Net income per unit(1) |  | $     | 0.27 |        | $ | 0.32  |  | $      | 0.13 |      

---

F-33

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