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

                                   -----------

                                    FORM 10-K

  [X]   ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE
        ACT OF 1934

                   FOR THE FISCAL YEAR ENDED DECEMBER 31, 2001

                                       OR

   [ ]  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: 333-59597


                                   -----------


                      ENBRIDGE ENERGY, LIMITED PARTNERSHIP
             (Exact name of Registrant as specified in its charter)


                DELAWARE                                 39-1715851
     (State or other jurisdiction of                  (I.R.S. Employer
     incorporation or organization)                 Identification No.)


                                 1100 LOUISIANA
                                   SUITE 3300
                              HOUSTON, TEXAS 77002
              (Address of principal executive offices and zip code)


                                 (713) 650-8900
              (Registrant's telephone number, including area code)

           Securities registered pursuant to Section 12(b) of the Act:

    Title of each class                Name of each exchange on which registered
            NONE                                        NONE

        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 |X| No |_|

      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. |X|

                    DOCUMENTS INCORPORATED BY REFERENCE: NONE

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<PAGE>

                                TABLE OF CONTENTS

<TABLE>
<CAPTION>
                                                                                       PAGE
<S>                                                                                     <C>

               PART I
ITEMS 1 & 2.   Business and Properties...............................................    4
ITEM 3.        Legal Proceedings.....................................................   12
ITEM 4.        Submission of Matters to a Vote of Security Holders...................   13
               PART II
ITEM 5.        Market for Registrant's Common Equity and Related Stockholder Matters.   13
ITEM 6.        Selected Financial Data...............................................   13
               Management's Discussion and Analysis of Financial Condition and
ITEM 7.        Results of Operations.................................................   14
ITEM 7A.       Quantitative and Qualitative Disclosures About Market Risk............   19
ITEM 8.        Financial Statements and Supplementary Data...........................   20
               Changes in and Disagreements with Accountants on Accounting and
ITEM 9.        Financial Disclosure..................................................   20
               PART III
ITEM 10.       Directors and Executive Officers of the Registrant....................   21
ITEM 11.       Executive Compensation................................................   22
ITEM 12.       Security Ownership of Certain Beneficial Owners and Management........   23
ITEM 13.       Certain Relationships and Related Transactions........................   23
               PART IV
ITEM 14.       Exhibits, Financial Statement Schedules and Reports on Form 8-K.......   24
SIGNATURES..........................................................................    27
INDEX TO FINANCIAL STATEMENTS, SUPPLEMENTARY INFORMATION AND FINANCIAL STATEMENT
SCHEDULES...........................................................................   F-1

</TABLE>

      THIS ANNUAL REPORT ON FORM 10-K CONTAINS FORWARD-LOOKING STATEMENTS. THESE
STATEMENTS ARE BASED ON THE PARTNERSHIP'S BELIEFS AS WELL AS ASSUMPTIONS MADE BY
AND INFORMATION CURRENTLY AVAILABLE TO THE PARTNERSHIP. WHEN USED IN THIS
DOCUMENT, THE WORDS "ANTICIPATE," "BELIEVE," "EXPECT," "ESTIMATE," "FORECAST,"
"PROJECT," AND SIMILAR EXPRESSIONS IDENTIFY FORWARD-LOOKING STATEMENTS. THESE
STATEMENTS REFLECT THE PARTNERSHIP'S CURRENT VIEWS WITH RESPECT TO FUTURE EVENTS
AND ARE SUBJECT TO VARIOUS RISKS, UNCERTAINTIES AND ASSUMPTIONS INCLUDING:

      o     THE PARTNERSHIP'S DEPENDENCE UPON ADEQUATE SUPPLIES OF AND DEMAND
            FOR WESTERN CANADIAN CRUDE OIL,

      o     THE PRICE OF CRUDE OIL AND THE WILLINGNESS OF SHIPPERS TO SHIP CRUDE
            OIL,

      o     REGULATION OF THE PARTNERSHIP'S TARIFFS BY THE FEDERAL ENERGY
            REGULATORY COMMISSION AND THE POSSIBILITY OF UNFAVORABLE OUTCOMES OF
            FUTURE TARIFF PROCEEDINGS, AND

      o     THE EFFECTS OF COMPETITION, IN PARTICULAR, BY OTHER PIPELINE
            SYSTEMS.

      IF ONE OR MORE OF THESE RISKS OR UNCERTAINTIES MATERIALIZE, OR IF THE
UNDERLYING ASSUMPTIONS PROVE INCORRECT, ACTUAL RESULTS MAY VARY MATERIALLY FROM
THOSE DESCRIBED IN THIS FORM 10-K. EXCEPT AS REQUIRED BY APPLICABLE SECURITIES
LAWS, THE PARTNERSHIP DOES NOT INTEND TO UPDATE THESE FORWARD-LOOKING
STATEMENTS. FOR ADDITIONAL DISCUSSION OF SUCH RISKS, UNCERTAINTIES AND
ASSUMPTIONS, SEE "ITEMS 1 & 2. BUSINESS AND PROPERTIES--RISK FACTORS" INCLUDED
ELSEWHERE IN THIS FORM 10-K.




                                       2
<PAGE>

                                    GLOSSARY

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

<TABLE>
<S>                          <C>
Act........................  Pipeline Safety Act
ADOE.......................  Alberta Department of Energy
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
EBITDA.....................  Earnings before Interest, Taxes, Depreciation, and
                             Amortization
Enbridge...................  Enbridge Inc.
Enbridge Mustang...........  Enbridge Holdings (Mustang) Inc.
Enbridge Partnership.......  Enbridge Energy Partners, L.P.
Enbridge System............  Canadian portion of the System
Enbridge Pipelines.........  Enbridge Pipelines Inc.
Enbridge U.S...............  Enbridge (U.S.) Inc.
EPA........................  Environmental Protection Agency
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.
ICA........................  Interstate Commerce Act
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
Mobil......................  Mobil Pipe Line Company
Mustang....................  Mustang Pipe Line Partners
NEB........................  National Energy Board
NGL or NGLs................  Natural gas liquids
OPS........................  Office of Pipeline Safety
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 Agreements.....  Amended and Restated Agreements of Limited Partnership of
                             the Enbridge Partnership and Operating Partnership
Partnership................  Enbridge Energy, Limited Partnership
PPIFG-1....................  Producer Price Index for Finished Goods minus 1%
RCRA.......................  Resource Conservation and Recovery Act
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 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.

</TABLE>


                                       3
<PAGE>

                                     PART I

ITEMS 1 & 2. BUSINESS AND PROPERTIES

OVERVIEW

      Enbridge Energy, Limited Partnership is a 98.9899% owned operating
subsidiary partnership of Enbridge Energy Partners, L.P., a publicly traded
Delaware limited partnership. Both partnerships are Delaware limited
partnerships.

      The Partnership was formed in 1991 to acquire, own and operate the
Lakehead System, which was the regulated crude oil and NGL pipeline business of
the General Partner, a wholly-owned subsidiary of Enbridge Pipelines. Enbridge
Pipelines is a Canadian company owned by Enbridge of Calgary, Alberta, Canada.
The General Partner owns a 1.0101% general partner interest in the Partnership.
The remaining 98.9899% limited partner interest in the Partnership is owned by
the Enbridge Partnership.

      The Partnership and Enbridge Pipelines transport crude oil and other
liquid hydrocarbons for others through the world's longest liquid petroleum
pipeline system. In this document, the combined operations of the Lakehead
System and the Enbridge System are referred to as the System. The System is the
primary transporter of crude oil from western Canada to the United States and is
the only pipeline that transports crude oil from western Canada to the province
of Ontario, Canada. The System serves all the major refining centers in the
Great Lakes region of the United States, as well as Ontario and, through
interconnects, the Patoka/Wood River pipeline hub and refining center in
southern Illinois.

      The System extends from Edmonton, Alberta, across the Canadian prairies to
the U.S. border near Neche, North Dakota. From Neche the System continues to
Superior, Wisconsin where it splits into two branches, with one branch traveling
through the upper Great Lakes region and the other through the lower Great Lakes
region of the United States. Both branches reenter Canada near Marysville,
Michigan. From Marysville the System continues to Toronto, Ontario with lateral
lines to Nanticoke, Ontario and the Buffalo, New York area. Another part of the
Enbridge System, Line 9, originates in Montreal, Quebec, and continues west to
serve Sarnia, Ontario refineries. The System is approximately 3,100 miles long,
of which approximately 1,880 miles are in the United States.

      Shipments tendered to the System primarily originate in oil fields in the
western Canadian provinces of Alberta, Saskatchewan, Manitoba and British
Columbia and in the Northwest Territories of Canada. Shipments reach the System
through facilities owned and operated by third parties or affiliates of Enbridge
Pipelines. Deliveries from the System are currently made in the prairie
provinces of Canada and, through the Lakehead System, to the Great Lakes and
Midwest regions of the United States and to the province of Ontario. These
deliveries are made principally to refineries either directly or through
connecting pipelines of other companies.

      All scheduling of shipments (including routes and storage) is handled by
Enbridge Pipelines in coordination with the Partnership. The Lakehead System
includes 15 connections to pipelines and refineries at various locations in the
United States, including the refining areas in and around Chicago, Illinois;
Minneapolis-St. Paul, Minnesota; Detroit, Michigan; Toledo, Ohio; Buffalo and
Patoka/Wood River. The Lakehead System has three main terminals at Clearbrook,
Minnesota, Superior and Griffith, Indiana. The terminals are used to gather
crude oil prior to injection into the Lakehead System and to provide tankage in
order to allow for more flexible scheduling of oil movements.

PROPERTIES

      The Lakehead System consists of approximately 3,300 miles of pipe with
diameters ranging from 12 inches to 48 inches, 63 pump station locations with a
total of approximately 667,000 installed horsepower and 58 crude oil storage
tanks with an aggregate working capacity of approximately 10 million barrels.
The Lakehead System requires approximately 14 million barrels of oil in the
pipeline for operation, all of which is owned by the shippers. The Lakehead
System regularly transports up to 43 different types of liquid hydrocarbons
including light, medium and heavy crude oil (including bitumen), condensate,
synthetic crudes and NGL.

      The Lakehead System is comprised of a number of separate segments as
follows:

      o     Canadian border to Clearbrook segment including portions of four
            pipelines consisting of 18-, 20-, 26-, and 34-inch diameter pipe,
            respectively, and a fifth line consisting of 36- and 48-inch
            diameter pipe with a total annual capacity of 1,727,000 bpd;

      o     Clearbrook to Superior segment including portions of three pipelines
            consisting of 18-, 26-, and 34-inch diameter pipe, respectively,
            with a total annual capacity of 1,395,000 bpd. This segment includes
            approximately 80 miles of 48-inch pipeline looping that increases
            the capacity of this segment;



                                       4
<PAGE>

      o     Superior to Marysville  segment  consisting of 30-inch diameter pipe
            with a total annual capacity of 491,000 bpd;

      o     Superior to Chicago area segment including two pipelines of 24- and
            34-inch diameter pipe with a total annual capacity of 889,000 bpd;

      o     Chicago area to Marysville segment consisting of a 30-inch diameter
            pipe with a total annual capacity of 333,000 bpd; and

      o     Canadian border to Buffalo segment consisting of 12- and 20-inch
            diameter pipe with a total annual capacity of 74,000 bpd.

      Estimated annual capacities noted above take into account receipt and
delivery patterns and ongoing pipeline maintenance, and reflect achievable
pipeline capacity over long periods of time.

      The Partnership believes that the Lakehead System has been constructed and
is maintained substantially in accordance with applicable federal, state and
local laws and regulations, standards prescribed by the American Petroleum
Institute, American Society of Mechanical Engineers or other technical
associations and accepted industry practice. The Partnership attempts to control
external corrosion of the pipeline through the use of pipe coatings and cathodic
protection systems and monitors the integrity of the Lakehead System through a
program of periodic internal inspections using electronic instruments. At
intervals not exceeding 3 weeks, but at least 26 times each calendar year, the
entire pipeline right of way is inspected from the air. In addition, trained and
skilled operators use computerized monitoring systems to identify pressure drops
or abnormal conditions that might indicate potential disruptions in flow, and
operate remote-controlled valves and pumps that allow the Lakehead System to be
shut down quickly if necessary.

TITLE TO PROPERTIES

      The Partnership conducts business and owns properties located in seven
states: Wisconsin, Minnesota, Illinois, Indiana, Michigan, Ohio and New York. In
general, the Lakehead System is located on land owned by others and is 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 the
Lakehead System 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 SEP II. The affiliate is continuing to sell these parcels to
third parties while retaining an easement for the benefit of the Partnership.
See "Item 13. Certain Relationships and Related Transactions."

      Substantially all of the Lakehead System assets are subject to a first
mortgage securing indebtedness of the Partnership.

RISK FACTORS

      An inadequate supply of western Canadian crude oil could adversely affect
the Partnership's business. The supply of western Canadian crude oil was
negatively impacted by low world oil prices in 1998 and early 1999. Since oil
prices stabilized in late 1999, there has been a shift in focus to natural gas
drilling rather than oil, due to the favorable natural gas price environment.
The Partnership's ability to increase deliveries and to expand the Lakehead
System in the future also depends upon increased supplies of western Canadian
crude oil. For a discussion of the forecast for the future supply of crude oil
produced in western Canada, see "--Supply of and Demand for Western Canadian
Crude Oil."

      Demand for western Canadian crude oil and NGL in the geographic areas
served by the Lakehead System is affected by the delivery of other crude oil and
refined petroleum products into the same areas. Existing pipeline capacity for
the delivery of crude oil to the U.S. upper Midwest, the primary destination
market served by the Lakehead System, exceeds current refining capacity. The
Partnership believes that the System has several advantages over other
transporters of crude oil with which it competes and the System is among the
lowest cost transporters of crude oil and NGL in North America based on costs
per barrel mile transported. See "--Competition."

      The Partnership is subject to the risk that changes may occur in existing
economic conditions, fuel conservation measures, alternative fuel requirements,
governmental regulation or technological advances in fuel economy and energy
generation devices. Any of these factors could reduce the demand for crude oil
and other liquid hydrocarbons in the areas in which deliveries are made by the



                                       5
<PAGE>

Lakehead System. In addition, reduced throughput on the System could result from
testing, line repair, reduced operating pressures, reduced crude oil supply,
regulatory restrictions on System utilization or other causes.

      The operations of the Partnership are subject to federal and state laws
and regulations relating to environmental protection and operational safety;
compliance with these regulations may increase the Partnership's costs and
reduce its revenues. Although the Partnership believes that the operations of
its systems are in substantial compliance with applicable environmental and
safety regulations, risks of substantial costs and liabilities are inherent in
pipeline operations, and such costs and liabilities could be incurred. See
"--Environmental and Safety Regulation."

      The Partnership periodically files tariff rate increases and decreases
with the FERC. A tariff agreement between the Partnership and customer
representatives sets forth parameters governing the tariff changes associated
with SEP II, Terrace, and related expansion projects on the Lakehead System.
Notwithstanding this agreement, any shipper who is not a party to the agreement
could challenge any existing or future rate filings. Any challenge, if
successful, could have a material adverse effect on the Partnership. For a
discussion of FERC regulation, Partnership tariff rates and the tariff
agreement, see "--Regulation" and "--Tariffs."

      The Partnership's General Partner is affiliated to both Enbridge and the
Partnership, which could result in conflicts of interest between the Partnership
and Enbridge from time to time. The Partnership Agreements limit the fiduciary
duties of the General Partner to the Partnership, and the unit holders have
effectively consented to various actions and conflicts that might otherwise be
deemed a breach of fiduciary or other duties under law. Conflicts could arise
regarding time and amount of capital expenditures, borrowing, issuance or
purchase of units, and allocation of resources. As a result of the reversal of
the flow of Line 9 in 1999, Enbridge Pipelines competes with the Partnership to
supply crude oil to the Ontario market.

REGULATION

FERC REGULATION

      The Partnership's interstate common carrier pipeline operations are
subject to rate regulation by the FERC under the version of the ICA applicable
to oil pipelines. The ICA requires that petroleum products and crude oil common
carrier pipeline rates be just, reasonable and non-discriminatory. The ICA
permits challenges to new, changed and existing rates through either a "protest"
or "complaint." At the FERC, a protest normally applies only to a proposed
change in a pipeline's rates or practices and subjects the pipeline to a
forward-looking investigation and possible refund obligation. The FERC can also
choose to suspend the proposed change for up to seven months from the proposed
date of the change. A complaint, by comparison, typically applies to an existing
rate or practice and subjects the pipeline, in some circumstances, to possible
two-year retroactive liability for past rates or practices found to be unlawful.

      The FERC utilizes a simplified ratemaking methodology for oil pipelines
that prescribes an indexing methodology for setting rate ceilings. As described
in FERC Orders No. 561 and No. 561-A, the index used is the PPIFG-1. Rate
ceiling levels are increased or decreased each July 1. The PPIFG-1 index for use
beginning on July 1, 2001, was approximately 2.8%. Inflationary rate changes
prescribed under the FERC's indexing methodology may be different than changes
in the Partnership's costs. Indexed rates are subject both to protests and to
complaints, but in either case the FERC's existing regulations specify that the
party challenging a rate must show reasonable grounds for asserting that the
amount of any rate increase resulting from application of the index is so
substantially in excess of the pipeline's increase in costs as to be unjust and
unreasonable (or alternatively, that the amount of any rate decrease is so
substantially less than the actual cost decrease incurred by the pipeline that
the rate is unjust and unreasonable).

      The FERC has stated that, as a general rule, crude oil pipelines must
utilize the indexing methodology to change rates. However, the FERC has retained
cost-based ratemaking, market-based rates and settlements as alternatives to the
indexing approach. A pipeline can follow a cost-based approach when it can
demonstrate that there is a substantial divergence between the actual costs
experienced by the carrier and the rates resulting from application of the
index. Under FERC's cost-based methodology, crude oil pipeline rates are
permitted to generate operating revenues, based on projected volumes, not
greater than the total of operating expenses, depreciation and amortization,
federal and state income taxes and an overall allowed rate of return on the
pipeline's rate base. In addition, a pipeline can charge market-based rates if
it first establishes that it lacks significant market power in a particular
relevant market, and a pipeline can establish rates pursuant to a settlement if
agreed upon by all current shippers. Initial rates for new services can be
established through a cost-based filing or through an uncontested agreement
between the pipeline and at least one shipper not affiliated with the pipeline.

OTHER REGULATION

      The governments of the United States and Canada have, by treaty, agreed to
ensure nondiscriminatory treatment for the passage of oil and gas through the
pipelines of one country across the territory of the other. Individual border
crossing points require U.S.



                                       6

<PAGE>

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

RATE CASES

      The Partnership had several rate cases pending before the FERC during the
period from 1992 to 1996. The primary issue was the applicability of the FERC's
Opinion 154-B/C trended original cost methodology. In 1995 and 1996, the FERC
issued decisions on the Partnership's 1992 tariff rate increase that determined
the Partnership was entitled to use the FERC's Opinion No. 154-B/C rate
methodology, although it was not entitled to recover in its cost of service a
tax allowance with respect to income attributable to limited partners who are
not corporations or other similar entities.

      In October 1996, the FERC approved the Settlement Agreement between the
Partnership, CAPP, and ADOE on all then-outstanding contested tariff rates. The
Settlement Agreement provided for a tariff rate reduction of approximately 6%
and total rate refunds and interest of $120.0 million through the effective date
of October 1, 1996, with interest accruing thereafter on the unpaid balance.
Effective November 22, 1999, the $120.0 million refund and related interest were
fully repaid.

      The Settlement Agreement also provided for the terms of an incremental
tariff rate surcharge for a period of 15 years to recover the cost of, and allow
a return on, the Partnership's investment in SEP II. The rate of return on this
investment is based, in part, on the utilization level of the additional
capacity constructed. As specified in the Settlement Agreement, higher
utilization results in a greater rate of return, subject to a minimum and
maximum rate of return of 7.5% and 15.0%, respectively. The tariff rate
surcharge is recomputed on a cost of service basis and filed with FERC each
year. The Settlement Agreement further provided that the agreed underlying
tariff rates would be subject to indexing as prescribed by FERC regulation and
that CAPP and ADOE would not challenge any rates within the indexed ceiling for
a period of five years, which expired in October 2001. See "Item 7. Management's
Discussion and Analysis of Financial Condition and Results of Operations,--Other
Matters,--Regulatory Matters."

TARIFF AGREEMENT

      In 1998, the Partnership filed the Tariff Agreement with the FERC to
facilitate the filing of tariff rate surcharges in late 1998 and early 1999.
This filing consolidated the 1996 Settlement Agreement for SEP II and other
significant agreements with customers concerning Terrace and the transportation
of heavy crude oil. The FERC found the Tariff Agreement a reasonable compromise
and approved it on the grounds that it is fair, reasonable, and in the public
interest.

      With respect to Terrace, the Tariff Agreement included terms governing a
tariff surcharge associated with the project. A fixed toll increase of Cdn.
$0.05 per barrel for the movement of light crude oil from Edmonton to the
Chicago area was allocated approximately Cdn. $0.02 ($0.013 U.S.) to the
Partnership and Cdn. $0.03 to Enbridge. Effective April 1, 2001, Enbridge and
the Partnership agreed to reallocate the Cdn. $0.05 per barrel Terrace toll
surcharge, Cdn. $0.04 ($0.026 U.S.) to the Partnership and Cdn. $0.01 to
Enbridge. This reallocation is permitted under the terms of the Agreement and
was done in an effort to rebalance the project economics between the parties as
a result of volume shortfalls, for which the Partnership is completely at risk.
This toll will be in effect until April 1, 2004, when, absent any agreement from
Enbridge stating otherwise, the toll allocation to the Partnership will change
to Cdn. $0.01 ($0.007 U.S.) per barrel. The Terrace incremental toll is also
subject to increase or decrease based on changes in other defined circumstances.
The portion of the agreement associated with Terrace also established in-service
and notice dates for future phases of the expansion program. CAPP provided
notice to construct Phase III of Terrace in June 2001. See "Item 7. Management's
Discussion and Analysis of Financial Condition and Results of Operations,--Other
Matters,--Future Prospects,--Terrace Expansion Program."

OTHER PIPELINE RATE CASES

      On January 13, 1999, the FERC issued Opinion No. 435 in a case involving
SFPP, which addressed various issues of interest to FERC-regulated publicly
traded partnerships and other oil pipelines. These included application of
FERC's Opinion No. 154-B/C rate methodology and income tax allowances for
publicly traded partnerships. The FERC issued rehearing orders on May 17, 2000
(Opinion No. 435-A) and September 13, 2001 (Opinion No. 435-B) that largely
reconfirmed the rulings in Opinion No. 435. These orders remain subject to
further rehearing on certain issues, as well as judical review. If the SFPP
opinion is not changed on further rehearing by FERC or on review by a court of
appeals, and if it were applied to the Partnership in some future rate
proceedings, the impact to the Partnership, positive or negative, would be
dependent upon the specific application of the rulings in that opinion to the
Partnership.



                                       7
<PAGE>

      Many of the ratemaking issues contested in the Partnership's rate cases,
in particular the FERC's oil pipeline ratemaking methodology, have not been
reviewed by a federal appellate court. Judicial review, whether or not in a case
directly involving the Partnership, could ultimately result in the
implementation of alternative ratemaking methodologies that could have a
material adverse effect on the Partnership.

TARIFFS

      Under published tariffs for transportation on the Lakehead System, the
rates for light crude oil from key receipt locations to principal delivery
points at January 1, 2002 (including the tariff surcharges related to SEP II and
Terrace) are set forth below.


                                                     PUBLISHED TARIFF PER BARREL
                                                     ---------------------------
Canadian border near Neche to Clearbrook ............        $    0.171
Canadian border near Neche to Superior ..............        $    0.334
Canadian border near Neche to Chicago area ..........        $    0.683
Canadian border near Neche to Marysville area .......        $    0.816
Canadian border near Neche to Buffalo area ..........        $    0.836
Chicago to the international border near Marysville .        $    0.302


      The rates at January 1, 2002 for medium and heavy crude oils are higher
and those for NGL 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 FERC's indexing methodology and the Tariff Agreement and will file an
updated SEP II surcharge to be effective April 1, 2002. This filing will include
any differences between the SEP II surcharge filed in 2001 and actual results
for the year, as well as an estimate for 2002. Overall, the Partnership believes
that the surcharge will remain relatively consistent with 2001 levels.

DELIVERIES FROM THE LAKEHEAD SYSTEM

      Deliveries from the Lakehead System are made in the Great Lakes and
Midwest regions of the United States and in Ontario, principally to refineries,
either directly or through connecting pipelines of other companies. Major
refining centers within these regions are located near Sarnia, Nanticoke,
Toronto, Minneapolis-St. Paul, Superior, Chicago, the Patoka/Wood River area,
Detroit, Toledo, and Buffalo areas. Crude oil and NGL transported by the
Lakehead System are feedstock for refineries and petrochemical plants.

      The U.S. government segregates the United States into five PADDs for
purposes of its strategic planning to ensure crude oil supply to key refining
areas in the event of a national emergency. The oil industry utilizes these
districts in reporting statistics regarding oil supply and demand. The Lakehead
System services the northern tier of PADD 2. U.S. governmental publications
project that crude oil demand in this area will remain relatively constant over
the next 10 years. In addition, these publications project the total supply of
crude oil, from producing areas in the U.S. southwest, Rocky Mountains and
Midwest that currently serve the entire PADD 2 market, to decline in the near
term as reserves are depleted, resulting in a need for additional supplies of
crude oil to replace the continuing demand. As a result of these factors, the
Partnership believes that the Lakehead System will be able to exceed its 2001
level of deliveries into PADD 2 during the next 10 years.



                                       8
<PAGE>


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,
2001.


                                                       DELIVERIES
                                                       ----------

                                            2001    2000    1999    1998    1997
                                           -----   -----   -----   -----   -----
                                                    (THOUSANDS OF BPD)
UNITED STATES
    Light crude oil ....................     292     321     299     338     282
    Medium and heavy crude oil .........     663     630     575     627     652
    NGL ................................       5      25      24      27      26
                                           -----   -----   -----   -----   -----

    Total United States ................     960     976     898     992     960
                                           -----   -----   -----   -----   -----

ONTARIO
    Light crude oil ....................     174     174     282     366     355
    Medium and heavy crude oil .........      77      85      87      97      98
    NGL ................................     104     103     102     107      99
                                           -----   -----   -----   -----   -----

    Total Ontario ......................     355     362     471     570     552
                                           -----   -----   -----   -----   -----

TOTAL DELIVERIES .......................   1,315   1,338   1,369   1,562   1,512
                                           =====   =====   =====   =====   =====


BARREL MILES (billions per year) .......     333     341     350     391     389
                                           =====   =====   =====   =====   =====


SUPPLY OF AND DEMAND FOR WESTERN CANADIAN CRUDE OIL

SUPPLY

      Substantially all of the liquid petroleum delivered through the Lakehead
System originates in oilfields in western Canada. The Lakehead System also
receives:

      o     U.S. and Canadian production at Clearbrook through a connection with
            a pipeline owned by a subsidiary of the Enbridge Partnership

      o     U.S. production at Lewiston, Michigan; and

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

      Changes in supply from western Canada directly affect movements through
the Enbridge System and, therefore, the supply available for transportation
through the Lakehead System. Enbridge regularly prepares forecasts of western
Canadian crude oil, which take into account deliveries on the Lakehead System.
This is a long-term outlook, which incorporates updated supply projections from
producers of both conventional and non-conventional sources of crude oil. The
forecast includes supply from existing operations, proposed expansions of
existing operations and production from selected projects proposed for
development.

      The forecast developed by Enbridge in early 2002 projects that the supply
of western Canadian crude oil will be approximately 2.1 million bpd in 2002 and
approximately 2.2 million bpd in 2003. This forecast projects the supply of
crude oil to rise to approximately 2.3 million bpd in 2004 and to approximately
2.8 million bpd by 2011. The forecast was made subject to numerous uncertainties
and assumptions, including a crude oil price ranging from $23-$26 per bbl from
2002 to 2011. On February 20, 2002, the benchmark West Texas Intermediate crude
oil price closed at $20.29 per bbl.

      The Partnership believes that the outlook for increased crude oil
production in western Canada continues to be positive, as evidenced by the
Enbridge forecast and CAPP's request to proceed with Terrace Phase III. The
timing of growth in the supply of western Canadian crude oil, however, will
depend upon the level of crude oil prices, oil drilling activity and the timing
of completion of projects to produce heavy and synthetic oil from the Alberta
oil sands. The Partnership anticipates that 2002 deliveries on the Lakehead
System will average approximately 1.33 million to 1.40 million bpd based on the
most recent survey of shippers.

DEMAND

      The Lakehead System services the northern tier of PADD 2. The Partnership
believes that modestly increasing crude oil demand and declining inland U.S.
domestic production will contribute to an increasing need to import crude oil
into PADD 2. The Partnership also



                                       9
<PAGE>

believes that PADD 2 will continue to provide an excellent market for western
Canadian producers as returns to crude oil producers are expected to be
attractive. Moreover, the Partnership believes that PADD 2 will remain the most
attractive market for western Canadian supply since it is currently the largest
North American processor of western Canadian heavy crude oil and has the most
refinery processing capacity available to Canadian producers.

      Although western Canadian heavy crude oil producers experience competition
from Venezuelan and Mexican heavy crude oil in PADD 2, western Canadian heavy
crude oil is expected to remain the largest heavy supply source for the region.
The Partnership believes that Latin American heavy crude oil will continue to
provide modest amounts of supply to the PADD 2 region. The Partnership expects
that producers of Latin American heavy crude oil will focus on the PADD 3 and
Asian markets, where processing arrangements with refineries are available.

      The most recent Enbridge forecast projects demand for exports from western
Canada to the United States to increase to approximately 1.67 million bpd in
2006 and to approximately 2.0 million by 2011. The 2011 forecast exports to the
U.S. market is 700,000 bpd higher than expected 2002 exports. PADD 2 is expected
to receive approximately 1.30 million bpd in 2006, and 1.54 million bpd in 2011.

      Demand for crude oil and NGL in the Province of Ontario is expected to
remain at approximately 580,000 bpd over the next 10 years. Since 1999, the
Partnership's deliveries to the Province of Ontario have been impacted by the
reversal of Line 9 from Montreal to Sarnia. The Partnership's deliveries to the
Province of Ontario are forecasted to be approximately 400,000 bpd throughout
the forecast period.

CUSTOMERS

      The Lakehead System operates under month-to-month transportation
arrangements with its shippers. During 2001, 39 shippers tendered crude oil and
NGL for delivery through the Lakehead System. Customers included integrated oil
companies, major independent oil producers, refiners and marketers. Shipments by
the top ten shippers during 2001 accounted for approximately 87% of total
revenues during that period. Revenue from BP Canada Energy Company and
ExxonMobil Canada Energy accounted for approximately 24% and 20%, respectively,
of total operating revenue generated by the Lakehead System during 2001. The
remaining shippers each accounted for less than 10% of total revenues. See Note
7 to the Partnership's Financial Statements.

CAPITAL EXPENDITURES

      In 2001, the Partnership made capital expenditures of $34.0 million, of
which $9.2 million was for pipeline system enhancements, $8.5 million for
core maintenance activities and $16.3 million for Terrace. See "Item 7.
Management's Discussion and Analysis of Financial Condition and Results of
Operations."

TAXATION

      For U.S. federal and state income tax purposes, the Enbridge
Partnership and the Partnership are not taxable entities. 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.

COMPETITION

      Because pipelines are the lowest cost method for intermediate and long
haul movement of crude oil over land, the System's most significant existing
competitors for the transportation of western Canadian crude oil are other
pipelines. In 2001, the Enbridge System transported approximately 65% of total
western Canadian crude oil production. The remainder of 2001 western Canadian
crude oil production was refined in Alberta or Saskatchewan 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% of design capacity is shared by five other
pipelines transporting crude oil to British Columbia, Washington, Montana, and
other states in the U.S. Northwest.

      Competition among common carrier pipelines is based primarily on
transportation charges, access to producing areas and proximity to end users.
The Partnership believes that high capital requirements, environmental
considerations and the difficulty in acquiring rights of way and related permits
make it difficult for a competing pipeline system comparable in size and scope
to the System to be built in the foreseeable future.



                                       10
<PAGE>

      Express Pipeline owns and operates a 170,000 bpd capacity pipeline that
carries western Canadian crude oil to the U.S. Rocky Mountain region, where it
connects to a 125,000 bpd capacity pipeline system. This connecting pipeline
serves the Patoka/Wood River market area. Express Pipeline began service in
early 1997. The System, however, offers lower tolls into Chicago and Patoka than
Express Pipeline and competitive tolls into Wood River. In addition, the System
does not require shipper volume commitments as currently required by Express
Pipeline.

      The System encounters competition in serving shippers to the extent that
shippers have alternative opportunities for transporting liquid hydrocarbons
from their sources to customers. In selecting the destination for their supplies
of crude oil, sellers generally desire to use the alternative that results in
the highest return to them. Generally, it is expected that sellers will receive
the highest return from markets served by the System, but alternate markets may,
for periods of time, offer equal or better returns for the seller. Such markets
could potentially include the U.S. Rocky Mountain region for sweet crude oil and
the state of Washington market for light sour crude oil.

      In the United States, the Lakehead System encounters competition from
other crude oil and refined product pipelines and other modes of transportation
delivering crude oil and refined products to the refining centers of
Minneapolis-St. Paul, Chicago, Detroit and Toledo and the refinery market and
pipeline hub located in the Patoka/Wood River area. The Lakehead System
transports approximately 54% of all crude oil deliveries into the Chicago area,
approximately 86% of all crude oil deliveries into the Minneapolis-St. Paul area
and approximately 62% of all deliveries of crude oil to Ontario.

ENVIRONMENTAL AND SAFETY REGULATION

GENERAL

      The operations of the Partnership are subject to federal, state and local
laws and regulations relating to protection of the environment and safety.
Although the Partnership believes that the operations of the Lakehead System are
in substantial compliance with applicable environmental and safety laws and
regulations, the risk of substantial liabilities is inherent in pipeline
operations, and the Partnership could incur substantial liabilities. To the
extent that the Partnership is unable to recover environmental costs in its
rates (if not recovered through insurance), the Partnership could be subject to
material costs.

      In general, the Partnership expects to incur future ongoing expenditures
to comply with industry and regulatory environment and safety standards. The
Partnership does not expect that such expenditures, to the extent they can be
estimated, will have a material adverse effect on the Partnership.

AIR

      The operations of the Partnership are subject to the federal CAA and
comparable state statutes. The main impact of these regulations on the
Partnership is the requirement to obtain and maintain permit authorizations to
operate facilities that emit air contaminants to the atmosphere. These
authorizations generally impose emission limits and controls as well as
establish monitoring and reporting procedures to demonstrate compliance. Federal
and State laws provide varying civil and criminal penalties and liabilities in
the case of violations of permit authorizations or in the case of failure to
obtain such authorizations. The Partnership is unaware of any significant
violations of air quality requirements and expenses of routine compliance with
these regulations are not expected to have a material adverse impact on the
Partnership.

WATER

      The federal CWA, as amended, imposes strict controls on the discharge of
any pollutant, including oil, into the waters of the United States. The CWA
provides penalties for any such discharge, imposes liability for clean-up costs
and natural resource damage, and allows for third party lawsuits. As required by
the CWA, the Partnership has developed Facility Response Plans, which are
designed to prevent contamination of waters in the event of a petroleum
overflow, rupture or leak, and has submitted these plans to, and received the
approval of, the OPS of the U.S. DOT. The federal Safe Drinking Water Act of
1974, as amended, further regulates discharges into groundwater. State laws also
provide varying civil and criminal penalties and liabilities in the case of a
release of pollutants into surface water or groundwater. Expenses of routine
compliance with these and other similar regulations are not expected to have a
material adverse impact on the Partnership.

REMEDIATION MATTERS

      Contamination resulting from spills of crude oil and petroleum products is
not unusual within the petroleum pipeline industry. Historic spills along the
Lakehead System as a result of past operations may have resulted in soil or
groundwater contamination. The



                                       11

<PAGE>

Partnership is continuing to address known sites through monitoring and
remediation programs. Currently, expenses relating to such remediation programs
are not expected to have a material adverse impact on the Partnership.

SUPERFUND

      The CERCLA, as amended, also known as "Superfund," and comparable state
laws impose liability, without regard to fault or the legality of the original
act, on certain classes of persons that contribute to the release of a
"hazardous substance" into the environment. In the course of its ordinary
operations, the Partnership's systems generate wastes, some of which fall within
the federal and state statutory definitions of a "hazardous substance" and some
of which were historically disposed of at sites that may require cleanup under
Superfund and related state statutes. The Partnership is unaware of any such
obligations at this time.

WASTE

      The Partnership generates hazardous and non-hazardous solid wastes that
are subject to requirements of the federal RCRA and comparable state statutes.
The Partnership believes that operations of its systems are in substantial
compliance with such statutes in all states in which it operates.

PIPELINE SAFETY LEGISLATION AND REGULATION

      The operations of the Lakehead System are subject to construction,
operating and safety regulation under the Act as applied by the OPS. Various
other federal, state and local legislative and regulatory requirements also
affect construction, maintenance and operation practices. The Act has been
amended periodically requiring OPS to consider environmental impacts and
cost-benefit analysis, in addition to its traditional public safety
considerations, when developing pipeline safety regulations. Among the
amendments, OPS was mandated to establish pipeline operator qualification rules
that were issued in 1999 and which came into effect during 2001. Other
requirements include mandating OPS to establish a national pipeline mapping and
records system, evaluating the feasibility of requiring additional valves and/or
remotely operated valves and completing the identification of areas "unusually
environmentally sensitive" to leaks from liquid pipelines. In December 2000, the
OPS issued final rules defining "unusually environmentally sensitive areas" and
is in the process of identifying and mapping these distinct areas throughout the
U.S. As well, in December 2000, OPS issued final rules for "Pipeline Integrity
Management in High Consequence Areas". In December 2001, OPS issued final rules
for more prescriptive corrosion protection standards, and for more stringent
spill reporting requirements for liquid pipelines. These more stringent
requirements were generally consistent with existing industry codes and
standards. The Partnership has submitted pipeline maps and descriptive detail to
OPS as part of its voluntary national mapping and records system and is in the
process of enhancing its integrity management program for liquid pipelines to
meet the new regulatory requirements. The recently issued rules or proposed
rules are comprehensive, but are not expected to have a material adverse
financial effect on the Partnership.

      In the aftermath of two significant pipeline incidents in Washington and
New Mexico during 1999 and 2000, the U.S. Congress has proposed several bills to
significantly amend the Act. Proposals include many initiatives already underway
by OPS and discussed above. Additional proposals of significance include
potential certification of pipeline control operators or qualification programs,
more prescriptive integrity management programs, broader public communications,
increased involvement of states, strengthened inspection and enforcement
authority for OPS, and broader research and development programs. The
Partnership expects final legislation to be considered in the first half of
2002. As this legislative initiative is still evolving, the financial impact of
additional new legislative requirements cannot be determined at this time.

EMPLOYEES

      Neither the General Partner nor the Partnership has any employees. The
General Partner is responsible for the management and operation of the
Partnership, and to fulfill these obligations, it has entered into agreements
with Enbridge and several of its subsidiaries to provide the necessary services.
The Partnership reimburses service providers for expenses incurred in performing
these services at cost.

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.

      In September 2001, the Partnership settled its third party claim for costs
incurred in connection with a release of crude oil in September 1998 and an NGL
release in October 1998, near Plummer, Minnesota. The Partnership recovered an
amount that adequately



                                       12
<PAGE>

reimbursed it for costs incurred to remediate the releases. There are no further
pending legal or regulatory enforcement actions in connection with these
releases.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

No matters were submitted to a vote of security holders during 2001.

                                     PART II

ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS

None.

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 financial statements of the Partnership and notes thereto,
and should be read in conjunction with those audited financial statements.

<TABLE>
<CAPTION>
                                                                                      YEAR ENDED DECEMBER 31,
                                                                  --------------------------------------------------------------
                                                                     2001         2000         1999         1998         1997
                                                                  ----------   ----------   ----------   ----------   ----------
                                                                             (DOLLARS IN MILLIONS, EXCEPT PER UNIT AMOUNTS)

<S>                                                               <C>          <C>          <C>          <C>          <C>
INCOME STATEMENT DATA:
    Operating revenue ........................................    $    304.0   $    305.6   $    312.6   $    287.7   $    282.1
    Operating expenses .......................................         210.8        189.1        182.3        182.3        174.0

    Operating income .........................................          93.2        116.5        130.3        105.4        108.1
    Interest and other income ................................           2.8          4.8          3.4          5.9          9.7
    Interest expense .........................................         (58.0)       (60.4)       (54.1)       (21.9)       (38.6)
                                                                  ----------   ----------   ----------   ----------   ----------
    Net income ...............................................    $     38.0   $     60.9   $     79.6   $     89.4   $     79.2
                                                                  ==========   ==========   ==========   ==========   ==========


FINANCIAL POSITION DATA (AT YEAR END):
    Property, plant and equipment, net .......................    $  1,253.9   $  1,281.9   $  1,321.3   $  1,296.2   $    850.3
    Total assets .............................................    $  1,333.2   $  1,376.7   $  1,413.5   $  1,414.2   $  1,063.1
    Long-term debt ...........................................    $    715.4   $    799.3   $    784.5   $    814.5   $    463.0
    Partners' capital
       Limited Partner .......................................         539.3        535.7        585.9        494.8        501.7
       General Partner .......................................           3.3          3.2          3.6          2.6          2.5
       Other comprehensive income ............................          (1.9)        --           --           --           --
                                                                  ----------   ----------   ----------   ----------   ----------
                                                                  $    540.7   $    538.9   $    589.5   $    497.4   $    504.2
                                                                  ==========   ==========   ==========   ==========   ==========


CASH FLOW DATA:
    Cash flow from operating activities ......................    $    117.4   $    117.3   $    101.6   $    103.6   $    106.6
    Cash flow used in investing activities ...................    $    (33.1)  $    (20.7)  $    (91.1)  $   (427.9)  $   (101.7)
    Cash flow from (used in) financing activities ............    $    (87.9)  $    (99.4)  $    (17.5)  $    252.7   $     24.1
    Capital expenditures included in investing activities ....    $    (34.0)  $    (21.7)  $    (82.9)  $   (487.3)  $   (126.9)

OPERATING DATA:
    Barrel miles (billions) ..................................         333          341          350          391          389
    Deliveries
     (thousands of bpd)
       United States .........................................         960          976          898          992          960
       Ontario ...............................................         355          362          471          570          552
                                                                  ----------   ----------   ----------   ----------   ----------
                                                                     1,315        1,338        1,369        1,562        1,512
                                                                  ==========   ==========   ==========   ==========   ==========

</TABLE>


                                       13
<PAGE>


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 audited 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 statements of income are discussed
under "Results of Operations". The "Liquidity and Capital Resources" section
analyzes cash flows and financial position. "Other Matters" addresses future
prospects, regulatory matters and recent accounting developments.

GENERAL

       The Lakehead System forms part of the world's longest liquid petroleum
pipeline system that strategically links crude oil production from the Western
Canadian Sedimentary Basin to key markets in the U.S. Midwest and eastern
Canada. During 2001, crude oil production from western Canada continued to lag
behind industry expectations and, as a result, deliveries on the Lakehead System
were lower than the previous year. Despite strong crude oil prices, exploration
and development activity focused on natural gas drilling rather than crude oil,
due to more favorable natural gas prices. Heavy crude oil production was
particularly affected due to a combination of an unusually low heavy crude oil
price relative to light crude, higher cost of diluents required to be added to
heavy crude for transportation and higher costs of natural gas used for fuel in
thermal recovery processes. Western Canadian crude oil supply was also adversely
affected by production problems and longer than expected maintenance shut-downs
at a major Alberta oil sands plant.

      The Partnership believes that crude oil production, and therefore
deliveries on the Lakehead System, will improve in 2002. Incremental production
is anticipated from some of the heavy crude oil sands development projects that
are expected to go into service during the year. Furthermore, long-term
prospects for increased crude oil production remain positive as western Canadian
producers continue to be committed to expansion projects that will bring
incremental supply to the Lakehead System. See--"Other Matters,--Future
Prospects".

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

       The Partnership's financial statements have been prepared in accordance
with accounting principles generally accepted in the United States. 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. The basis for these estimates is
historical experience 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.

      The Partnership believes the following critical accounting policies
respresent the more significant judgments and estimates used in the preparation
of its consolidated financial statements. In the normal course of the
Partnership's business, judgment is involved in determining depreciation,
customer and pipeline oil overage balance, crude oil measurement losses and
year-end accruals. The Partnership records depreciation 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. The oil overage
balance is recorded by the Partnership based on measurement estimates. These
estimates are based on mathematical calculations, 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. Last, in the normal course of preparing the year-end financial
statements, revenue and expense accruals are made for the month of December to
ensure amounts are complete and accurate on an annual basis. Judgments and
estimates are necessary to prepare these accruals. Changes in these estimates
are not expected to have a material impact on the earnings of the Partnership.
For additional details relating to the Partnership's accounting policies, see
Note 2 to the Partnership's Financial Statements.

RESULTS OF OPERATIONS

YEAR ENDED DECEMBER 31, 2001 COMPARED TO YEAR ENDED DECEMBER 31, 2000

      Net income for 2001 was $38.0 million compared with $60.9 million for
2000. Net income for 2001 was $22.9 million lower than 2000 primarily due to
higher operating expenses, which included a non-recurring charge for costs
related to the relocation of the Partnership's head office.


                                       14
<PAGE>

      Operating revenue for 2001 was $304.0 million, or $1.6 million lower than
2000. The decrease was primarily due to a decline in deliveries on the Lakehead
System offset by higher tariffs. Deliveries averaged 1.315 million bpd on the
Lakehead System in 2001, compared to 1.338 million bpd in 2000. This decline
occurred due to lower crude oil production in western Canada. System utilization
on the Lakehead System, measured in barrel miles, was 333 billion for 2001,
compared to 341 billion for 2000, reflecting the decline in deliveries. The
average haul, measured in miles, was 694 for 2001, compared to 696 in 2000.

      Total operating expenses of $210.8 million in 2001 were higher than the
2000 level of $189.1 million, due to higher operating and administrative costs
($18.9 million), power costs ($1.9 million), and depreciation expense ($0.9
million). Operating and administrative expenses increased $18.9 million
primarily due to higher oil measurement losses and costs related to the
relocation of the Partnership's head office, offset by an increase in
capitalized charges

      Oil measurement losses occur as part of normal operating conditions of a
liquid petroleum pipeline and can be classified as follows:

      o     Physical losses--occur through evaporation, shrinkage, difference in
            measurement between receipt and delivery locations and other
            incidents;

      o     Degradation losses--result from mixing at the interface between
            higher quality light crude oil and lower quality heavy crude oil in
            the pipeline; and

      o     Revaluation losses--are a function of the price of crude oil, the
            level of carrier's inventory and inventory positions of customers.

      Oil measurement losses were approximately $18.0 million in 2001, or
approximately $11.0 million higher than in 2000. This increase was primarily due
to higher differentials between light and heavy crude oil prices, which
increased the expense associated with inherent degradation between the batches
of crude oil in the pipeline system. Also included in oil measurement losses was
an adjustment to the value of the oil overage balance of approximately $5.0
million. This was the result of refinements in the oil measurement loss
estimation process, as well as improvements in the accuracy of measuring oil
losses through the development of new software applications.

      During the second quarter of 2001, the Partnership announced the closing
of its head office in Duluth, Minnesota and its relocation to Houston, Texas.
The results of operations for 2001 include a charge of $5.0 million related to
the expense of relocating the office.

      Interest expense of $58.0 million in 2001 was $2.4 million lower than 2000
primarily due to a combination of lower average debt balances and interest rates
on the revolving credit facility.

YEAR ENDED DECEMBER 31, 2000 COMPARED TO YEAR ENDED DECEMBER 31, 1999

      Net income for 2000 was $60.9 million compared with $79.6 million for
1999. Net income for 2000 was $18.7 million lower than 1999 primarily due to
lower pipeline utilization and increased operating costs. The decline in
utilization was a result of low crude oil prices in late 1998 and early 1999,
which caused crude oil producers to limit their investment in oil producing
facilities. Coupled with natural declines of crude oil reserves, reduced
investment by oil producers adversely affected short-term Partnership results
due to lower volumes of crude oil being available for transport.

      Operating revenue for 2000 was $305.6 million, or $7.0 million less than
1999. The decrease was primarily due to the decline in deliveries. Deliveries
averaged 1.338 million bpd in 2000, compared to 1.369 million bpd in 1999. The
decline occurred because the supply of crude oil had not recovered to
anticipated levels, further exacerbated by the effects of crude oil producer
maintenance shutdowns and wetter than normal weather in western Canada, which
delayed oil well tie-ins and other development activities. System utilization,
measured in barrel miles, was 341 billion for 2000, compared to 350 billion for
1999, reflecting the decline in deliveries. Average haul was 696 miles in 2000,
compared to 700 miles in 1999.

      Total operating expenses of $189.1 million in 2000 were higher than 1999
levels of $182.3 million as higher operating and administrative costs and higher
depreciation expense associated with expansions of the Lakehead System were
partially offset by lower power costs. Power costs decreased $5.6 million due to
lower throughput volumes. Operating and administrative expense increased $9.1
million primarily due to higher oil measurement losses, higher property taxes
associated with recent expansion projects and lower capitalized charges due to
the decrease of construction activity in 2000. Oil measurement losses were
approximately $3.9 million higher in 2000 compared to 1999, primarily due to the
higher differentials between the light and heavy crude oil prices. Depreciation



                                       15
<PAGE>

expense increased $3.3 million primarily due to the full year impact of placing
the Terrace Phase I project in service on April 1, 1999 and plant additions from
the prior year.

      Interest expense of $60.4 million in 2000 was $6.3 million higher than
1999 primarily due to lower capitalized interest resulting from less
construction activity during 2000.

LIQUIDITY AND CAPITAL RESOURCES

      The primary cash requirements for the Partnership consist of normal
operating expenses, maintenance and expansion capital expenditures,
distributions to the partners and debt service payments. Short-term cash
requirements, such as operating expenses, maintenance capital expenditures and
quarterly distributions to the partners are expected to be funded by operating
cash flows. Long term cash requirements for expansion projects are expected to
be funded by several sources including cash flows from operating activities,
borrowings under bank credit facilities, borrowings from affiliates and the
issuance of public debt.

      At December 31, 2001, cash and cash equivalents totaled $33.6 million,
down $3.6 million from December 31, 2000. Of this amount, $30.7 million was used
for the cash distribution paid to the Enbridge Partnership for payment to the
public unitholders on February 14, 2002, with the remaining $2.9 million
available for future cash distributions, capital expenditures and other business
needs.

      Cash flows from operating activities for 2001 were $117.4 million,
compared to $117.3 million for 2000. Cash flows from operating activities
primarily reflect the effects of net income, depreciation and amortization, and
changes in working capital. Net income decreased primarily due to higher
operating expenses. The change in operating assets and liabilites was $22.8
million higher in 2001, primarily due to the change in the oil overage balance.

      Cash outflows used in investing activities were $33.1 million in 2001,
compared to $20.7 million in 2000. In 2001, the Partnership made capital
expenditures (excluding acquisitions) of $34.0 million, of which $9.2 million
was for pipeline system enhancements, $8.5 million for core maintenance
activities and $16.3 million for Terrace. In 2000, the Partnership made capital
expenditures of $21.7 million, of which $10.8 million was for pipeline
enhancements and $10.9 million for core maintenance activities.

      In 2002, the Partnership anticipates spending approximately $10.0 million
for routine pipeline system enhancements, $10.0 million for core maintenance
activities, and $194.0 million for Terrace. Excluding major expansion projects,
ongoing capital expenditures are expected to average approximately $20.0 million
annually (approximately 50% for core maintenance and 50% for enhancement of the
pipeline system). Core maintenance activities, such as the replacement of
equipment and preventive maintenance programs, will be undertaken to enable the
Partnership's pipeline systems to continue to operate at their maximum operating
capacity. Enhancements to the pipeline systems, such as renewal and replacement
of pipe, are expected to extend the life of the systems and permit the
Partnership to respond to developing industry and government standards and the
changing service expectations of its customers.

      On an annual basis, the Partnership makes expenditures of a capital and
operating nature related to maintaining compliance of its transportation systems
with applicable environmental and safety regulations. Capital expenditures for
safety and environmental purposes comprise a portion of the routine core
maintenance and enhancement capital expenditures annually incurred by the
Partnership. Amounts are not readily segregated since individual projects may be
undertaken for a variety of reasons in addition to environment and safety
considerations. Based on existing laws and regulations, future environmental and
safety expenditures are not anticipated to have a material adverse impact on the
Partnership's results of operations.

      Cash outflows used in financing activities were $87.9 million in 2001
compared to $99.4 million in 2000. These cash flows are affected primarily by
distributions to the partners, Partners' contributions, repayments of variable
rate financing, borrowings from affiliates and fixed rate financing. At December
31, 2001, the Partnership had outstanding $310.0 million aggregate principal
amount of First Mortgage Notes bearing interest at the rate of 9.15% per annum,
payable semi-annually. The notes are due and payable in ten equal annual
installments beginning in December 2002, and are expected to be funded by
operating cash flows or refinancing arrangements. The Partnership had a $350.0
million Revolving Credit Facility under which $137.0 million was outstanding at
December 31, 2001. Interest rates on amounts drawn under this facility were
variable and averaged 5.3% in 2001.

      On January 29, 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, to replace the existing $350.0 million Revolving Credit
Facility. Under the terms of these new facilities, the Partnership and the
Enbridge 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 Enbridge
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 will be guaranteed by the Partnership, the
Enbridge Partnership and any of its material subsidiaries, unless it is the
borrower. Upon closing, indebtedness



                                       16

<PAGE>

under the $350.0 million Revolving Credit Facility was refinanced with
indebtedness drawn under the new credit facilities and the $350.0 million
Revolving Credit Facility was terminated. As at February 20, 2002, the
Partnership and the Enbridge Partnership had borrowed approximately $194.0
million under the two new credit facilities.

      In November 2000, the Partnership sold $100 million of 7.9% senior
notes due 2012. The proceeds from this sale were used to retire bank debt. In
1998, the Partnership sold $100 million of 7% senior notes due 2018 and $100
million of 7.125% senior notes due 2028. For additional details relating to
the Partnership's debt, see Note 5 to the Partnership's Financial Statements.

      The Partnership distributes quarterly all of 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 the partners and, as necessary, to comply
with the terms of any agreement or obligation of the Partnership. The
Partnership anticipates that it will continue to have adequate liquidity to
fund future recurring operating and investing activities. The Partnership
intends to fund ongoing capital expenditures with the proceeds from future
debt and equity offerings, other borrowings, cash generated from operating
activities, and existing cash and cash equivalents. Cash distributions are
expected to be funded with internally generated cash. The Partnership's
ability to complete future debt offerings will depend on prevailing market
conditions and the then existing financial condition of the Partnership.

OTHER MATTERS

FUTURE PROSPECTS

      The System serves as a strategic link between the western Canadian oil
fields and the markets of the Upper Midwest United States and eastern Canada. In
response to market conditions, the Partnership plans to maintain the service
capability of the Lakehead System and to expand its capacity and improve
efficiency where appropriate. To the extent allowed under orders of FERC or by
agreement with customers, the Partnership expects to file additional tariff
increases and surcharges from time to time to reflect these ongoing expansions.

TERRACE EXPANSION PROGRAM

      The Partnership and Enbridge are undertaking a major expansion of the
entire System, including the Lakehead System. This expansion is referred to as
the Terrace expansion program. This expansion program consists of a multi-phase
expansion of both the U.S. and Canadian portions of the System. Upon the
completion of all three phases of Terrace, the Partnership expects that
approximately 350,000 bpd of capacity will be added to the System.

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

      o     Construction of Phase II of Terrace began in June 2001, and was
            placed in service in early 2002. While Phase II did not involve
            construction on the Lakehead System, the approximate 40,000 bpd
            increase in capacity of the Enbridge System is expected to benefit
            the Lakehead System directly as additional deliveries begin from the
            Alberta oil sands.

      o     Phase III of Terrace is designed primarily to increase heavy oil
            transportation capacity on the Lakehead System between Clearbrook,
            Minnesota and Superior, Wisconsin by approximately 140,000 bpd. CAPP
            provided notice in June 2001 to proceed with this phase. Following
            permitting approval, construction on this phase of the program began
            in late 2001. The estimated cost to the Partnership of Terrace Phase
            III is approximately $210 million, and the new facilities are
            expected to be in service in 2003.

      o     CAPP also has provided notification requesting additional pipeline
            facilities to enhance market access to PADD 2. The project is part
            of the future phases portion of Terrace. The estimated cost of this
            project is approximately $35 million and, subject to final
            approvals, is expected to be in service in 2003.

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



                                       17
<PAGE>

PROSPECTS FOR GROWTH IN THE SUPPLY OF WESTERN CANADIAN CRUDE OIL

      Changes in supply from western Canada directly affect movements on the
Enbridge System and, therefore, the supply available for transportation on the
Lakehead System. Enbridge regularly updates its forecast of western Canadian
crude oil supply. This is a long-term outlook, which incorporates updated supply
projections from producers of both conventional and non-conventional sources of
crude oil. The forecast includes supply from existing operations, proposed
expansions of existing operations and production from selected projects proposed
for development.

      The forecast developed by Enbridge in early 2002 projects that the supply
of western Canadian crude oil will be approximately 2.1 million bpd in 2002, 2.2
million bpd in 2003 and approximately 2.3 million bpd in 2004. By 2011, supply
is expected to increase to approximately 2.8 million bpd. In 2001, the Enbridge
System transported approximately 65% of the total western Canadian crude oil
production, of which approximately 90% was transported by the Lakehead System.
The forecast quantity of crude oil was made subject to numerous uncertainties
and assumptions, including a crude oil price ranging from $23 to $26 per barrel
from 2002 to 2011. On February 20, 2002, the benchmark West Texas Intermediate
crude oil price closed at $20.29 per barrel.

      The Partnership believes that the outlook for increased crude oil
production in western Canada continues to be positive, as evidenced by the
recently completed Enbridge forecast and CAPP's request to proceed with Phase
III of Terrace. The timing of this growth in the supply of western Canadian
crude oil, however, will depend on the level of crude oil prices and drilling
activity, and the timing of completion of projects to produce heavy and
synthetic oil from the Alberta oil sands. During the last quarter of 2001,
volumes were starting to improve as one of the Alberta oil sands expansion
projects was placed into service. These volumes are expected to continue to
increase during 2002. As a result, based on a recent survey of shippers, the
Partnership anticipates that deliveries on the Lakehead System will average
approximately 1.33 to 1.40 million bpd per day during 2002.

      In the near-term, management believes that the Partnership is well
positioned to benefit from the expected increases in western Canadian crude oil
supply through utilization of a combination of existing capacity and expansions
currently underway. Canada has substantial reserves of non-conventional
hydrocarbon resources consisting predominantly of the Alberta oil sands. Firms
involved in the production of heavy and synthetic crude oil from the oil sands
region of western Canada have announced expansion projects over the next ten
years with value in excess of Cdn. $40.0 billion and representing more than two
million barrels per day of potential incremental production. Alberta oil sands
projects are expected to provide substantial increases in the production of
heavy and synthetic crude oil in western Canada well into the future.

REGULATORY MATTERS

      The Lakehead System is subject to a rate regulatory methodology that
prescribes rate ceilings that are adjusted each July 1. The rate ceilings are
adjusted by reference to annual changes in the Producer Price Index for Finished
Goods minus 1 percent. The General Partner expects the rate ceiling to increase
slightly for 2002. This increase in the PPIFG-1 should not have a material
effect on 2002 operating revenue since the increase will not be effective until
mid-year 2002 and does not apply to SEP II or Terrace.

      The 1996 Settlement Agreement among the Partnership, CAPP and ADOE
provided that the agreed underlying tariff rates on the Lakehead System would be
subject to indexing as prescribed by FERC regulation and that CAPP and ADOE
would not challenge any rates within the indexed ceiling until after October
2001. To challenge the rates, FERC regulations require that a shipper must show
that the amount of any indexed rate increase is so substantially in excess of
the pipeline's increase in costs as to be unjust and unreasonable. The
Partnership believes that changes in costs, other than those associated with
expansions and oil losses, have been in line with changes in the index, and does
not expect a challenge. The Partnership strives to have a strong working
relationship with its shippers.

      The indexed rate environment, the Settlement Agreement, and other
negotiated settlements with customers for SEP II and Terrace have benefited the
Partnership and its customers by restoring stability and providing predictable
tariff rates. To the extent allowed under FERC orders or by agreement with
customers, the Partnership has filed, and will continue to file, for additional
tariff increases from time to time to reflect ongoing expansion programs.


                                       18
<PAGE>

RECENT ACCOUNTING DEVELOPMENTS

      In June 1998, the FASB issued SFAS No. 133, "Accounting for Derivative
Instruments and Hedging Activities." This Statement requires that all
derivatives be recognized at fair value in the balance sheet and all changes in
fair value be recognized currently in earnings or deferred as a component of
other comprehensive income, depending on the intended use of the derivative. The
Partnership adopted SFAS No. 133 on January 1, 2001.

      In June 2001, the FASB issued SFAS No. 141, "Business Combinations." This
Statement requires the use of the purchase method for all business combinations.
In addition, it requires the reassessment of intangible assets to determine if
they are appropriately classified either separately or within goodwill. This
Statement is effective for business combinations initiated after June 30, 2001.
The Partnership adopted SFAS No. 141 on July 1, 2001 with no impact on results
of operations, financial position or cash flows.

      In July 2001, the FASB issued SFAS No. 142, "Goodwill and Other Intangible
Assets". Under SFAS No. 142, goodwill and intangible assets with indefinite
lives will not be amortized but will be reviewed for impairment at least
annually. Intangible assets with finite lives will continue to be amortized over
their useful lives, which will not be limited to a maximum life of forty years.
The Partnership adopted SFAS No. 142 on January 1, 2002. This standard is not
expected to have a material impact on results of operations, financial position
or cash flows.

      Also in July 2001, the FASB issued SFAS No. 143 "Accounting for Asset
Retirement Obligations" under which retirement obligations will be recognized at
fair value in the period they are incurred. 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. SFAS No. 143 is
effective for fiscal years beginning after June 15, 2002. The Partnership is
currently evaluating the potential effects of adopting SFAS No. 143, if any, on
its financial condition and results of operations as well as the timing of its
adoption.

      In October 2001, the FASB issued SFAS No. 144, "Accounting for the
Impairment or Disposal of Long-Lived Assets". SFAS No. 144 clarifies the
financial accounting and reporting to be recognized if the carrying amount of a
long-lived asset is not recoverable from its undiscounted cash flows. The
impairment loss to be recognized is the difference between the carrying amount
and the fair value of the assets. The Partnership adopted SFAS No. 144 on
January 1, 2002. This standard is not expected to have a material impact on
results of operations, financial position or cash flows.

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 agreements. 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 US dollars. To the
extent that a material foreign exchange exposure were to arise, the Partnership
intends to hedge such exposure using forward or other derivative contracts.


                                       19
<PAGE>


      The table below summarizes 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 interest rates by expected
(contractual) maturity dates. Notional amounts are used to calculate the
contractual payments to be exchanged under the contract.

<TABLE>
<CAPTION>
                                                                EXPECTED MATURITY DATE
                                                              -----------------------------          THERE-                 FAIR
DECEMBER 31, 2001                            2002        2003       2004        2005       2006      AFTER       TOTAL      VALUE
-----------------                           ------      ------    -------     -------    -------    -------     -------    --------
                                                                        ($U.S. IN MILLIONS)
<S>                                        <C>         <C>       <C>         <C>         <C>        <C>         <C>        <C>
LIABILITIES
FIXED RATE:
    First Mortgage Notes ..............    $  31.0     $  31.0   $  31.0     $  31.0     $  31.0    $ 155.0     $ 310.0    $ 342.6
    Interest Rate .....................       9.15%       9.15%     9.15%       9.15%       9.15%      9.15%         --         --
    Senior Unsecured Notes ............    $     0     $     0   $     0     $     0     $     0    $ 300.0     $ 300.0    $ 291.4
    Average Interest Rate .............         --          --        --          --          --       7.34%         --         --
VARIABLE RATE:
    Revolving Credit Facility .........    $     0     $     0   $     0     $ 137.0     $     0    $     0     $ 137.0    $ 137.0
    Weighted Average Interest Rate ....         --          --        --        2.43%         --         --          --         --
INTEREST RATE DERIVATIVES
INTEREST RATE SWAPS:
    Variable to Fixed .................    $  50.0     $     0   $     0     $     0     $     0    $     0     $  50.0    $  (1.9)
    Average Pay Rate ..................       6.23%         --        --          --          --         --          --         --

</TABLE>


      The fair value of the First Mortgage Notes and Senior Unsecured Notes at
December 31, 2001, was $342.6 million (2000--$346.5 million) and $291.4 million
(2000--$290.3 million), respectively. The Partnership had $137.0 million
(2000--$190.0 million) of variable rate debt outstanding under the Revolving
Credit Facility at December 31, 2001, with a fair value of $137.0 million
(2000--$190.0 million), at an interest rate of 2.43% (2000--6.2%). The
Partnership intends to roll over variable rate debt under its revolving credit
facilities as the debt matures.

      The fair value of the interest rate swap agreements at December 31,
2001 was ($1.9) million (2000--($0.1) million). For additional information
concerning the Partnership's debt obligations, please see Note 9 to the
Partnership's Financial Statements.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

      The financial statements of the Partnership together with the notes
thereto and the independent accountants' report thereon, appear on pages F-2
though F-12 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.


                                       20
<PAGE>

                                    PART III

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

(a) DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

      The Registrant is a limited partnership and has no officers, directors or
employees. Set forth below is certain information concerning the directors and
executive officers of the General Partner. Enbridge Pipelines, the sole
stockholder of the General Partner, elects the directors of the General Partner
on an annual basis. All officers of the General Partner serve at the discretion
of the directors of the General Partner.


       NAME                            AGE  POSITION WITH GENERAL PARTNER
       ----                            ---  -----------------------------

       J.R. Bird.....................  52   Director
       P.D. Daniel...................  55   Director
       E.C. Hambrook.................  64   Director
       G.K. Petty....................  60   Director
       C.A. Russell..................  68   Director
       D.P. Truswell.................  58   Director
       D.C. Tutcher..................  53   President and Director
       L.H. DeBriyn..................  55   Vice President
       G.L.Sevick....................  46   Vice President--Operations
       M.A. Maki.....................  37   Controller
       A. Monaco.....................  42   Treasurer
       J.L. Balko....................  36   Chief Accountant
       E.C. Kaitson..................  45   Corporate Secretary



      Mr. Bird was elected Director of the General Partner in September 2000 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 has also served as Group Vice President, Transportation of Enbridge and
President of Enbridge Pipelines since September 2000. Prior to that time he
served as Senior Vice President, Corporate Planning and Development of Enbridge
from August 1997 through August 2000 and as Vice President and Treasurer of
Enbridge from January 1995 to August 1997.

      Mr. 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 and Chief Operating Officer--Energy Delivery of Enbridge
from June 1998 to December 2000. Prior to that time Mr. Daniel served as
Executive Vice President and Chief Operating Officer--Energy Transportation
Services of Enbridge from September 1997 through June 1998, as Senior Vice
President of Enbridge from May 1994 to August 1997, as President and Chief
Executive Officer of Enbridge Pipelines from August 1996 to August 1997, and as
President and Chief Operating Officer of Enbridge Pipelines from May 1994 to
August 1996.

      Mr. Hambrook was elected Director of the General Partner in January 1992
and served as Chairman of the General Partner from July 1996 until July 1999. He
also serves on the Audit, Finance & Risk Committee pursuant to the over-ride
allowed by Rule 303 of the NYSE Company manual. Mr. Hambrook is the President of
Hambrook Resources Inc., a real estate investment, marketing and sales company.
The NYSE requires that members of the General Partner's audit committee be
"independent", which is defined as the absence of any relationship to the
Partnership that may interfere with the exercise of his independence from
management of the Partnership. The NYSE Company Manual further provides that a
director who is an employee (including non-employee executive officers) of the
General Partner or any of its affiliates may not serve on the audit committee
until three years following the termination of his or her employment, except
that one non-independent member is permitted under certain circumstances.
Although Mr. Hambrook has never been employed by the General Partner or any of
its affiliates, prior to July 15, 1999 he served as Chairman of the Board of the
General Partner. The Board of Directors of the General Partner believes that
such prior service has not and will not interfere with Mr. Hambrook's exercise
of his independence from management of the General Partner.


                                       21
<PAGE>

      Mr. Petty was elected Director of the General Partner on February 22, 2001
and serves on the Audit, Finance & Risk Committee. Mr. Petty has served as
Director of Enbridge Inc. since January 2001 and as Director of CAE Incorporated
since August 1996. Mr. Petty served as President and Chief Executive Officer of
Telus Corporation, a Canadian telecommunications company, from November 1994 to
November 1999. Mr. Petty is a business consultant providing executive management
consulting services to the telecommunications industry.

      Mr. Russell was elected Director of the General Partner in October 1985
and serves as the Chairman of the 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 Director of the General
Partner, Mr. Russell is retired

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

      Mr. Tutcher was elected Director and was appointed President of the
General Partner in June 2001. He also currently serves as Group Vice President,
Transportation Group South, of Enbridge Inc., as well as President of Enbridge
Midcoast Energy Inc. He was previously Chairman of the Board, President and
Chief Executive Officer of Midcoast Energy Resources, Inc. from its formation in
1992 until its acquisition by Enbridge on May 15, 2001.

      Mr. DeBriyn was elected Vice President, Special Projects of the General
Partner in June 2001 and served as Vice President and Director from July 1999
until June 2001. Prior to that time he served as Vice President, Canadian
Operations, of Enbridge Pipelines from July 1996 to July 1999, and prior to that
time in managerial positions in operations with Enbridge Pipelines and the
General Partner.

      Mr. Sevick was elected Vice President, Operations of the General Partner
in June 2001. Prior to that time, he served as Vice President, Canadian
Operations for Enbridge Pipelines from 1999 to June 2001. Prior to that time, he
served as Vice President, Engineering & Logistics of Enbridge Consumers Gas from
1998 to 1999 and Senior Vice President, Distribution Operations of Enbridge
Consumers Gas from 1996 to 1998.

      Mr. Maki was elected Controller of the General Partner in June 2001. 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.

      Mr. Monaco was elected 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 since 1997.

      Ms. Balko has served as Chief Accountant since October 1999. Prior to that
time, she served in supervisory positions in accounting with Enbridge Pipelines
since January 1998, and was with The Westaim Corporation, an investor in, and
manufacturer of, industrial technologies in various industries, including the
biomedical and semiconductor industries, from November 1995 to December 1997.

      Mr. 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 Inc. He was previously Assistant
Corporate Secretary and General Counsel of Midcoast Energy Resources, Inc. from
1997 until its acquisition by Enbridge on May 15, 2001.

ITEM 11. EXECUTIVE COMPENSATION

The General Partner is responsible for the management and operation of the
Partnership. The Partnership does not directly employ any of the persons
responsible for managing or operating the Partnership's operations, but instead
reimburses the General Partner or its affiliates for the services of such
persons. The General Partner, in turn, because it has no employees, has entered
into services agreements with Enbridge U.S. and other affiliates to provide the
services required by the Partnership.



                                       22

<PAGE>

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

      (A)   SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS

      The General Partner owns a 1.0101% general partner interest in the
Partnership. The remaining 98.9899% limited partner interest in the Partnership
is owned by the Enbridge Partnership.

      (B)   SECURITY OWNERSHIP OF MANAGEMENT

      None.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

The Partnership is managed by the General Partner under the Amended and Restated
Agreements of Limited Partnership of the Partnership and the Operating
Partnership, as amended. The General Partner has entered into a service
agreement with Enbridge U.S., dated January 1, 1996, whereby the General Partner
will utilize the resources of Enbridge U.S. to operate the Partnership. Under
this agreement, Enbridge U.S. will be reimbursed at cost for all direct and
indirect expenses it incurs or payments it makes on behalf of the Partnership.
The General Partner also receives certain administrative, engineering, treasury
and computer services from Enbridge and Enbridge Pipelines for the benefit of
the Partnership. The Partnership reimburses the General Partner for the cost of
these services. For information about reimbursements to the General Partner, see
Note 6 to the Partnership's Financial Statements.

      The Partnership has entered into an Agency Agreement dated March 3, 2000
with Tidal, a joint venture owned 50% by Enbridge, for a term of five years. For
a fee and a share of the lease payments in excess of a specified base lease
rate, Tidal has agreed to serve as leasing agent for the Partnership's crude oil
storage tanks at its Hartsdale facility in Schererville, Indiana. See Note 6 to
the Partnership's Financial Statements.

      The Partnership has entered into an easement acquisition agreement
dated October 20, 1997 with Enbridge Mustang, a subsidiary of Enbridge U.S.
Pursuant to this agreement, using funds advanced by the Partnership, Enbridge
Mustang acquired properties for the purpose of granting a pipeline easement
to the Partnership to allow construction of SEP II. Enbridge Mustang is in
the process of reselling these properties. As each parcel is resold, Enbridge
Mustang retains an easement for transfer to the Partnership and repays the
Partnership for the funds advanced to make the original purchase of the
property (less the cost of the easement). Enbridge Mustang is being
reimbursed for all costs associated with this process at cost by the
Partnership and will be indemnified by the Partnership from and against all
liabilities that may arise in connection with this process. See Note 9 to the
Partnership's Financial Statements.

      The Partnership has entered into an agreement, dated March 3, 1998, with
Mustang and Mobil to provide for a joint tariff covering shipments of western
Canadian crude oil to the Patoka pipeline hub south of Chicago. Mustang is a
Delaware general partnership owned by Mobil Illinois Pipe Line Company and
Enbridge Mustang. Shipments covered by the joint tariff travel on the Lakehead
System to Chicago and to the Patoka pipeline hub through the Mustang pipeline
system. The joint tariff agreement provides for lower transportation costs to
shippers desiring access to the Patoka market area, an incentive which the
Partnership believes complements its expansion programs.

      The General Partner believes that the terms of the agreements described in
the preceding four paragraphs are at least as favorable as terms that could have
been obtained from unaffiliated third parties.

      On January 29, 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, to replace the existing $350.0 million Revolving Credit
Facility. Under the terms of these new facilities, the Partnership and the
Enbridge 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 Enbridge
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 will be guaranteed by the Partnership, the
Enbridge Partnership and any of its material subsidiaries, unless it is the
borrower.



                                       23
<PAGE>

                                     PART IV


ITEM 14. 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 2001: A report on Form 8-K was filed on November 1, 2001
attaching a press release announcing an acquisition by the Enbridge Partnership.
      (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. (Partnership's
                  Registration Statement No. 33-43425-- Exhibit 10.1)

      3.2         Certificate of Amendment to Certificate of Limited
                  Partnership. (2000 Form 10-K/A dated October 9, 2001---Exhibit
                  10.8)

      4.1         Form of Certificate representing Class A Common Units of the
                  Partnership (Partnership's 2000 Form 10-K/A dated October 9,
                  2001-Exhibit 4.1)

      4.2         Amended and Restated Agreement of Limited Partnership, dated
                  December 27, 1991. (1991 Form 10-K-- Exhibit 10.6)

      4.3         Amendment to Amended and Restated Agreement of Limited
                  Partnership, dated August 28, 2001. (Form 10-K/A dated October
                  9, 2001--Exhibit--10.10)

     10.1         Note Agreement and Mortgage, dated December 12, 1991. (1991
                  Form 10-K-- Exhibit 10.1)

     10.2         [Intentionally Omitted]

     10.3         Distribution Support Agreement, dated December 27, 1991, among
                  the Partnership, Lakehead Pipe Line Company, Inc. and
                  Interprovincial Pipe Line Inc. (1991 Form 10-K-- Exhibit 10.3)

     10.4         Assumption and Indemnity Agreement, dated December 18, 1992,
                  between Interprovincial Pipe Line Inc. and Interprovincial
                  Pipe Line System Inc. (1992 Form 10-K-- Exhibit 10.4)

     10.5         Amended Services Agreement, dated February 29, 1988, between
                  Interprovincial Pipe Line Inc. and Lakehead Pipe Line Company,
                  Inc. (1991 Form 10-K-- Exhibit 10.4)

     10.6         Amended Services Agreement, dated January 1, 1992, between
                  Interprovincial Pipe Line Inc. and Lakehead Pipe Line Company,
                  Inc. (1992 Form 10-K-- Exhibit 10.6)

     10.7         Certificate of Limited Partnership of the Partnership.
                  (Partnership's Registration Statement No. 33-43425-- Exhibit
                  3.1)

     10.8         Certificate of Amendment to Certificate of Limited Partnership
                  of the Partnership (Partnership's 2000 Form 10-K/A dated
                  October 9, 2001-Exhibit 3.2)

     10.9         Amended and Restated Agreement of Limited Partnership of the
                  Partnership, dated April 15, 1997. (Partnership's Form 8-A/A,
                  dated May 2, 1997)

     10.10        Amendment to Amended and Restated Agreement of Limited
                  Partnership, dated August 28, 2001(Partnership's 2000 Form
                  10-K/A dated October 9, 2001-Exhibit 4.3)

     10.11        Certificate of Limited Partnership of Lakehead Services,
                  Limited Partnership. (Partnership's Registration Statement No.
                  33-43425 -- Exhibit 10.4)

     10.12        Amendment No. 1 to the Certificate of Limited Partnership of
                  Lakehead Services, Limited Partnership. (Partnership's
                  Registration Statement No. 33-43425-- Exhibit 10.16)

     10.13        Amended and Restated Agreement of Limited Partnership of
                  Lakehead Services, Limited Partnership, dated December 27,
                  1991. (1991 Form 10-K-- Exhibit 10.9)

     10.14        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. (1991 Form 10-K-- Exhibit 10.10)

     10.15        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. (1991
                  Form 10-K-- Exhibit 10.11)


                                       24
<PAGE>

     10.16        Services Agreement, dated January 1, 1996, between IPL Energy
                  (U.S.A.) Inc. and Lakehead Pipe Line Company, Inc. (1995 Form
                  10-K -- Exhibit 10.14)

     10.17        Amended and Restated Revolving Credit Agreement, dated
                  September 6, 1996, among Lakehead Pipe Line Company, Inc.,
                  Lakehead Pipe Line Partners, L.P., Lakehead Services, Limited
                  Partnership, Lakehead Pipe Line Company, Limited Partnership
                  and the Bank of Montreal and Harris Trust and Savings Bank.
                  (1996 Form 10-K-- Exhibit 10.15)

     10.18        First Amendment to Amended and Restated Revolving Credit
                  Agreement, dated September 6, 1996, among Lakehead Pipe Line
                  Company, Inc., Lakehead Pipe Line Partners, L.P., Lakehead
                  Services, Limited Partnership, Lakehead Pipe Line Company,
                  Limited Partnership and the Bank of Montreal. (1996 Form
                  10-K-- Exhibit 10.16)

     10.19        Second Amendment to Amended and Restated Revolving Credit
                  Agreement, dated June 16, 1998, among Lakehead Pipe Line
                  Company, Inc., Lakehead Pipe Line Partners, L.P., Lakehead
                  Services Limited Partnership, Lakehead Pipe Line Company,
                  Limited Partnership and Bank of Montreal, The Toronto Dominion
                  Bank, Canadian Imperial Bank of Commerce, ABN AMRO Bank, N.V.
                  Cayman Islands Branch and Bank of Montreal, as agent. (Form
                  10-Q/A, filed September 14, 1998-- Exhibit 10.1)

     10.20        Settlement Agreement, dated August 28, 1996, between Lakehead
                  Pipe Line Company, Limited Partnership and the Canadian
                  Association of Petroleum Producers and the Alberta Department
                  of Energy. (1996 Form 10-K-- Exhibit 10.17)

     10.21        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. (1998 Form
                  10-K--Exhibit 10.19)10.22

     10.22        Treasury Services Agreement, dated January 1, 1996, between
                  IPL Energy Inc. and Lakehead Pipe Line Company, Inc. (1996
                  Form 10-K -- Exhibit 10.18)

     10.23        Tariff Agreement as filed with the Federal Energy Regulatory
                  Commission for the System Expansion Program II and Terrace
                  Expansion Project. (1998 Form 10-K--Exhibit 10.21)

     10.24        Indenture dated September 15, 1998, between Lakehead Pipe Line
                  Company, Limited Partnership and the Chase Manhattan Bank.
                  (October 20, 1998 Form 8-K -- Exhibit 4.1 )

     10.25        First Supplemental Indenture dated September 15, 1998, between
                  Lakehead Pipe Line Company, Limited Partnership and the Chase
                  Manhattan Bank. (1998 Form 8-K of Lakehead Pipe Line Company,
                  Limited Partnership-- Exhibit 4.2, dated October 20, 1998)

     10.26        Second Supplemental Indenture dated September 15, 1998,
                  between Lakehead Pipe Line Company, Limited Partnership and
                  the Chase Manhattan Bank. (1998 Form 8-K of Lakehead Pipe Line
                  Company, Limited Partnership-- Exhibit 4.3, dated October 20,
                  1998)

     10.27        Indenture dated September 15, 1998, between Lakehead Pipe Line
                  Company, Limited Partnership and the Chase Manhattan Bank.
                  (1998 Form 8-K of Lakehead Pipe Line Company, Limited
                  Partnership-- Exhibit 4.4, dated October 20, 1998)

     10.28        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. (1999 Form
                  10-K--Exhibit 10.26)

     10.29        Third Supplemental Indenture dated November 21, 2000, between
                  Lakehead Pipe Line Company, Limited Partnership and the Chase
                  Manhattan Bank. (2000 Form 8-K of Lakehead Pipe Line Company,
                  Limited Partnership--Exhibit 4.2, dated November 16, 2000).

     10.30        Credit Agreement dated January 29, 2002, among Enbridge Energy
                  Partners, L.P., Enbridge Energy, Limited Partnership and Bank
                  of America, N.A., (Partnership's 2001 Form 10-K--Exhibit
                  10.30)

     10.31        364-Day Credit Agreement dated January 29, 2002, among
                  Enbridge Energy Parnters, L.P., Enbridge Energy, Limited
                  Partnership and Bank of America, N.A. (Partnership's 2001 Form
                  10-K--Exhibit 10.31)

     23.1         Consent of PricewaterhouseCoopers LLP.

     27           Financial Data Schedule as of and for the year ended December
                  31, 2001.


      All Exhibits listed above (with the exception of Exhibits 10.30, 10.31,
and 23.1 which are filed herewith) are incorporated herein by reference to
the documents identified in parentheses.


                                       25
<PAGE>

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

      (d)  As to financial statement schedules, reference is made to "Financial
           Statement Schedules" on page F-1 of this report.




                                       26
<PAGE>

                                   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, LIMITED PARTNERSHIP
                                                     (Registrant)

                                     By:  Enbridge Energy Company, Inc.,
                                          as General Partner



Date: March 22, 2002                 By:  -----------------------------------
                                                    Dan C. Tutcher
                                                     (PRESIDENT)


      Pursuant to the requirements of the Securities Exchange Act of 1934, this
Report has been signed below on March 22, 2002 by the following persons on
behalf of the Registrant and in the capacities indicated with the General
Partner.


     /S/ DAN C. TUTCHER                       /S/ E.C. HAMBROOK
  ------------------------------     ---------------------------------------
         Dan C. Tutcher                           E.C. Hambrook
    President and Director                         Director
 (Principal Executive Officer)



        /s/ J.R. BIRD                            /S/ J.L. BALKO
  ------------------------------     ---------------------------------------
          J. R. Bird                                J.L. Balko
          Director                              Chief Accountant
                                    (Principal Financial and Accounting Officer)




      /s/ C.A. RUSSELL                           /S/ P.D. DANIEL
  ------------------------------     ---------------------------------------
         C.A. Russell                              P.D. Daniel
           Director                                  Director



      /s/ G.K. PETTY                          /S/ D.P. TRUSWELL
  ------------------------------     ---------------------------------------
        G.K. Petty                              D.P. Truswell
         Director                                  Director



                                       27
<PAGE>

          INDEX TO FINANCIAL STATEMENTS, SUPPLEMENTARY INFORMATION AND
                          FINANCIAL STATEMENT SCHEDULES

                      ENBRIDGE ENERGY, LIMITED PARTNERSHIP

<TABLE>
<CAPTION>
                                                                                      PAGE
                                                                                      ----
<S>                                                                                      <C>
Financial Statements
  Report of Independent Accountants.................................................   F-2
  Statements of Income for the Years Ended December 31, 2001, 2000, 1999............   F-3
  Statements of Cash Flows for the Years Ended December 31, 2001, 2000, 1999........   F-4
  Statements of Financial Position as at December 31, 2001 and 2000.................   F-5
  Statements of Partners' Capital for the Years Ended December 31, 2001, 2000, 1999.   F-6
  Notes to the Financial Statements.................................................   F-7
Supplementary Information (Unaudited)
Selected Quarterly Financial Data...................................................  F-14

</TABLE>


                               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-1
<PAGE>


                       REPORT OF INDEPENDENT ACCOUNTANTS

To the Partners of
Enbridge Energy, Limited Partnership:

In our opinion, the accompanying statements of financial position and the
related statements of income, of partners' capital, and of cash flows present
fairly, in all material respects, the financial position of Enbridge Energy,
Limited Partnership (the Partnership) at December 31, 2001 and 2000, and the
results of its operations and its cash flows for each of the three years in the
period ended December 31, 2001 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.

PricewaterhouseCoopers LLP

Houston, Texas
January 24, 2002



                                      F-2

<PAGE>

<TABLE>
<CAPTION>
--------------------------------------------------------------------------------
                      ENBRIDGE ENERGY, LIMITED PARTNERSHIP
                              STATEMENTS OF INCOME
--------------------------------------------------------------------------------


(IN MILLIONS)
--------------------------------------------------------------------------------

Year ended December 31,                     2001         2000         1999
--------------------------------------------------------------------------------
<S>                     <C>                <C>          <C>          <C>
Operating revenue (NOTE 7)                 $304.0       $305.6       $312.6
--------------------------------------------------------------------------------

Expenses
   Power                                     49.3         47.4         53.0
   Operating and administrative              99.5         80.6         71.5
   Depreciation                              62.0         61.1         57.8
--------------------------------------------------------------------------------

                                            210.8        189.1        182.3
--------------------------------------------------------------------------------

Operating income                             93.2        116.5        130.3

Interest and other income                     2.8          4.8          3.4

Interest expense (NOTE 5)                   (58.0)       (60.4)       (54.1)
--------------------------------------------------------------------------------

Net income                                 $ 38.0       $ 60.9       $ 79.6
================================================================================

</TABLE>

  THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THESE FINANCIAL STATEMENTS.



                                      F-3
<PAGE>

--------------------------------------------------------------------------------
                      ENBRIDGE ENERGY, LIMITED PARTNERSHIP
                            STATEMENTS OF CASH FLOWS
--------------------------------------------------------------------------------

<TABLE>
<CAPTION>
(IN MILLIONS)
---------------------------------------------------------------------------------------------------------------------

Year ended December 31,                                                 2001              2000              1999
---------------------------------------------------------------------------------------------------------------------
<S>                                                                    <C>               <C>               <C>
Cash provided from operating activities
   Net income                                                          $ 38.0            $ 60.9            $ 79.6
   Adjustments to reconcile net income to cash
      provided from operating activities:
        Depreciation                                                     62.0              61.1              57.8
        Interest on accrued rate refunds                                   --                --               0.7
        Other                                                             0.1               0.8               0.9
        Changes in operating assets and liabilities, net
            Accounts receivable and other                                (0.6)              1.1              (3.2)
            Oil overage balance                                          18.9              (4.2)             (3.1)
            Materials and supplies                                         --              (0.3)             (0.3)
            General Partner and affiliates                                1.0              (3.2)             (1.2)
            Accounts payable and other                                   (1.8)             (0.2)             (2.4)
            Interest payable                                              0.3               0.2               0.8
            Property and other taxes                                     (0.5)              1.1               1.4
            Payment of rate refunds and related interest                   --                --             (29.4)
---------------------------------------------------------------------------------------------------------------------

                                                                        117.4             117.3             101.6
---------------------------------------------------------------------------------------------------------------------

Investing activities
   Repayments from affiliate (NOTE 6)                                     3.0               1.6              24.5
   Additions to property, plant and equipment                           (34.0)            (21.7)            (82.9)
   Changes in construction payables                                      (2.1)             (0.6)            (32.7)
---------------------------------------------------------------------------------------------------------------------

                                                                        (33.1)            (20.7)            (91.1)
---------------------------------------------------------------------------------------------------------------------

Financing activities
   Partners' contributions, net                                          80.7                --             120.9
   Distributions to partners (NOTE 3)                                  (115.0)           (111.5)           (108.4)
   Loan (from) to Enbridge Energy Partners, L.P., net                    (0.2)              0.2                --
   Variable rate financing, net (NOTE 5)                                (53.0)            (85.0)            (30.0)
   Fixed rate financing, net (NOTE 5)                                      --              99.8                --
   Debt financing costs                                                  (0.4)             (2.9)               --
---------------------------------------------------------------------------------------------------------------------

                                                                        (87.9)            (99.4)            (17.5)
---------------------------------------------------------------------------------------------------------------------

Decrease in cash and cash equivalents                                    (3.6)             (2.8)             (7.0)

Cash and cash equivalents at beginning of year                           37.2              40.0              47.0
---------------------------------------------------------------------------------------------------------------------

Cash and cash equivalents at end of year                               $ 33.6            $ 37.2            $ 40.0
=====================================================================================================================
</TABLE>

   THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THESE FINANCIAL STATEMENTS.


                                      F-4

<PAGE>

<TABLE>
<CAPTION>
--------------------------------------------------------------------------------
                      ENBRIDGE ENERGY, LIMITED PARTNERSHIP
                        STATEMENTS OF FINANCIAL POSITION

--------------------------------------------------------------------------------


(IN MILLIONS)
--------------------------------------------------------------------------------

December 31,                                               2001        2000
--------------------------------------------------------------------------------
<S>                                                      <C>         <C>
                              ASSETS

Current assets
   Cash and cash equivalents                             $   33.6    $   37.2
   Due from General Partner and affiliates                    0.5         1.5
   Accounts receivable and other                             26.3        25.7
   Oil overage balance                                         --         8.9
   Advances to affiliate (NOTE 6)                             2.9         5.9
   Materials and supplies                                     7.7         7.7
--------------------------------------------------------------------------------

                                                             71.0        86.9
--------------------------------------------------------------------------------

Deferred charges and other                                    8.3         7.9

Property, plant and equipment, net (NOTE 4)               1,253.9     1,281.9
--------------------------------------------------------------------------------

                                                         $1,333.2    $1,376.7
================================================================================

          LIABILITIES AND PARTNERS' CAPITAL

Current liabilities
   Oil overage balance                                   $   10.0    $    0.2
   Accounts payable and other                                13.5        17.4
   Interest payable                                           6.8         6.5
   Property and other taxes payable                          13.9        14.4
   Other current liabilities (NOTE 9)                         1.9          --
   Current portion of First Mortgage Notes                   31.0          --
--------------------------------------------------------------------------------

                                                             77.1        38.5

Long-term debt (NOTE 5)                                     715.4       799.3
Contingencies (NOTE 8)
--------------------------------------------------------------------------------

                                                            792.5       837.8
--------------------------------------------------------------------------------

Partners' capital
   Limited partner                                          539.3       535.7
   General Partner                                            3.3         3.2
   Accumulated other comprehensive loss (NOTE 9)             (1.9)         --
--------------------------------------------------------------------------------

                                                            540.7       538.9
--------------------------------------------------------------------------------

                                                         $1,333.2    $1,376.7
================================================================================
</TABLE>


THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THESE FINANCIAL STATEMENTS.



                                      F-5
<PAGE>

--------------------------------------------------------------------------------

                      ENBRIDGE ENERGY, LIMITED PARTNERSHIP
                         STATEMENTS OF PARTNERS' CAPITAL

--------------------------------------------------------------------------------

<TABLE>
<CAPTION>
                                                                                             Accumulated
                                                                                                   Other
                                                            Limited            General     Comprehensive
(IN MILLIONS)                                               Partner            Partner              Loss        Total
------------------------------------------------------------------------------------------------------------------------
<S>                                                          <C>               <C>             <C>             <C>
Partners' capital at December 31, 1998                       $494.8            $  2.6          $   --          $497.4

Partners' contributions, net                                  119.7               1.2              --           120.9

Distributions to partners                                    (107.3)             (1.1)             --          (108.4)

Net income allocation                                          78.7               0.9              --            79.6
------------------------------------------------------------------------------------------------------------------------

Partners' capital at December 31, 1999                        585.9               3.6              --           589.5

Distributions to partners                                    (110.4)             (1.1)             --          (111.5)

Net income allocation                                          60.2               0.7              --            60.9
------------------------------------------------------------------------------------------------------------------------

Partners' capital at December 31, 2000                        535.7               3.2              --           538.9

Partners' contributions, net                                   79.9               0.8              --            80.7

Distributions to partners                                    (113.8)             (1.2)             --          (115.0)
------------------------------------------------------------------------------------------------------------------------

Subtotal                                                      501.8               2.8              --           504.6
------------------------------------------------------------------------------------------------------------------------

Net income allocation                                          37.5               0.5              --            38.0

Other comprehensive income:

Loss on derivative financial instruments                         --                --            (1.9)           (1.9)
------------------------------------------------------------------------------------------------------------------------

Comprehensive Income                                           37.5               0.5            (1.9)           36.1
------------------------------------------------------------------------------------------------------------------------

Partners' capital at December 31, 2001                       $539.3            $  3.3          $ (1.9)         $540.7
========================================================================================================================

</TABLE>

   THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THESE FINANCIAL STATEMENTS.


                                      F-6

<PAGE>

--------------------------------------------------------------------------------

                      ENBRIDGE ENERGY, LIMITED PARTNERSHIP
                       NOTES TO THE FINANCIAL STATEMENTS

--------------------------------------------------------------------------------


(IN MILLIONS)
--------------------------------------------------------------------------------

1.  PARTNERSHIP ORGANIZATION AND NATURE OF OPERATIONS

Enbridge Energy, Limited Partnership (the "Partnership") (formerly Lakehead
Pipe Line Company, Limited Partnership), a Delaware limited partnership, was
formed in 1991 to acquire the pipeline business of Enbridge Energy Company,
Inc. (the sole "General Partner") (formerly Lakehead Pipe Line Company, Inc.),
which retained a 1% general partner interest.  Enbridge Energy Partners, L.P.,
a publicly traded limited partnership (the "Enbridge Partnership") (formerly
Lakehead Pipe Line Partners, L.P.), owns a 99% limited partner interest in the
Partnership.  The General Partner is a wholly-owned subsidiary of Enbridge
Pipelines Inc. ("Enbridge Pipelines"), a Canadian company owned by Enbridge
Inc. of Calgary, Alberta, Canada.

The Partnership is engaged in the transportation of crude oil and natural gas
liquids through a common carrier pipeline system. Substantially all of the
shipments delivered originate in western Canadian oil fields. The majority of
the shipments reach the Partnership at the Canada/United States border in North
Dakota, through a Canadian pipeline system owned by Enbridge Pipelines.
Deliveries are made in the Great Lakes region of the United States and to the
Province of Ontario, principally to refineries, either directly or through the
connecting pipelines of other companies.


2.  SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

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

REGULATION OF PIPELINE SYSTEM

As an interstate common carrier oil pipeline, rates and accounting practices are
under the regulatory authority of the Federal Energy Regulatory Commission
("FERC").

REVENUE RECOGNITION

Substantially all revenues are derived from the transportation of crude oil and
natural gas liquids ("NGLs") and are recognized in income upon delivery.

CASH AND CASH EQUIVALENTS

Cash equivalents are defined as all highly marketable securities with a maturity
of three months or less when purchased. They are accounted for as
held-to-maturity securities and valued at amortized cost.

OIL OVERAGE BALANCE

Represents oil owed to, or receivable from, customers of the pipeline system.
The balance also includes crude oil retained by the pipeline under terms of its
transportation tariff.

MATERIALS AND SUPPLIES

Materials and supplies are stated at cost.



                                       F-7
<PAGE>

2.  SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)


DEFERRED FINANCING CHARGES

Deferred financing charges are amortized on the 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 cost. Expenditures for system
expansion and major renewals and betterments are capitalized; maintenance and
repair costs are expensed as incurred. Interest incurred on external borrowings
during construction is capitalized. Depreciation of property, plant and
equipment is provided on the straight-line basis over estimated service lives.
When property, plant and equipment are disposed of, the cost less net proceeds
is normally charged to accumulated depreciation and no gain or loss on disposal
of property is recognized.

INCOME TAXES

The Partnership is not a taxable entity for federal and state income tax
purposes. Accordingly, no recognition has been given to income taxes for
financial reporting purposes. The tax on the Partnership's 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
reportable to the partners 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 Agreements. The aggregate
difference in the basis of the Partnership's net assets for financial and tax
reporting purposes cannot be readily determined because information regarding
each partner's tax attributes in the Enbridge Partnership is not available.

NET INCOME ALLOCATION

The allocation of net income to the partners is adjusted to reflect the
depreciation of property, plant and equipment on the General Partner's pro rata
historical cost basis for assets originally contributed on formation of the
Partnership.

DERIVATIVE FINANCIAL INSTRUMENTS

The Partnership recognizes all derivative financial instruments as assets and
liabilities and measures them at fair value. For derivatives financial
instruments that are designated and qualify as cash flow hedges, the effective
portions of changes in fair value of the derivatives are recorded in other
comprehensive income and are recognized in the income statement when the hedged
items affect earnings. Changes in the fair value of derivatives that do not
qualify for hedge treatment are recognized currently in earnings. The related
cash flows from those derivative financial instruments accounted for as hedges
are classified in the same category as the items being hedged.

Net income and cash flow are subject to volatility stemming mainly from changes
in interest rates. In order to manage the risks to the Partnership, the General
Partner uses derivative financial instruments to create offsetting positions to
interest rate exposures. These financial instruments are employed in connection
with an underlying asset, liability or anticipated transaction and are not used
for speculative purposes. In implementing its hedging programs, the General
Partner has established a formal analysis and execution framework that requires
the approval of the Board of Directors of the General Partner, or a committee of
senior management.

Derivative financial instruments are used to hedge against the effect of future
interest rate movements.

COMPARATIVE AMOUNTS

Certain reclassifications have been made to the prior years reported amounts to
conform to the classifications used in the 2001 financial statements. These
reclassifications have no impact on net income.


                                      F-8

<PAGE>

2.  SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)


NEW ACCOUNTING PRONOUNCEMENTS

In June 1998, the Financial Accounting Standards Board ("FASB") issued Statement
of Financial Accounting Standards ("SFAS") No. 133, "Accounting for Derivative
Instruments and Hedging Activities." This Statement requires that all
derivatives be recognized at fair value in the balance sheet and all changes in
fair value be recognized currently in earnings or deferred as a component of
other comprehensive income, depending on the intended use of the derivative. The
Partnership adopted SFAS No. 133 on January 1, 2001.

In June 2001, the FASB issued SFAS No. 141, "Business Combinations." This
Statement requires the use of the purchase method for all business combinations.
In addition, it requires the reassessment of intangible assets to determine if
they are appropriately classified either separately or within goodwill. This
Statement is effective for business combinations initiated after June 30, 2001.
The Partnership adopted SFAS No. 141 on July 1, 2001 with no impact on results
of operations, financial position or cash flows.

In July 2001, the FASB issued SFAS No. 142, "Goodwill and Other Intangible
Assets". Under SFAS No.142, goodwill and intangible assets with indefinite lives
will not be amortized but will be reviewed for impairment at least annually.
Intangible assets with finite lives will continue to be amortized over their
useful lives, which will not be limited to a maximum life of forty years. The
Partnership adopted SFAS No.142 on January 1, 2002. This standard will not have
an impact on results of operations, financial position or cash flows.

Also in July 2001, the FASB issued SFAS No. 143 "Accounting for Asset Retirement
Obligations" under which retirement obligations will be recognized at fair value
in the period they are incurred. 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. SFAS No.143 is effective for
fiscal years beginning after June 15, 2002. The Partnership is currently
evaluating the potential effects of adopting SFAS No. 143, on its financial
condition and results of operations.

In October 2001, the FASB issued SFAS No. 144, "Accounting for the Impairment or
Disposal of Long-Lived Assets". SFAS No. 144 establishes a single accounting
model for long-lived assets to be disposed of by sale. The Statement retains
most of the requirements in SFAS No. 121 related to the recognition of
impairment of long-lived assets to be held and used. The Partnership adopted
SFAS No. 144 on January 1, 2002. This standard is not expected to have a
material impact on results of operations, financial position or cash flows.


3.  CASH DISTRIBUTIONS

The Partnership distributes quarterly all of its "Available Cash", which is
generally defined in the Partnership Agreements 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. Distributions by the Partnership of its Available
Cash generally are made 99% to the Enbridge Partnership and 1% to the General
Partner.

In 2001, 2000 and 1999, the Partnership paid cash distributions of $115.0
million, $111.5 million and $108.4 million, respectively.



                                      F-9
<PAGE>

4.  PROPERTY, PLANT AND EQUIPMENT, NET

--------------------------------------------------------------------------------


                                             Depreciation
December 31,                                        Rates       2001        2000
--------------------------------------------------------------------------------
--------------------------------------------------------------------------------

Land                                                    -  $     6.4  $     6.4
Rights-of-way                                3.8% - 4.35%      109.8      109.8
Pipeline                                     3.6% - 4.35%      967.2      957.9
Pumping equipment, buildings and tanks       4.2% - 4.35%      475.6      470.1
Vehicles, office furniture and equipment    8.15% - 25.0%       36.7       34.3
Construction in progress                                -       25.9       10.0
--------------------------------------------------------------------------------
                                                             1,621.6    1,588.5
Accumulated depreciation                                      (367.7)    (306.6)
--------------------------------------------------------------------------------

                                                           $ 1,253.9  $ 1,281.9
================================================================================


Depreciation rates utilized by the Lakehead System were approved by the Federal
Energy Regulatory Commission, effective January 1, 1999, coinciding with the
in-service date for the Partnership's system expansion programs.


5.  DEBT

--------------------------------------------------------------------------------

December 31,                                                   2001        2000

First Mortgage Notes                                      $   310.0     $ 310.0
Revolving Credit Facility Agreement                           137.0       190.0
Senior Unsecured Notes, Net                                   299.4       299.3
--------------------------------------------------------------------------------
                                                          $   746.4     $ 799.3
Current portion                                               (31.0)         -
--------------------------------------------------------------------------------

                                                          $   715.4     $ 799.3
================================================================================

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 Partnership and
are due and payable in ten equal annual installments beginning December 2002.
The interest rate on the Notes is 9.15% per annum, payable semi-annually. 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 General Partner 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 3) 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.

REVOLVING CREDIT FACILITY AGREEMENT

As of December 31, 2001, the Partnership had a $350.0 million Revolving Credit
Facility Agreement scheduled to mature in September 2005. Upon drawdown, the
loans are secured by a first lien on the mortgaged property that ranks equally
with the Notes or may be fully collateralized with U.S. or Canadian government
securities. The facility contains restrictive covenants substantially identical
to those in the Note Agreements, provides for borrowing at variable interest
rates and has a facility fee of 0.10% (2000 - 0.10%) per annum on the entire
$350.0 million. At December 31, 2001, $137.0 million of the facility was
utilized and is classified as long-term debt (2000 - $190.0 million). The
interest rate on loans averaged 5.3% (2000 - 6.7%; 1999 - 5.4%) for the year and
was 2.3% at the end of 2001 (2000 - 6.2%).



                                      F-10
<PAGE>

5.  DEBT  (CONTINUED)

On January 29, 2002, the Partnership entered into two new bank credit facilities
to replace the $350.0 million Revolving Credit Facility. The new credit
facilities consist of a $300.0 million extendible revolving three-year term
credit facility which currently matures in January, 2005 and a $300.0 million
extendible revolving 364-day facility which currently matures in January 2003.
Under the terms of these facilities, the Enbridge Partnership may borrow funds
up to a combined maximum of $300.0 million under each facility. Obligations of
the Partnership under each of these facilities are guaranteed by the Operating
Partnership. Not more than annually and subject to lender approval, the maturity
date of both facilities may be extended by one year. Upon closing, indebtedness
under the $350.0 million Revolving Credit Facility was refinanced with
indebtedness drawn under the new credit facilities and the $350.0 million
Revolving Credit Facility was terminated.

SENIOR UNSECURED NOTES

The Partnership has issued a total of $300 million of senior unsecured notes.
The notes pay interest semi-annually and have varying maturities and terms as
outlined in the table below. The senior unsecured notes do not contain any
covenants restricting the issuance of additional indebtedness.

Senior Unsecured Notes
-------------------------------------------------------------------------------
                                            Interest
December 31,                                    Rate        2001         2000
-------------------------------------------------------------------------------

Notes maturing in 2012                        7.900%    $   100.0    $   100.0
Notes maturing in 2018                        7.000%        100.0        100.0
Notes maturing in 2028                        7.125%        100.0        100.0
Unamortized Discount                                         (0.6)        (0.7)
-------------------------------------------------------------------------------
                                                        $   299.4    $   299.3
===============================================================================

INTEREST

Interest expense is net of amounts capitalized of $0.3 million (2000 - $0.3
million; 1999 - $4.4 million). Interest paid amounted to $57.0 million (2000 -
$59.4 million; 1999 - $56.1 million).

DEBT SERVICE RESERVE

Under the terms of the First Mortgage Notes and the Revolving Credit Facility in
place at December 31, 2001, the Partnership is required to establish at the end
of each quarter a debt service reserve in an amount equal to 50% of the
prospective debt service payments for the immediately following calendar
quarter. At December 31, 2001, the debt service reserve was $1.0 million (2000 -
$0.8 million).

The aggregate long-term maturities for the five years ending December 31, 2002
through 2006 are $31 million per year of First Mortgage Notes and $137.0 million
borrowed on the Revolving Credit Facility in 2005.


6.  RELATED PARTY TRANSACTIONS

The Partnership, which does not have any employees, uses the services of the
General Partner and its affiliates for managing and operating its pipeline
business. These services, which are reimbursed at cost in accordance with
service agreements, amounted to $36.9 million (2000 - $30.3 million; 1999 -
$34.3 million) and are included in operating and administrative expenses. At
December 31, 2001, the Partnership has accounts receivable from the General
Partner and affiliates of $0.5 million. At December 31, 2000, the Partnership
had accounts receivable from the General Partner and affiliates of $1.5 million.

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 certain real property for the purpose of
granting pipeline easements to the Operating Partnership for construction of a
new pipeline, completed during 1998, by the Partnership from Superior, Wisconsin
to Chicago,



                                      F-11
<PAGE>

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.



6.  RELATED PARTY TRANSACTIONS  (CONTINUED)

As Enbridge Mustang disposes of the real property, the advances are repaid. The
advances amounted to $2.9 million at December 31, 2001 (2000 - $5.9 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 an agreement with Tidal Energy Marketing Inc.
("Tidal") of which Enbridge Inc. 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 the leasing of the Partnership's terminalling
and storage facility, consisting of nine 100,000 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 2001 the Partnership paid
Tidal a total of $0.3 million, (2000 $0.1 million).


7.  MAJOR CUSTOMERS

Operating revenue received from major customers was as follows:

------------------------------------------------------------------------------

Year ended December 31,                         2001        2000        1999
------------------------------------------------------------------------------

BP Canada Energy Company                     $   72.9    $   69.6    $   71.9
Mobil Oil Company of Canada Ltd.             $   56.8    $   48.3    $   42.2
PDV Midwest                                  $   21.4    $   33.7    $   23.7
Imperial Oil Limited                         $   24.0    $   23.3    $   33.3
==============================================================================

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 Operating Partnership's
pipeline and storage facilities.


8.  CONTINGENCIES

ENVIRONMENT

The Partnership is subject to federal and state laws and regulations relating to
the protection of the environment. Environmental risk is inherent to liquid
pipeline operations and the Partnership could, at times, be subject to
environmental cleanup and enforcement actions. The General Partner manages this
environmental risk through appropriate environmental policies and practices to
minimize the impact to the Partnership. To the extent that the Partnership is
unable to recover environmental costs in its rates, 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 the Lakehead System 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.

OIL IN CUSTODY

The Lakehead System transports crude oil and NGL 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.



                                      F-12
<PAGE>


9.  FINANCIAL INSTRUMENTS

FAIR VALUE OF FINANCIAL INSTRUMENTS

The carrying amounts of cash equivalents approximate fair value because of the
short-term maturities 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
Revolving Credit Facility approximate fair value, the fair value of the First
Mortgage Notes approximates $342.6 million (2000 - $346.5 million) and the fair
value of the Senior Unsecured Notes approximates $291.4 million (2000 - $290.3
million). Due to defined contractual make-whole arrangements, refinancing of the
First Mortgage Notes and Senior Unsecured Notes would not result in any
financial benefit to the Partnership.

FAIR VALUE OF DERIVATIVE FINANCIAL INSTRUMENTS

The Partnership enters into interest rate swaps to manage the effect of future
interest rate movements on its interest costs. These agreements, maturing July
2002, meet the criteria for hedge accounting and are treated as cash flow
hedges. On January 1, 2001, the Partnership recorded an unrealized loss of $0.1,
million charged to Other Comprehensive Income, representing the transition
adjustment for the cash flow hedges. During the year ended December 31, 2001,
this unrealized loss increased to $1.9 million due to revaluation of the
floating to fixed interest rate swaps and the entire amount is reflected in
Other Comprehensive Income.

Realized gains and losses on financial instruments used to hedge the
Partnership's exposure to changes in future interest rates are recognized
currently with the related interest expense.




                                      F-13

<PAGE>

                      ENBRIDGE ENERGY, LIMITED PARTNERSHIP

                      SUPPLEMENTARY INFORMATION (UNAUDITED)
                        SELECTED QUARTERLY FINANCIAL DATA
                              (Dollars in Millions)


<TABLE>
<CAPTION>
2001 QUARTERS                                              FIRST      SECOND        THIRD       FOURTH        TOTAL
-------------                                              -----      ------        -----       ------        -----
<S>                                                        <C>         <C>          <C>          <C>         <C>
Operating revenue.................................         $71.9       $80.1        $73.0        $79.0       $304.0
Operating income..................................         $24.7       $25.6        $19.4        $23.5        $93.2
Net income........................................         $10.2       $11.5         $6.0        $10.3        $38.0



2000 QUARTERS                                              FIRST      SECOND        THIRD       FOURTH        TOTAL
-------------                                              -----      ------        -----       ------        -----

Operating revenue.................................         $78.8       $78.3        $74.9        $73.6       $305.6
Operating income..................................         $33.3       $31.2        $29.0        $23.0       $116.5
Net income........................................         $20.3       $16.7        $14.4         $9.5        $60.9

</TABLE>



                                      F-14