<PAGE>   1
 
                                 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, 1998
 
                                       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: 1-10934
 
                       LAKEHEAD PIPE LINE PARTNERS, L.P.
             (Exact name of Registrant as specified in its charter)
 
<TABLE>
<S>                                            <C>
                  DELAWARE                                      39-1715850
       (State or other jurisdiction of                       (I.R.S. Employer
       incorporation or organization)                       Identification No.)
</TABLE>
 
                              LAKE SUPERIOR PLACE
                            21 WEST SUPERIOR STREET
                          DULUTH, MINNESOTA 55802-2067
             (Address of principal executive offices and zip code)
 
                                 (218) 725-0100
              (Registrant's telephone number, including area code)
                            ------------------------
 
          Securities registered pursuant to Section 12(b) of the Act:
 
<TABLE>
<S>                                            <C>
             Title of each class                 Name of each exchange on which registered
            CLASS A COMMON UNITS                          NEW YORK STOCK EXCHANGE
</TABLE>
 
        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]
 
     As of March 1, 1999, the aggregate market value of the Registrant's Class A
Common Units held by non affiliates of the Registrant was $965,384,000 based on
the reported closing sale price of such units on the New York Stock Exchange on
that date.
 
     As of March 1, 1999, there were 22,290,000 of the Registrant's Class A
Common Units outstanding.
                            ------------------------
 
                   DOCUMENTS INCORPORATED BY REFERENCE: NONE
<PAGE>   2
 
                               TABLE OF CONTENTS
 
<TABLE>
<CAPTION>
                                                                                PAGE
                                                                                ----
<S>             <C>                                                             <C>
                                       PART I
ITEMS 1 & 2.    Business and Properties.....................................      1
ITEM 3.         Legal Proceedings...........................................     11
ITEM 4.         Submission of Matters to a Vote of Security Holders.........     12
 
                                      PART II
ITEM 5.         Market for Registrant's Common Equity and Related
                Stockholder Matters.........................................     12
ITEM 6.         Selected Financial Data.....................................     13
ITEM 7.         Management's Discussion and Analysis of Financial Condition
                and Results   of Operations.................................     14
ITEM 7A.        Quantitative and Qualitative Disclosures About Market
                Risk........................................................     21
ITEM 8.         Financial Statements and Supplementary Data.................     22
ITEM 9.         Changes in and Disagreements with Accountants on Accounting
                and   Financial Disclosure..................................     22
 
                                      PART III
ITEM 10.        Directors and Executive Officers of the Registrant..........     22
ITEM 11.        Executive Compensation......................................     23
ITEM 12.        Security Ownership of Certain Beneficial Owners and
                Management..................................................     24
ITEM 13.        Certain Relationships and Related Transactions..............     24
 
                                      PART IV
ITEM 14.        Exhibits, Financial Statement Schedules and Reports on Form
                8-K.........................................................     25
SIGNATURES..................................................................     28
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:
 
     - the Partnership's dependence upon adequate supplies of and demand for
       western Canadian crude oil,
 
     - the price of crude oil and the willingness of shippers to ship crude oil
       when prices are low,
 
     - regulation of the Partnership's tariffs by the Federal Energy Regulatory
       Commission and the possibility of unfavorable outcomes of future tariff
       proceedings,
 
     - the Partnership's ability to complete Year 2000 readiness activities, and
 
     - 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 -- Business Risks"
included elsewhere in this Form 10-K.
<PAGE>   3
 
                                     PART I
 
ITEMS 1 & 2. BUSINESS AND PROPERTIES
 
OVERVIEW
 
     Lakehead Pipe Line Partners, L.P. is a publicly traded Delaware limited
partnership ("Registrant" or "Partnership"), which owns a 99% limited partner
interest in Lakehead Pipe Line Company, Limited Partnership ("Operating
Partnership"), also a Delaware limited partnership. Unless the context otherwise
requires, references in this Form 10-K to the Partnership include the Registrant
and the Operating Partnership.
 
     The Partnership was formed in 1991 to acquire, own and operate the
regulated crude oil and natural gas liquids pipeline business of Lakehead Pipe
Line Company, Inc. (the "General Partner"), a wholly-owned subsidiary of
Enbridge Pipelines Inc. ("Enbridge Pipelines" formerly Interprovincial Pipe Line
Inc.). Enbridge Pipelines is a Canadian company owned by Enbridge Inc.
("Enbridge" formerly IPL Energy Inc.) of Calgary, Alberta, Canada. The General
Partner owns a 14.8% limited partner interest (in the form of 3,912,750 Class B
Common Units) and a 1% general partner interest in the Registrant, as well as a
1% general partner interest in the Operating Partnership (an effective 16.6%
combined interest in the Partnership). The remaining 83.4% limited partner
interest in the Partnership is represented by 22,290,000 publicly traded Class A
Common Units.
 
     The Partnership and Enbridge Pipelines transport crude oil and other liquid
hydrocarbons for others through the world's longest liquid petroleum pipeline
system ("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 eastern Canada. The System serves all the major
refining centers in the Great Lakes region of the United States, as well as the
province of Ontario, Canada and the Patoka/Wood River refinery and pipeline hub
in southern Illinois. Various subsidiaries of Enbridge own the Canadian portion
of the System ("Enbridge Pipelines System") and the Partnership owns the U.S.
portion of the System ("Lakehead System").
 
     The System extends from Edmonton, Alberta, across the Canadian prairies to
the U.S. border near Neche, North Dakota. From Neche the System continues on to
Superior, Wisconsin, where it splits into two branches with one branch
travelling 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 on to Toronto,
Ontario and Montreal, Quebec, with lateral lines to Nanticoke, Ontario and the
Buffalo, New York area. The System is approximately 3,000 miles long, of which,
approximately 1,750 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 and 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, in the Great Lakes and Midwest regions of the United States
and the province of Ontario, 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 16 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.
 
                                        1
<PAGE>   4
 
PROPERTIES
 
     The Lakehead System consists of approximately 3,200 miles of pipe with
diameters ranging from 12 inches to 48 inches, 60 main line pump station
locations with a total of approximately 663,000 installed horsepower and 54
crude oil storage tanks with an aggregate working capacity of approximately nine
million barrels. The volume of liquid hydrocarbons in the Lakehead System
required at all times for operation is approximately 13 million barrels, all of
which is owned by the shippers on the Lakehead System. The Lakehead System
regularly transports up to 45 different types of liquid hydrocarbons including
light, medium and heavy crude oil (including bitumen), condensate, synthetic
crudes and natural gas liquids ("NGL").
 
     The Lakehead System is comprised of a number of separate segments as
follows:
 
     - Canadian border to Clearbrook segment including portions of four
       pipelines consisting of 18-, 20-, 26-, and 34-inch diameter pipe with a
       total annual capacity of 1,571,000 barrels per day. This segment includes
       approximately 40 miles of 48-inch pipeline looping that increases the
       annual capacity of this segment;
 
     - 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 1,337,000 barrels per day. This segment also
       includes approximately 80 miles of 48-inch pipeline looping;
 
     - Superior to Marysville segment consisting of 30-inch diameter pipe with
       an annual capacity of 509,000 barrels per day;
 
     - Superior to Chicago area segment including two pipelines of 24- and
       34-inch diameter pipe with a total annual capacity of 889,000 barrels per
       day;
 
     - Chicago area to Marysville segment that is a 30-inch diameter pipe with
       an annual capacity of 333,000 barrels per day;
 
     - Canadian border to Buffalo segment consisting of 12-inch diameter pipe
       with an annual capacity of 74,000 barrels per day.
 
     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. Lakehead System capacities set
forth above do not include the estimate of annual capacity upon completion of
Phase I of the Terrace Expansion Program ("Terrace") which is expected to be
completed in two stages during 1999. See "Item 7. Management's Discussion and
Analysis of Financial Condition and Results of Operations, -- Terrace Expansion
Program." Terrace will add an additional 170,000 barrels per day annual capacity
to the Lakehead System from the Canadian border to Superior. The properties
described above include facilities added during the System Expansion Program II
("SEP II") of the Lakehead System, consisting primarily of a new 24-inch
diameter pipeline from Superior to the Chicago area (approximately 450 miles).
This new pipeline, together with other pipeline system modifications, is
projected to provide approximately 170,000 barrels per day of additional
delivery capacity to the Midwest U.S. markets served by the Partnership. The new
pipeline has an ultimate potential capacity of 350,000 barrels per day through
the installation of additional pumping units. SEP II complements a Cdn. $160
million expansion of the Enbridge Pipelines System.
 
     The Partnership believes that the Lakehead System has been constructed and
is maintained in accordance with applicable federal, state and local laws and
regulations, standards prescribed by the American Petroleum Institute and
accepted industry practice. The Partnership attempts to control 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. On a bi-weekly basis, 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
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
required.
 
                                        2
<PAGE>   5
 
TITLE TO PROPERTIES
 
     The Partnership conducts business and owns properties located in seven
states. 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 pursuant to
easements or permits. An affiliate of the General Partner has acquired
properties for the benefit of the Partnership in connection with SEP II. 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 Operating Partnership.
 
BUSINESS RISKS
 
     The Lakehead System is dependent upon the level of supply of crude oil and
other liquid hydrocarbons from western Canada. Supply, in turn, is dependent
upon a number of variables, one of which is the price of crude oil. In recent
months, the price of crude oil has reached a twenty year low, resulting in
reduced throughput on the System. For a discussion of the forecast of the future
supply of crude oil produced in western Canada, see "-- Supply 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 products into the same areas. Existing pipeline capacity for the
delivery of crude oil to the Midwest U.S., the primary destination market served
by the Lakehead System, exceeds current refining capacity. The Partnership
believes that the System has certain 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."
 
     Enbridge Pipelines is in the process of modifying a pipeline segment from
Sarnia, Ontario to Montreal, involving a reversal of a line to bring crude oil
from Montreal to Sarnia ("Montreal Extension" or "Line 9"). The line reversal
will result in Enbridge Pipelines becoming a competitor of the Partnership for
supplying crude oil to the Ontario market which is anticipated to decrease the
level of deliveries into the Ontario market. See "Item 7. Management's
Discussion and Analysis of Financial Condition and Results of Operations,
-- Montreal Extension Reversal."
 
     The Partnership cannot predict the impact of future economic conditions,
fuel conservation measures, alternative fuel requirements, governmental
regulation or technological advances in fuel economy and energy generation
devices, all of which could reduce the demand for crude oil and other liquid
hydrocarbons in the areas in which deliveries are made by the Lakehead System.
In addition, reduced throughput on the System could result from testing, line
repair, reduced operating pressures, reduced crude oil supply or other causes.
 
     The operations of the Partnership are subject to federal and state laws and
regulations relating to environmental protection and operational safety.
Although the Partnership believes that the operations of the Lakehead System are
in substantial compliance with applicable environmental and safety regulations,
risks of substantial costs and liabilities are inherent in pipeline operations,
and there can be no assurance that such costs and liabilities will not be
incurred, see "-- Environmental and Safety Regulation."
 
     The Partnership filed a rate increase with the Federal Energy Regulatory
Commission ("FERC") in late 1998 to reflect the projected incremental costs and
throughput resulting from SEP II. A Tariff Agreement previously reached between
the Partnership and customer representatives sets forth parameters governing the
tariff increase associated with SEP II, Terrace, and other expansion projects,
although individual customers who are not parties to the agreement could
potentially challenge any existing or future rate filing. 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."
 
                                        3
<PAGE>   6
 
REGULATION
 
FERC Regulation
 
     The Partnership's interstate common carrier pipeline operations are subject
to rate regulation by the FERC under the version of the Interstate Commerce Act
("ICA") applicable to oil pipelines. The ICA requires that petroleum products
and crude oil 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 if the FERC chooses
to suspend the proposed change as it is empowered to do 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 certain
circumstances, to possible 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 Producer Price Index
for Finished Goods minus 1% ("PPIFG-1"). Rate ceiling levels are increased or
decreased each July 1. The PPIFG-1 for use on July 1, 1998, was approximately
negative 0.6%. Inflationary rate increases allowed under the FERC's indexing
methodology may be different than increases 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 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, 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
the following components:
 
     - operating expenses,
 
     - depreciation and amortization,
 
     - federal and state income taxes and
 
     - an overall allowed rate of return on the pipeline's rate base.
 
     During the period 1992 to 1995, the Partnership implemented several rate
filings in accordance with this methodology, see "-- Tariffs, -- Rate Cases." 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 with respect to 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. 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.
 
                                        4
<PAGE>   7
 
TARIFFS
 
Rate Cases
 
     The Partnership had several rate cases pending before the FERC during the
period from 1992 to 1996. The primary issue included the applicability of the
FERC's Opinion 154-B/C trended original cost methodology. 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 individual limited partners.
 
     In 1996, the FERC approved a settlement agreement ("Settlement Agreement")
between the Partnership, the Canadian Association of Petroleum Producers
("CAPP") and the Alberta Department of Energy ("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. The Partnership made rate refunds of $41.8
million in the fourth quarter of 1996, with the balance being paid through a 10%
reduction of tariff rates until all refunds have been made, which is expected to
occur sometime late in the second half of 1999. At December 31, 1998, the
remaining liability for rate refunds was $28.7 million.
 
     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 rate of return on the Partnership's investment in, SEP II. The rate of return
on this investment will be based, in part, on the utilization level of the
additional capacity constructed. As specified in the Settlement Agreement,
higher utilization will result 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 will be recomputed on a cost of service basis and filed with FERC each
year. The Settlement Agreement provided that the agreed underlying tariff rates
will be subject to indexing as prescribed by FERC regulation and that CAPP and
ADOE will not challenge any rates within the indexed ceiling for a period of
five years, expiring October 2001.
 
Tariff Agreement
 
     In 1998, the Partnership filed an offer of settlement ("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 with
respect to 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 will be allocated approximately Cdn. $0.02 ($0.013 U.S.) to the
Partnership and Cdn. $0.03 to Enbridge Pipelines. The toll increase is also
subject to increase or decrease based on changes in certain defined
circumstances. The portion of the agreement associated with Terrace also
establishes in-service and notice dates for future phases of the expansion
program. Should CAPP not provide notice to construct later phases of Terrace by
July 1, 2001, the toll increment will revert to a cost of service recovery,
including collection of both prospective and past variances between revenue
generated by the Cdn. $0.05 toll increment and the Terrace cost of service.
 
Other Pipeline Rate Cases
 
     On January 13, 1999, the FERC issued an opinion and order in the Santa Fe
Pacific Pipeline, L.P. ("SFPP") case that addressed various issues of interest
to FERC-regulated publicly traded partnerships and other oil pipelines including
application of FERC's Opinion No. 154-B/C rate methodology and income tax
allowances for publicly traded partnerships. The SFPP opinion is anticipated to
have no impact on the Partnership's current rates due to the Tariff Agreement
with customers. If the SFPP opinion were applied to
 
                                        5
<PAGE>   8
 
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.
 
     Many of the ratemaking issues contested in the Partnership's rate cases, in
particular the FERC's own oil pipeline ratemaking methodology, have not
previously been reviewed by a federal appellate court. Any decision ultimately
rendered by the FERC on any rate case involving its oil pipeline ratemaking
methodology, including the recent SFPP decision, may be subject to judicial
review. Any such judicial review could ultimately result in alternative
ratemaking methodologies that could have a material adverse effect on the
Partnership.
 
Tariffs
 
     Under published tariffs for transportation by the Lakehead System, the
rates for light crude oil from the Canadian border near Neche to principal
delivery points at January 1, 1999 (including a tariff surcharge related to SEP
II) are set forth below. As previously discussed, the Partnership's published
tariffs are subject to a 10% reduction; the tariffs less this 10% reduction are
also set forth below.
 
<TABLE>
<CAPTION>
                                                       PUBLISHED         PUBLISHED
                                                         TARIFF      TARIFF PER BARREL
                                                       PER BARREL    LESS 10% REDUCTION
                                                       ----------    ------------------
<S>                                                    <C>           <C>
Clearbrook, Minnesota..............................      $0.165            $0.149
Superior, Wisconsin................................      $0.318            $0.286
Chicago, Illinois area.............................      $0.647            $0.582
Canadian border near Marysville, Michigan..........      $0.747            $0.672
Buffalo, New York area.............................      $0.792            $0.713
</TABLE>
 
     The rates at January 1, 1999, for medium and heavy crude oils are higher,
while 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
a tariff surcharge for Terrace during the first half of 1999 of an estimated
$0.013 per barrel for light crude oil to the Chicago market. See "-- Tariffs,
-- Tariff Agreement."
 
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 oils and NGL transported by the Lakehead System
are feedstock for refineries and petrochemical plants.
 
     The U.S. government segregates the United States into five districts,
Petroleum Administration for Defense Districts ("PADD"), 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. 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 maintain or exceed its current level of deliveries into PADD 2.
 
                                        6
<PAGE>   9
 
     The following table sets forth Lakehead System average deliveries per day
and barrel miles for each of the years in the five-year period ending December
31, 1998.
 
<TABLE>
<CAPTION>
                                                                            DELIVERIES
                                                             -----------------------------------------
                                                             1998     1997     1996     1995     1994
                                                             ----     ----     ----     ----     ----
                                                                  (THOUSANDS OF BARRELS PER DAY)
<S>                                                          <C>      <C>      <C>      <C>      <C>
UNITED STATES
  Light crude oil........................................      338      282      309      345      335
  Medium and heavy crude oil.............................      627      652      569      513      452
  NGL....................................................       27       26       23       18        8
                                                             -----    -----    -----    -----    -----
  Total United States....................................      992      960      901      876      795
                                                             -----    -----    -----    -----    -----
EASTERN CANADA
  Light crude oil........................................      366      355      348      332      321
  Medium and heavy crude oil.............................       97       98      102       96      108
  NGL....................................................      107       99      100      105      102
                                                             -----    -----    -----    -----    -----
  Total Eastern Canada...................................      570      552      550      533      531
                                                             -----    -----    -----    -----    -----
TOTAL DELIVERIES.........................................    1,562    1,512    1,451    1,409    1,326
                                                             =====    =====    =====    =====    =====
BARREL MILES (billions per year).........................      391      389      384      385      366
                                                             =====    =====    =====    =====    =====
</TABLE>
 
     See "Item 7. Management's Discussion and Analysis of Financial Condition
and Results of Operations, -- Montreal Extension Reversal."
 
SUPPLY AND DEMAND FOR WESTERN CANADIAN CRUDE OIL
 
Supply
 
     Substantially all of the shipments delivered through the Lakehead System
originate in oilfields in western Canada. The Lakehead System also receives U.S.
and Canadian production at Clearbrook through a connection with a pipeline owned
by a subsidiary of Enbridge, U.S. production at Stockbridge and Lewiston,
Michigan, and both U.S. and offshore production in the Chicago area. Changes in
supply from western Canada would directly affect movements through the Enbridge
Pipelines System and, therefore, the supply available for transportation through
the Lakehead System.
 
     Enbridge Pipelines applied to the National Energy Board of Canada ("NEB")
in December 1997 to construct its Terrace Phase I facilities in Canada which
would complement the Terrace Phase I facilities to be constructed by the
Partnership in the United States. As part of that application, Enbridge
Pipelines submitted a forecast of supply of western Canadian crude oil and a
projection of the markets in which it could be reasonably expected to be
consumed. Forecasts by their nature are based upon numerous assumptions,
including estimates provided by industry, many of which are beyond the control
of Enbridge Pipelines or the Partnership. The forecast submitted to the NEB in
1997 showed the supply of western Canadian crude oil in the year 2003 at over
2,550,000 barrels per day, approximately 500,000 barrels per day above 1997
average daily production of western Canadian crude oil. The supply of western
Canadian crude oil was expected to remain at over 2,500,000 barrels per day
through 2010. While acknowledging the uncertainty associated with forecasts of
the supply of crude oil and other commodities shipped on the Enbridge Pipelines
System, the NEB accepted as reasonable the forecasts of the supply of crude oil
and other commodities submitted by Enbridge Pipelines and recommended that a
certificate for construction be issued. The forecast quantity of crude oil was
made subject to numerous uncertainties and assumptions, including a crude oil
price of $17.50 per barrel in 1998 rising to $22.25 in 2010.
 
     At December 31, 1998, the benchmark West Texas Intermediate ("WTI") crude
oil price closed at $12.05 per barrel, up from the 1998 low of $10.73 per
barrel. This lower crude oil price, compared to that assumed in the 1997
forecast, has impacted the crude oil supply available in western Canada.
Enbridge Pipelines has recently completed its updated forecast of western
Canadian crude oil supply and markets for western Canadian crude oil. This
long-term outlook is partially based on supply projections from the oil sands
                                        7
<PAGE>   10
 
projects currently operating, being expanded or proposed in western Canada. The
Partnership believes that production from these projects is less sensitive to
the price of crude oil due to the size and committed capital expenditures
involved. The updated forecast projects the supply of western Canadian crude oil
to be lower during the period 1999 through 2002 than the Terrace forecast by
approximately 120,000 to 190,000 barrels per day. The forecast supply of western
Canadian crude oil is projected to recover to 2,500,000 barrels per day in 2003,
rising to over 2,600,000 barrels per day from 2004 through 2010. The updated
forecast assumes a WTI crude oil price of $14.50 per barrel in 1999, $19.50 in
2003, and $23.00 in 2010.
 
     As a result of the decline in crude oil prices, it is anticipated that 1999
deliveries on the Lakehead System could be approximately 50,000 to 75,000
barrels per day (on average) less than 1998 delivery levels of 1,562,000 barrels
per day, a trend which could continue into the year 2000.
 
     Despite the downturn in crude oil prices and deliveries, the Partnership
believes that the outlook regarding future growth prospects continues to be
positive and that the potential for increased crude oil production in western
Canada remains substantial. The timing of growth in supply of western Canadian
crude oil, however, will be dependent upon recovery of crude oil prices.
 
Demand
 
     Rising crude oil demand and declining inland U.S. domestic production are
contributing to an increasing need for importing crude oil into the PADD 2
market. The Partnership believes that PADD 2 will continue to provide an
excellent market for western Canadian shippers as returns to crude oil producers
are expected to remain 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 greatest potential for converting refining capacity from light
to heavy crude.
 
     Although western Canadian producers experience competition from Venezuelan
and Mexican heavy crude oil in PADD 2, western Canadian heavy crude oil is
expected to remain the dominant supply source for the region. Latin American
heavy crude oil will continue to provide the swing supply to the PADD 2 region.
In the short-term, Latin American deliveries to PADD 2 are expected to increase
due to reduced supply of western Canadian crude oil resulting from low crude oil
prices and producer returns. However, over the long-term, it is expected that
producers of Latin American heavy crude oil will concentrate on PADD 3 and PADD
5 markets, where they receive a higher return than compared to PADD 2.
 
     Based on the recent forecast completed by Enbridge Pipelines, exports from
western Canada to the United States are forecast to increase to approximately
1,800,000 barrels per day in 2005 and remain at that level or above through
2010. This is approximately 700,000 barrels per day higher than 1997 exports. Of
the exports to the United States, PADD 2 would receive approximately 1,470,000
barrels per day in 2005, approximately 600,000 barrels per day higher than 1997.
Exports to PADD 2 would rise to approximately 1,540,000 barrels per day in 2007
and decline to approximately 1,430,000 barrels per day by 2010. Although in 1999
exports on the System to PADD 2 are anticipated to be marginally lower than
1998, recovery is expected in 2001 with long-term exports surpassing Terrace
forecast levels by 2005. Current low crude oil prices are expected to delay
supply and market growth for western Canadian crude oil by approximately one to
two years.
 
     Deliveries to eastern Canada averaged approximately 570,000 barrels per day
in 1998. Demand in eastern Canada is expected to grow to approximately 640,000
barrels per day over the next several years. Partnership deliveries to eastern
Canada are, however, expected to decline due to the reversal of Enbridge's Line
9 from Montreal to Sarnia. See "Item 7. Management's Discussion and Analysis of
Financial Condition and Results of Operations, -- Montreal Extension Reversal."
 
     Crude oil refineries in eastern Canada are generally configured to process
light sweet and light sour crude oil. While Canadian crude oil supplies have
increased over the last several years, the supply of conventional light sweet
and light sour crude oil in western Canada is expected to decline. Eastern
Canadian refiners cannot process significantly greater amounts of western
Canadian heavy crude oil without substantial reconfiguration of their
refineries. To the extent eastern Canadian refiners have found it difficult to
obtain light crude oil supply from western Canada at an economic price, refiners
have been recently accessing U.S. and imported
 
                                        8
<PAGE>   11
 
light crude volumes through Lakehead System pipeline connections in the Chicago
area. Light crude oil movements originating in the Chicago area for delivery to
eastern Canada have increased from approximately 70,000 barrels per day in 1997
to approximately 110,000 barrels per day in 1998. These movements are expected
to decline following the reversal of the Enbridge's Line 9 in 1999.
 
CUSTOMERS
 
     The Lakehead System operates under month-to-month transportation
arrangements with its shippers. During 1998, 48 shippers tendered crude oil and
NGL for delivery through the Lakehead System. These customers included
integrated oil companies with production facilities in western Canada and
refineries in eastern Canada, major oil companies, refiners and marketers.
Shipments by the top ten shippers during 1998 accounted for approximately 80% of
total revenues during that period. Revenue from Amoco (through affiliated
companies), Mobil Oil Company of Canada Ltd. and Imperial Oil Limited accounted
for approximately 20%, 14% and 12%, respectively, of total operating revenue
generated by the Lakehead System during 1998. The remaining shippers each
accounted for less than 10% of total revenues.
 
CAPITAL EXPENDITURES
 
     In 1998, the Partnership made capital expenditures of $487.3 million, of
which $470.7 million was for its two expansion programs SEP II and Terrace and
$16.6 million was for other projects including core maintenance of $7.2 million.
See "Item 7. Management's Discussion and Analysis of Financial Condition and
Results of Operations, -- SEP II, -- Terrace Expansion Program."
 
TAXATION
 
     For federal and state income tax purposes, the Partnership and Operating
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 1998 the Enbridge Pipelines System transported approximately 65%
of total western Canadian crude oil production, of which more than 90% was
transported by the Lakehead System. The remainder of 1998 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 70% of the total pipeline design
capacity. The remaining 30% of design capacity is shared by five other pipelines
transporting crude oil to British Columbia, Washington, Montana and other states
in the Northwest U.S.
 
     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.
 
     Express Pipeline Ltd. ("Express Pipeline"), a joint venture between Alberta
Energy Company, Ltd. and TransCanada PipeLines Limited, owns and operates a
170,000 barrel per day capacity pipeline that carries western Canadian crude oil
to the U.S. Rocky Mountain region, where it connects to a 150,000 barrels per
day capacity pipeline system. This connecting pipeline serves the Patoka/Wood
River market area. Express Pipeline began service in early 1997. The General
Partner believes, however, that the System is more attractive to western
Canadian producers shipping to the Chicago or Patoka/Wood River market area as
it offers lower tolls and shorter transit times than Express Pipeline and does
not require shipper volume commitments as currently required by Express
Pipeline.
                                        9
<PAGE>   12
 
     The System encounters competition in serving shippers to the extent that
shippers have alternate 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 Washington State 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 45% of all crude oil deliveries into the Chicago area,
approximately 75% of all crude oil deliveries into the Minneapolis-St. Paul area
and virtually all deliveries of crude oil to Ontario.
 
     Please refer to "Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations, -- Montreal Extension Reversal," for
discussion of a planned reversal of the Montreal Extension that will result in
Enbridge Pipelines becoming a competitor of the Lakehead System for supplying
crude oil to the Ontario market.
 
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 are inherent in pipeline
operations, and there can be no assurance that substantial liabilities will not
be incurred. To the extent that the Partnership is unable to recover
environmental costs in its rates or 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. Such
expenditures cannot be accurately estimated at this time, although the
Partnership does not expect that they will have a material adverse effect on the
Partnership.
 
Air
 
     The operations of the Partnership are subject to the federal Clean Air Act
and comparable state statutes.
 
Water
 
     The federal Water Pollution Control Act, as amended by the Oil Pollution
Act of 1990 ("WPCA"), imposes strict controls on the discharge of oil into
navigable waters. The WPCA provides penalties for any discharges of petroleum
products in reportable quantities, imposes liability for clean-up costs and
natural resource damage, and allows for third party lawsuits. State laws also
provide varying civil and criminal penalties and liabilities in the case of a
release of petroleum into surface water or groundwater. Spill prevention control
and countermeasure requirements of federal laws require diking and similar
structures to help prevent contamination of navigable waters in the event of a
petroleum overflow, rupture or leak. In response to regulations mandated by the
WPCA, the Partnership has submitted to the Office of Pipeline Safety ("OPS") of
the U.S. Department of Transportation ("DOT") oil spill emergency response
plans, which have been approved, and a certification that it has the resources
to respond to a worst case spill. Expenses of routine compliance with these and
other similar regulations are not expected to have a material adverse impact on
the Partnership.
 
                                       10
<PAGE>   13
 
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 Partnership is addressing known sites through
monitoring and remediation programs.
 
Superfund
 
     The Comprehensive Environmental Response, Compensation and Liability Act of
1989, 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 contributed to the release of a "hazardous
substance" into the environment. In the course of its ordinary operations, the
Lakehead System generates 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.
 
Waste
 
     The Partnership generates hazardous and nonhazardous solid wastes that are
subject to requirements of the federal Resource Conservation and Recovery Act
and comparable state statutes. The Partnership believes that operations of the
Lakehead System are in substantial compliance with such statutes in all states
in which it operates. The Environmental Protection Agency ("EPA") is currently
in the process of developing stricter disposal standards for nonhazardous waste.
 
Safety Regulation
 
     The Partnership's operations are subject to construction, operating and
safety regulation by the DOT and various other federal, state and local
agencies. The Pipeline Safety Act of 1992, as amended by the Accountable
Pipeline Safety and Partnership Act of 1996, requires the OPS to consider
environmental impacts and do a risk assessment, as well as satisfy its
traditional public safety mandate, when developing pipeline safety regulations.
The Act also mandates the OPS to establish pipeline operator qualification
rules, requires pipeline operators to provide maps and records to the OPS, and
authorizes the OPS to require pipelines to be modified to accommodate internal
inspection devices. Regulations issued pursuant to the Act require pipeline
operators to implement drug and alcohol testing programs for employees and
contractors that are engaged in safety-sensitive activities. Additional
legislation or regulations have been proposed requiring remotely controlled
shutoff valves in populated or environmentally sensitive areas, increased public
education of pipeline safety and accident prevention and periodic integrity
testing of pipelines by internal inspection or hydrostatic testing. The
Partnership currently has an integrity testing program utilizing internal
inspection devices and has conducted additional hydrostatic testing for selected
segments of the Lakehead System. The Partnership is also subject to the
requirements of federal and state Occupational Safety and Health Acts.
 
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 certain of its subsidiaries to provide the required services.
The Partnership reimburses the General Partner or its affiliates for expenses
incurred in performing these services at cost.
 
ITEM 3. LEGAL PROCEEDINGS
 
     The Partnership is a defendant in various lawsuits and a party to various
legal proceedings arising in the ordinary course of business. Some of these
lawsuits and proceedings are covered, in whole or in part, by insurance. The
Partnership believes that the outcome of all these lawsuits and proceedings will
not, individually or in the aggregate, have a material adverse effect on the
financial condition of the Partnership. In connection with the transfer of its
pipeline business to the Partnership, the General Partner agreed to indemnify
the Partnership from and against substantially all liabilities, including
liabilities relating to
                                       11
<PAGE>   14
 
environmental matters, arising from operations prior to the transfer. This
indemnification does not apply to amounts that the Partnership would be able to
recover in its tariffs, through insurance, or to any liabilities relating to a
change in laws after December 27, 1991.
 
     In late July 1998, the Partnership's directional drilling operations for
SEP II construction caused a discharge of non-hazardous bentonite drilling mud
in a wetlands area. The Partnership does not believe that any penalties that
might be assessed by the EPA will have a material impact on the financial
condition of the Partnership. The State of Illinois is pursuing an action
relating to this discharge under Natural Resource Damage Assessment regulations
of the Clean Water Act to seek compensation for damage to the wetlands area. It
is expected that a settlement will be reached with the State to resolve the
matter and that it will not have a material impact on the financial condition of
the Partnership.
 
     In a letter dated August 19, 1998, the Illinois Attorney General informed
the Partnership that it is seeking a penalty of $135,000 for a May 28, 1998,
release of crude oil caused by a third party in Orland Park, Illinois. The
Partnership and the Attorney General are in negotiations on this matter.
 
     The Partnership received a Notice of Violation, dated October 29, 1998,
from the Wisconsin Department of Natural Resources ("Wisconsin DNR") that
alleges the Partnership failed to monitor discharges of water from SEP II
construction trenches on certain occasions and exceeded the effluent limitations
set forth in a permit The Partnership has submitted its reply to the notice and
intends to cooperate with the Wisconsin DNR in an effort to resolve the issue
and any penalties that may ensue. It is not anticipated that any penalty will
have a material impact on the financial condition of the Partnership.
 
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
 
     No matters were submitted to a vote of security holders during the fourth
quarter of 1998.
 
                                    PART II
 
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
 
     The Partnership's Class A Common Units are listed and traded on the New
York Stock Exchange, the principal market for the Class A Common Units, under
the symbol LHP. The quarterly price range per Class A Common Unit and cash
distributions paid per unit for 1998 and 1997 are summarized below:
 
<TABLE>
<CAPTION>
                                                             FIRST              SECOND              THIRD              FOURTH
                                                             -----              ------              -----              ------
<S>                                                      <C>   <C>         <C>   <C>           <C>   <C>           <C>   <C>
1998 QUARTERS
  High...............................................    $  46 3/4         $  49 15/16         $  52 7/16          $  54
  Low................................................    $  43             $  44 5/16          $  46 11/16         $  46 3/4
  Cash distributions paid............................    $0.78             $0.86               $0.86               $0.86
</TABLE>
 
<TABLE>
<CAPTION>
                                                             FIRST              SECOND              THIRD              FOURTH
                                                             -----              ------              -----              ------
<S>                                                      <C>   <C>         <C>   <C>           <C>   <C>           <C>   <C>
1997 QUARTERS
  High...............................................    $  38 3/4         $  39               $  47 3/4           $  47 7/8
  Low................................................    $  33             $  33 7/8           $  38               $  38 3/8
  Cash distributions paid............................    $0.68             $0.68               $0.78               $0.78
</TABLE>
 
     On March 1, 1999, the last reported sales price of the Class A Common Units
on the New York Stock Exchange was $43 5/16. At March 1, 1999, there were
approximately 39,000 Class A Common Unitholders of which there were
approximately 3,600 registered Class A Common Unitholders of record. There is no
established public trading market for the Partnership's Class B Common Units,
all of which are held by the General Partner.
 
                                       12
<PAGE>   15
 
ITEM 6. SELECTED FINANCIAL DATA
 
     The following table sets forth, for the periods and at the dates indicated,
summary historical financial and operating data for the Partnership. The table
is derived from the consolidated financial statements of the Partnership and
notes thereto, and should be read in conjunction with those audited financial
statements.
 
<TABLE>
<CAPTION>
                                                                YEAR ENDED DECEMBER 31,
                                                --------------------------------------------------------
                                                  1998        1997      1996(1)     1995(1)       1994
                                                  ----        ----      -------     -------       ----
                                                     (DOLLARS IN MILLIONS, EXCEPT PER UNIT AMOUNTS)
<S>                                             <C>         <C>         <C>         <C>         <C>
INCOME STATEMENT DATA:
  Operating revenue...........................  $  287.7    $  282.1    $  274.5    $  268.5    $  246.0
  Operating expenses(2).......................     182.3       174.0       187.1       195.2       159.7
                                                --------    --------    --------    --------    --------
  Operating income............................     105.4       108.1        87.4        73.3        86.3
  Interest and other income...................       6.0         9.7         9.6         7.1         4.1
  Interest expense............................     (21.9)      (38.6)      (43.9)      (40.3)      (29.8)
  Minority interest...........................      (1.0)       (0.9)       (0.7)       (0.5)       (0.7)
                                                --------    --------    --------    --------    --------
  Net income..................................  $   88.5    $   78.3    $   52.4    $   39.6    $   59.9
                                                ========    ========    ========    ========    ========
  Net income per unit(3)......................  $   3.07    $   3.02    $   2.11    $   1.60    $   2.61
                                                ========    ========    ========    ========    ========
  Cash distributions paid per unit............  $   3.36    $   2.92    $   2.60    $   2.56    $   2.51
                                                ========    ========    ========    ========    ========
FINANCIAL POSITION DATA (AT YEAR END):
  Property, plant and equipment, net..........  $1,296.2    $  850.3    $  763.5    $  725.1    $  727.6
  Total assets................................  $1,414.4    $1,063.2    $  975.9    $  915.2    $  868.6
  Long-term debt..............................  $  814.5    $  463.0    $  463.0    $  395.0    $  364.0
  Partners' capital
     Class A Common Unitholder................  $  453.4    $  461.6    $  376.3    $  387.9    $  409.3
     Class B Common Unitholder................      37.3        36.7        21.7        21.7        23.5
     General Partner..........................       4.3         3.5         1.6         1.5         1.6
                                                --------    --------    --------    --------    --------
                                                $  495.0    $  501.8    $  399.6    $  411.1    $  434.4
                                                ========    ========    ========    ========    ========
CASH FLOW DATA:
  Cash provided from operating activities.....  $  103.6    $  106.6    $   93.9    $  121.5    $  108.1
  Cash used in investing activities...........  $ (427.9)   $ (101.7)   $  (84.7)   $  (54.0)   $ (102.7)
  Cash provided from (used in) financing
     activities...............................  $  252.7    $   24.1    $    3.4    $  (32.5)   $   27.7
  Capital expenditures included in investing
     activities...............................  $ (487.3)   $ (126.9)   $  (76.7)   $  (35.5)   $ (136.9)
OPERATING DATA:
  Barrel miles (billions).....................       391         389         384         385         366
  Deliveries
     (thousands of barrels per day)
     United States............................       992         960         901         876         795
     Eastern Canada...........................       570         552         550         533         531
                                                --------    --------    --------    --------    --------
                                                   1,562       1,512       1,451       1,409       1,326
                                                ========    ========    ========    ========    ========
</TABLE>
 
---------------
(1) 1996 results reflect the impact of the Settlement Agreement between the
    Partnership and customer representatives on all outstanding contested tariff
    rates. 1995 results reflect the impact of a June 1995 FERC decision.
 
(2) Operating expenses include provisions for prior years' rate refunds of $20.1
    million and $22.9 million in 1996 and 1995, respectively.
 
(3) The General Partner's allocation of net income has been deducted before
    calculating net income per unit as follows: 1998, $8.0 million; 1997, $4.4
    million; 1996, $1.6 million; 1995, $1.2 million; and 1994, $1.4 million.
 
                                       13
<PAGE>   16
 
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
        OF OPERATIONS
 
     1998 was a successful year for the Partnership as record net income and
crude oil deliveries were achieved despite a decline in world crude oil prices.
The strong performance of the Partnership during 1998, coupled with expectations
for strong long-term performance, influenced the Board of Directors of the
General Partner to increase the quarterly cash distribution on April 16, 1998 to
$0.86 per unit ($3.44 on an annualized basis) from $0.78 per unit. This most
recent increase in the distribution is primarily the result of earnings growth
from capacity expansions.
 
     Challenges encountered by the Partnership during construction of the $450
million System Expansion Program II ("SEP II") were overcome and the targeted
completion date of first quarter 1999 was met. During December 1998, the process
of filling the new pipeline with crude oil was begun and deliveries from the new
line will commence in March 1999. A tariff increase associated with the new line
was filed with the Federal Energy Regulatory Commission ("FERC") in late
December and became effective on January 1, 1999. See "-- SEP II".
 
     The Partnership, together with Enbridge Pipelines Inc., of Edmonton,
Alberta, ("Enbridge Pipelines" formerly Interprovincial Pipe Line Inc.), began
construction of the first phase of the Terrace Expansion Program ("Terrace") in
1998. Terrace is a multi-phase program that will eventually add approximately
350,000 barrels per day of pipeline system delivery capability with the first
phase of 170,000 barrels per day expected to be operational by September 1999.
The remaining capacity may be added at customer request in stages over the next
several years. See "-- Terrace Expansion Program".
 
     Deliveries by the Partnership of crude oil and natural gas liquids ("NGL")
increased 3% over the previous record levels attained in 1997. In late 1998, the
Partnership began experiencing a decline in the level of crude oil deliveries
compared with the first half of 1998. Producers of crude oil throughout North
America began reducing production of less profitable crude oil due to the
significant drop in world crude oil prices. At December 31, 1997, the benchmark
West Texas Intermediate ("WTI") crude oil price was $17.83 per barrel. At
December 31, 1998 the reference WTI price closed at $12.05 per barrel, up from
the 1998 low of $10.73.
 
     While utilization of the Partnership's pipeline system historically has
been fairly insensitive to modest changes in the price of crude oil, the current
world crude oil price situation is anticipated to impact the supply of available
crude oil and the Partnership's short-term results. Despite this forecast
decrease in crude oil deliveries, the Partnership anticipates generating more
than sufficient cash from operating activities to continue its current level of
distribution through 1999. See "-- Future Prospects."
 
RESULTS OF OPERATIONS
 
     Net income for 1998 was $88.5 million ($3.07 per unit) compared with $78.3
million ($3.02 per unit) for 1997 and $52.4 million ($2.11 per unit) for 1996.
Net income for 1996 was impacted by rate refunds ($20.1 million) and related
interest expense ($3.2 million) attributable to prior years recorded in response
to a settlement agreement (the "Settlement Agreement") between the Partnership
and certain customer representatives that concluded a dispute that began in 1992
concerning the Partnership's tariff rates. See "Items 1 & 2. Business and
Properties, -- Tariffs, -- Rate Cases."
 
     Crude oil and NGL deliveries averaged a record 1,562,000 barrels per day in
1998, up from the 1,512,000 barrels per day averaged during 1997, a 3% growth in
Lakehead System deliveries. Crude oil and NGL deliveries increased 4% during
1997 when compared with 1996 results. Over the three-year period, increased
deliveries resulted from greater crude oil production in western Canada,
increased transportation of foreign and U.S. crude received in the Chicago area,
combined with increased pipeline capacity from the Partnership's expansion
programs. System utilization measured in barrel miles was relatively unchanged
over the three year period due to shorter average length of haul.
 
     Net income for 1998 was $10.2 million higher than net income in 1997
primarily due to increased operating revenue and lower interest expense
partially offset by higher operating expenses and lower interest and other
income. Net income per unit increased $0.05 due to the increase in net income
despite a greater number of weighted average units outstanding during 1998
compared with 1997 and additional incentive
                                       14
<PAGE>   17
 
income allocations to the General Partner related to the achievement of certain
target cash distribution levels. See Note 3 to the Partnership's consolidated
financial statements. Weighted average units outstanding increased in 1998 due
to the full year impact of the October 1997 Class A Common Unit offering.
 
     Net income in 1997 improved $25.9 million in comparison with 1996. A 1996
non-recurring charge of $20.1 million related to prior years' rate refunds
required under the Settlement Agreement together with a related interest accrual
of $3.2 million accounts for a majority of the increase. In addition, a
combination of higher operating revenue and lower interest expense, partially
offset by higher operating expenses, led to the increase in net income. Per unit
amounts increased significantly primarily due to increased net income.
 
     Operating revenue for 1998 was $287.7 million, or $5.6 million greater than
operating revenue for 1997. The increase was primarily due to increased
deliveries and the full year impact of a July 1, 1997, tariff increase of 1.6%,
partially offset by a 0.6% tariff decrease on July 1, 1998, as required under
the FERC's indexing methodology and an increase in the proportion of heavy crude
oil deliveries (up 9% to 625,000 barrels per day). The Partnership's current
tariff rate for medium and heavy crude oil deliveries to the Chicago area is
approximately 7% and 20% higher, respectively, than that for lighter crude oils.
The positive impact of increased deliveries and heavier crude oil mix were
somewhat offset by a decreased average length of haul (686 miles in 1998 versus
704 miles in 1997). Average length of haul decreased due to increased receipt of
crude oil in the Chicago area from U.S. and foreign sources for delivery to
markets east of Chicago including eastern Canada.
 
     Operating revenue for 1997 was $282.1 million, or $7.6 million greater than
1996 primarily due to increased deliveries and the transportation of a greater
proportion of heavy crude oil (up 22% to 573,000 barrels per day). Operating
revenue was also favorably impacted by the full year impact of a July 1996
tariff rate increase of 0.9%, and an additional 1.6% on July 1, 1997. Operating
revenue for 1996 reflects tariff rates implied in the Settlement Agreement.
 
     Total operating expenses of $182.3 million in 1998 were $8.3 million
greater than 1997 primarily due to higher power costs associated with increased
deliveries, and a heavier crude oil mix. Operating and administrative costs
increased $3.9 million primarily due to increased rents for rights-of-way as a
result of the renewal of certain lease agreements that expired during the year,
and higher maintenance costs associated with an increased level of internal
pipeline inspection. Depreciation expense increased due to the growth in
property, plant and equipment.
 
     Total 1997 operating expenses were $13.1 million less than 1996 primarily
due to the absence of a $20.1 million provision for prior years' rate refunds
recorded in 1996. The decrease in total operating expenses was somewhat offset
by higher power costs associated with a heavier crude oil mix and increased
deliveries. Operating and administrative expenses increased largely due to
higher property taxes. Depreciation expense for 1997 increased due to growth in
property, plant and equipment, somewhat offset by the impact of revised
depreciation rates that became effective on July 1, 1996. The depreciation rates
were revised to better represent the expected service life of the pipeline
system.
 
     Interest expense of $21.9 million in 1998 decreased $16.7 million from 1997
largely due to the capitalization of interest costs associated with SEP II and
Terrace as part of the costs of constructing the assets. Capitalized interest
reflects the Partnership's average cost of debt, of approximately 7.8%, and the
average level of funds invested in construction. Capitalized interest increased
due to the significant construction projects ongoing during 1998. Interest
expense is further decreased due to the utilization of the Partnership's cash
balances to finance a portion of the capital expenditures rather than issuing
additional debt or equity. Interest capitalization generally ceases once a
capital project is complete and ready for service. Interest paid increased to
$44.4 million in 1998 from $39.9 million paid in 1997 primarily due to greater
borrowing on the Partnership's revolving credit facility.
 
     Interest expense for 1997 decreased $5.3 million from 1996 due to lower
balances and interest rates with respect to rate refunds payable, and increased
capitalized interest attributable to greater construction work in process during
1997. These changes were partially offset by additional interest on greater
average borrowings in 1997 under the Partnership's credit facility.
 
                                       15
<PAGE>   18
 
LIQUIDITY AND CAPITAL RESOURCES
 
     At December 31, 1998, cash, cash equivalents and short-term investments
totaled $47.0 million, down $125.5 million since December 31, 1997. In keeping
with the Partnership's financing plans for SEP II and Terrace, existing cash
balances were used to partially finance the expansion programs. Of this $47.0
million, $24.7 million ($0.86 per unit) was set aside for the cash distribution
paid on February 12, 1999, with the remaining $22.3 million available for
capital expenditures and other business needs.
 
     Cash generated from operating activities in 1998 decreased marginally by
$3.0 million from 1997 to $103.6 million, as the impact of higher net income was
offset by changes in working capital requirements. Cash generated from operating
activities in 1997 increased $12.7 million from 1996 to $106.6 million primarily
due to higher net income, partially offset by the reduction in liability for
accrued rate refunds.
 
     In response to the October 1996 Settlement Agreement, the Partnership made
rate refunds of $28.5 million in 1998 and $27.7 million in 1997 with the
remaining balance continuing to be repaid through a 10% reduction of tariff
rates. This reduction will continue until all refunds have been made. Based on
the $28.7 million remaining balance at December 31, 1998, and projected pipeline
system deliveries, the 10% reduction is expected to remain effective until
sometime late in the second half of 1999.
 
     In 1998, the Partnership made capital expenditures of $487.3 million, of
which $358.0 million were for SEP II, $112.7 million were for Terrace, and $16.6
million were for other projects. With $450.0 million of capital expenditures
having been incurred or committed on SEP II through December 31, 1998, the
project is largely complete except for minor restoration and clean-up work and
the finalization of rights-of-way costs in 1999. In 1997, the Partnership made
capital expenditures of $126.9 million, including $84.9 million for SEP II and
$42.0 million for other projects.
 
     The first phase of the Terrace expansion is largely complete and capital
expenditures are anticipated to total approximately $138.0 million. In addition
to Terrace, the Partnership anticipates spending approximately $8.2 million for
pipeline system enhancements and $13.5 million for core maintenance activities
in 1999. See "-- Future Prospects, -- Lakehead System Expansion Projects."
 
     Excluding future phases of Terrace, ongoing capital expenditures are
expected to average $10 to $20 million on an annual basis (approximately 50% for
enhancement and 50% for core maintenance of the pipeline system). Core
maintenance activities, such as the replacement of equipment and preventive
maintenance programs, are expected to be undertaken to enable the Partnership's
pipeline system to continue to operate at its maximum operating capacity.
Enhancements to the pipeline system, such as renewal and replacement of pipe,
are expected to extend the life of the Lakehead System 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 the Lakehead System 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.
Future environment and safety expenditures are not anticipated to be material in
relation to the Partnership's results of operations.
 
     At December 31, 1998, the Partnership had $310.0 million aggregate
principal amount of First Mortgage Notes outstanding that bear 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 the year 2002. During 1998, the
Partnership increased the size of its $205.0 million Revolving Credit Facility
to $350 million. Total borrowings under the facility of $305.0 million were
outstanding at December 31, 1998. Interest rates on this facility are variable
and currently approximate 6%.
 
     During the third quarter of 1998, the Board of Directors of the General
Partner approved a $200 million uncommitted lending facility from the General
Partner to the Partnership. This uncommitted facility provided
 
                                       16
<PAGE>   19
 
an alternative source of funds at market interest rates in the event that a
disruption in the capital markets delayed anticipated debt and equity issuances.
In late September 1998, the Partnership borrowed, and subsequently repaid in
early October, $37.0 million under this arrangement.
 
     In October 1998, pursuant to a $400 million shelf registration statement
filed with the Securities and Exchange Commission ("SEC"), $200 million face
amount of senior unsecured notes were issued to retire borrowings under the
Revolving Credit Facility and to repay the loan of $37 million issued by the
General Partner. The Partnership issued the senior unsecured notes in two
tranches of $100 million, each, with maturities of 2018 (with an interest rate
of 7%) and 2028 (with an interest rate of 7.125%), respectively. For additional
details relating to the Partnership's debt, see Note 6 to the Partnership's
Consolidated Financial Statements.
 
     In October 1997, the Partnership issued 2.2 million Class A Common Units.
Net proceeds from the offering, including the General Partner's contribution,
were $99.2 million. This offering increased the number of Class A Common Units
outstanding to 22,290,000. Proceeds from this offering were used to finance a
portion of SEP II. For additional information regarding the 1997 equity offering
and Partnership organization, see Note 1 to the Partnership's Consolidated
Financial Statements. During the fourth quarter of 1998, the Partnership filed a
$200 million shelf registration statement with the SEC for the issuance of
additional Class A Common Units. As of December 31, 1998, no Class A Common
Units have been issued under this registration statement.
 
     Distributions paid to partners during 1998 increased $20.0 million to $95.3
million ($3.36 per unit). Distributions increased as a result of the increase in
the quarterly distribution to $0.86 per unit from $0.78 per unit declared in
April 1998, the issuance of 2.2 million Class A Common Units in 1997, and
increased incentive distributions paid to the General Partner as a result of
higher levels of cash distributions per unit. Distributions paid to partners for
1997 increased $11.4 million to $75.3 million ($2.92 per unit) compared to 1996.
 
     The Partnership distributes quarterly all of its Available Cash, which is
generally defined to mean, with respect to any calendar quarter, the sum of all
of the cash receipts of the Partnership plus net reductions to reserves less all
of its cash disbursements and net additions to reserves. These reserves are
retained to provide for the proper conduct of the Partnership's business, to
stabilize distributions of cash to Unitholders and the General Partner and as
necessary to comply with the terms of any agreement or obligation of the
Partnership. On February 12, 1999, the Partnership paid a $0.86 per unit
distribution related to the fourth quarter of 1998.
 
     The Partnership anticipates that it will continue to have adequate
liquidity to fund future recurring operating, investing and financing
activities. The Partnership intends to fund Terrace, remaining SEP II
expenditures, and ongoing capital expenditures with the proceeds from future
debt and equity offerings, other borrowings, cash generated from operating
activities, and existing cash, cash equivalents and short-term investments. Cash
distributions are expected to be funded with internally generated cash. The
Partnership's ability to make future debt and equity offerings will depend on
prevailing market conditions and interest rates and the then-existing financial
condition of the Partnership.
 
FUTURE PROSPECTS
 
     Income and cash flows of the Partnership are sensitive to oil industry
supply and demand in Canada and the United States, and the regulatory
environment. As the Partnership's pipeline system is operationally integrated
with the Enbridge Pipelines System in western Canada, the Partnership's revenues
are dependent upon the utilization of the Enbridge Pipelines System by producers
of western Canadian crude oil. The Partnership believes long-term demand for its
pipeline system will continue in light of industry's increasing production
forecasts for western Canadian crude oil and anticipated increased demand for
crude oil in the Midwest U.S. See "Items 1 & 2. Business and
Properties, -- Supply and Demand for Western Canadian Crude Oil."
 
     In late 1998, representatives of the Canadian Association of Petroleum
Producers ("CAPP") and the Partnership concluded informal discussions concerning
the projected supply of western Canadian crude oil and
 
                                       17
<PAGE>   20
 
NGL available for delivery during 1999. Based on these discussions, and as a
result of the general decline in crude oil prices, it is anticipated that
deliveries on the Partnership's pipeline system could be approximately 50,000 to
75,000 barrels per day (on average) less than 1998 delivery levels of 1,562,000
barrels per day. At this potential level of utilization, the Partnership will
earn a 7.5% nominal rate of return on its SEP II equity investment during 1999,
the minimum prescribed in tariff agreements reached with a majority of the
Partnership's customers. See "Items 1 & 2. Business and
Properties, -- Regulation, -- Tariffs."
 
     The collective impact of reduced deliveries and a 7.5% rate of return on
SEP II equity is anticipated to result in net income for 1999 of approximately
$80 to $90 million. Based on current projections, the Partnership anticipates
generating sufficient cash from operating activities to continue its current
level of cash distribution through 1999. Despite the recent weakness in crude
oil prices, the Partnership's outlook regarding future growth prospects remains
positive. While the availability of western Canadian crude oil is sensitive to
the long-term outlook for crude oil prices, the Partnership believes that recent
announcements by major Canadian oil producers affirming oil sands development
and other long-term expansion projects is encouraging and illustrative of
long-term supply growth from the western Canadian sedimentary basin.
 
     The Lakehead and Enbridge Pipelines Systems (the "System") serve as a
strategic link between the western Canadian oil fields and the markets of the
Midwest U.S. and eastern Canada and have for the last several years operated at
or near capacity. In response to a long-term trend of increasing supply of crude
oil from western Canada and the growth of demand in the markets of the Midwest
U.S., the Partnership plans not only to maintain the service capability of the
existing Lakehead System but also to expand its capacity where appropriate. This
is consistent with the Partnership's principal business objective to increase
cash generated from its operations to enhance cash distributions. This strategy
has enabled the Partnership to increase quarterly cash distributions to Common
Unitholders from $0.59 per unit in 1992 to $0.86 per unit currently.
 
Lakehead System Expansion Projects
 
     Key current and future expansion projects of the Partnership are summarized
below:
 
     - SEP II -- This expansion was largely completed in early 1999. SEP II
       involved the construction of a new pipeline from the Partnership's
       pipeline terminal at Superior, Wisconsin, to its Chicago, Illinois,
       market area. The pipeline is expected to provide an additional 170,000
       barrels per day of delivery capacity on the Lakehead System. Under a
       tariff agreement with its customers ("Tariff Agreement"), a tariff
       surcharge has been implemented that recovers the costs of, and return on,
       the SEP II facilities. The Tariff Agreement allows the Partnership to
       earn a return on its SEP II equity investment based on the benchmark
       National Energy Board of Canada ("NEB") multi-pipeline rate of return.
       Under the Tariff Agreement, return on SEP II equity can range from a
       minimum equivalent to the NEB multi-pipeline rate of return less 3%
       (subject to a 7.5% floor) to a maximum of the multi-pipeline rate of
       return plus 3% (subject to a 15% ceiling). Rate of return on equity
       within the range is determined by measuring SEP II capacity utilization
       on the Enbridge Pipelines System in Canada. See "Items 1 & 2. Business
       and Properties, -- Regulation, -- Tariffs."
 
     - Terrace Expansion Program -- This expansion program, which is being
       undertaken by the Partnership in conjunction with Enbridge Pipelines, is
       a phased expansion that is expected to ultimately provide an additional
       520,000 barrels per day of heavy crude oil capacity for western Canadian
       producers seeking greater access to Midwest U.S. markets. Subject to
       continued industry support, customer requirements and receipt of
       regulatory approvals, the General Partner and Enbridge Pipelines
       anticipate that this expansion program will be completed in stages
       beginning in 1999. Phase I of Terrace includes construction of new
       36-inch diameter pipeline facilities from Kerrobert, Saskatchewan, to
       Clearbrook, Minnesota. The new pipeline will join existing 48-inch
       diameter pipeline loops between Kerrobert and Clearbrook, creating
       another separate pipeline joining those locations. Phase I is expected to
       provide an initial 95,000 barrels per day increase in capacity in the
       first half of 1999, rising to 170,000 barrels per day by September 1999.
       Phase I construction is expected to cost the Partnership approximately
       $138 million for construction of facilities in the U.S., and Enbridge
       Pipelines Cdn. $610 million for construction of facilities in Canada.
       Subsequent phases of Terrace are dependent upon customer
 
                                       18
<PAGE>   21
 
       requirements and, if completed, are expected to provide up to 350,000
       barrels per day of added heavy crude oil capacity in addition to the
       170,000 barrels per day to be provided by Phase I. Subject to completion
       of all phases, and after allowing for anticipated declines in light crude
       oil production, total System delivery capability is expected to increase
       by 350,000 barrels per day. A tariff surcharge for Terrace of
       approximately $0.013 per barrel (for light crude oil to Chicago) is
       anticipated to be filed in the first half of 1999. This tariff surcharge
       is premised on the completion of Phase 2 and Phase 3 of Terrace. Should
       these later phases not proceed, the Partnership will be allowed to
       increase its tariff surcharge on a cost of service basis to allow
       recovery of, and return on, its Phase I Terrace investment including any
       revenue variances between the application of the toll increment and
       annual Terrace cost of service. See "Items 1 & 2. Business and
       Properties, -- Regulation, -- Tariffs."
 
     The Partnership 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
one percent ("PPIFG-1"). The General Partner expects the PPIFG-1 to decrease
approximately 1.9% for 1998. This decrease in the PPIFG-1 should not have a
material effect on 1999 operating revenue since the decrease does not apply to
SEP II or Terrace tariff surcharges and will be effective mid-year 1999. To
date, the Partnership has been able to manage its pipeline system to ensure
inflationary cost pressures in excess of the PPIFG-1 have not materially
impacted net income. The FERC is scheduled to review the appropriateness of the
indexing methodology, and specifically the PPIFG-1 index, in year 2000.
 
     The indexed rate environment, the Settlement Agreement, and other
negotiated settlements with customers for SEP II and Terrace are benefiting the
Partnership and its customers by restoring stability and providing predictable
tariff rates. Customer representatives who are a party to the various agreements
have agreed not to challenge any rates within the indexed ceiling until October
2001. In addition, 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.
 
Enbridge Inc. Projects
 
     Enbridge Inc. ("Enbridge" formerly IPL Energy Inc.) the ultimate parent of
the General Partner, is also engaged in North American crude oil pipeline
projects which are related to the Enbridge Pipelines and Lakehead Systems. The
General Partner believes that certain of these projects are complementary to
ongoing and future expansion projects even though they are not owned by the
Partnership, since the projects may result in increased deliveries on the
Lakehead System. Such projects are summarized below:
 
     - Mustang -- In 1996, a U.S. subsidiary of Enbridge entered into a
       partnership ("Mustang Pipe Line Partners") with Mobil Illinois Pipe Line
       Company, a subsidiary of Mobil Oil Corporation, to own and operate a
       crude oil pipeline that connects the Lakehead System to the Patoka/Wood
       River refinery area and pipeline hub south of Chicago. The Partnership
       has entered into a joint tariff agreement with Mustang Pipe Line Partners
       that became effective January 1, 1999. The agreement covers shipments of
       western Canadian crude oil over the Lakehead System and the Mustang
       pipeline. The joint tariff agreement provides lower transportation costs
       to shippers desiring access to the Patoka/Wood River market area. Prior
       to the joint tariff agreement, this market area was not competitively
       accessible to Partnership customers. The joint tariff agreement results
       in a reduction in the Partnership's light crude oil rate for deliveries
       destined for the Patoka/Wood River market area. The Mustang system has a
       capacity of approximately 100,000 barrels per day.
 
     - Enbridge Toledo -- Enbridge has completed construction of a new pipeline,
       which connects the Partnership's facilities at Stockbridge, Michigan, to
       two refineries in the Toledo, Ohio, area. This pipeline is anticipated to
       have an approximate capacity in excess of 80,000 barrels per day in heavy
       crude oil service and became available for service in early February
       1999.
 
     - Enbridge Athabasca (formerly Wild Rose)-- Enbridge is scheduled to
       complete construction of a new 30-inch diameter pipeline for the delivery
       of heavy crude oil from the Athabasca oil sands region near Fort
       McMurray, Alberta, to Hardisty, Alberta, by March 31, 1999. At Hardisty,
       the Athabasca pipeline would access other pipeline systems including the
       Enbridge Pipelines System in western
                                       19
<PAGE>   22
 
       Canada. This project would provide new pipeline capacity to accommodate
       anticipated growth in production in the Athabasca oil sands region. When
       fully powered, the Athabasca pipeline is anticipated to have an ultimate
       capacity of 570,000 barrels per day. Enbridge has entered into a 30-year
       transportation arrangement with Suncor Energy Inc., the initial shipper
       on the pipeline.
 
Montreal Extension Reversal
 
     The Enbridge Pipelines System includes a section which extends from Sarnia,
Ontario, to Montreal, Quebec (the "Montreal Extension" or "Line 9"). The portion
of the Montreal Extension from Sarnia to North Westover, Ontario, is currently
in west-to-east service and the portion of the Montreal Extension from North
Westover to Montreal has been purged with nitrogen and remains available for
service. Enbridge Pipelines and a group of refiners have developed the Line 9
reversal project to enable crude oil imported into eastern Canada through
facilities of Portland Pipe Line Corporation and Montreal Pipe Line Limited to
be transported on Line 9 in an east-to-west direction from Montreal to the major
refining centers in Ontario. The reversal of the Montreal Extension will result
in Enbridge Pipelines becoming a competitor of the Lakehead System for supplying
crude oil to the Ontario market. This reversal is expressly permitted by the
agreements entered into at the time of formation of the Partnership. The NEB
approved construction of facilities as well as the tolling methodology for the
Line 9 project on December 18, 1997. Enbridge received notice in July 1998 from
the group of sponsoring refiners to proceed with construction of facilities
necessary for reversal. Construction to allow for full reversal is expected to
be completed late in the third quarter or early in the fourth quarter of 1999 at
which time the reversed Line 9 is anticipated to have a capacity of
approximately 240,000 barrels per day from Montreal to Sarnia. Due to upstream
capacity constraints, the Montreal extension is anticipated to be reversed in
two stages, with the first stage entering service in May 1999 with a capacity of
120,000 barrels per day from Montreal to North Westover.
 
     The Partnership anticipates that the reversal of Line 9 will result in a
decline in deliveries over the Lakehead System to eastern Canada. Displaced
volumes originating in western Canada are anticipated to be diverted to other
markets in the Midwest U.S. U.S. domestic and foreign crude oil volumes that
enter the Lakehead System in Chicago are also anticipated to decline from recent
historical levels due to the reversal of Line 9. The level of decline in
deliveries over the Lakehead System to eastern Canada will be dependent upon the
global crude oil market dynamics and the level of utilization of Line 9.
 
Year 2000 Issue
 
     The Partnership's pipeline system is operationally dependent on the ability
of Enbridge Pipelines to transport crude oil and other liquid hydrocarbons from
western Canada to reach markets in the United States and eastern Canada. Due to
the integrated nature of these two pipeline systems, the Partnership's Year 2000
Readiness Program is being conducted in conjunction with Enbridge Pipelines.
 
     The Partnership's Year 2000 Readiness Program continues on schedule, with
several milestone points being reached by December 31, 1998. The Year 2000
Project Teams of Enbridge Pipelines and the Partnership have compiled a
comprehensive list of all computer hardware and software, embedded chip
technologies and business processes including those having significant third
party interdependencies. A risk assessment and business impact analysis of each
item has also been completed and the Partnership is prioritizing its efforts and
resources to ensure that all critical processes and assets are made to be
compliant on a timely basis. Some critical systems, such as certain accounting
systems which have been replaced under a business system upgrade project, are
already known to be Year 2000 compliant, thereby reducing the risk of failure.
 
     The most critical systems are those that operate and control crude oil and
NGL pipelines, as they are essential to Partnership operations. These systems
are used to control the entire liquid pipeline system, including related tank
farms and pumping stations. Instrumentation along the pipelines measure and
control temperatures, pressures, volume flow, pump operation, valve operation
control equipment and alarm states. This information is also passed to various
control systems to help monitor and track flowing crude oil and NGL in the
pipeline system. The control systems are expected to be compliant by mid 1999.
 
                                       20
<PAGE>   23
 
     In addition, the Year 2000 Project Teams have identified third parties
whose non compliance may have a significant effect on the ability of the
Partnership to continue to conduct its business without disruption. Dialogue has
been established with these entities in order to ascertain whether they will be
Year 2000 compliant in advance of January 1, 2000.
 
     The most significant third party interdependencies are reliance on
electrical and telecommunication suppliers as they are essential to the ability
to transport crude oil and NGL through the System. Also of significance are
feeder pipeline systems that deliver much of the crude oil and NGL entering the
System, as are the receiving connecting pipelines and refineries.
 
     While the Partnership is unable to provide a current assessment of these
critical suppliers' Year 2000 compliance progress, communication with these
entities and monitoring of their Year 2000 readiness status will continue. In
the case of critical suppliers and feeder pipelines, joint testing initiatives
may also be implemented. Where timely assurance is not received, restrictions on
use or replacement of vendors will be considered.
 
     In the review of the systems potentially impacted by the Year 2000 problem,
Enbridge Pipelines and the Partnership are giving consideration to the repair,
replacement, workaround, outsourcing and other methods of eliminating
deficiencies. Enbridge Pipelines and the Partnership are currently involved in
various stages of implementing their Year 2000 compliance initiatives and expect
to have all critical processes and assets compliant by mid 1999, at which point
lower risk systems will be remediated.
 
     In order to address unforeseen Year 2000 problems that could arise and in
an attempt to minimize business disruptions, Enbridge Pipelines and the
Partnership are developing business continuity plans for all critical processes,
systems, technologies and external relationships. These plans are also expected
to be completed before the end of the year.
 
     Preliminary cost estimates for achieving Year 2000 compliance of the
Partnership are approximately $6 million, including $1 million in capital costs
and $5 million of operating expense, with approximately $1 million of expense
having been incurred to date. A majority of the remaining costs are anticipated
to be incurred in 1999. No material resource constraints have been encountered
to date. Although management believes this estimate to be reasonable, due to the
complexities outlined above, there can be no assurance that the actual costs of
the project will not differ materially from the estimated amounts.
 
     Despite the Partnership's best efforts, there can be no guarantees that all
systems and applications will continue without interruption through January 1,
2000 and beyond. Limited testing ability on commercial software packages and the
complexity of identifying all embedded microprocessors that may be used in a
great variety of hardware used for process or flow control, environmental,
transportation, security, communication and other systems may result in non
compliant systems. Additionally, despite ongoing dialogue with interdependent
third parties there can be no assurance that their systems will be fully
compliant. In the event of critical system or supplier failure, crude oil and
NGL deliveries could be temporarily delayed until corrective action is taken or
continuity plans are implemented. Failures that result in substantial
disruptions of business activities could be material to the Partnership.
 
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
 
     The Partnership's market risk is primarily impacted by changes in interest
rates. The Partnership has minimal foreign exchange risk and its cash flows are
not significantly impacted by changes in commodity prices as the Partnership
does not own the crude oil and NGL it transports. However, commodity prices have
a significant impact on the underlying supply and demand for crude oil and NGL
that the Partnership transports. The Partnership does not currently hold or
issue derivative instruments for trading or any other purposes.
 
     The Partnership's market risk with respect to interest rate exposure is
managed through its long-term debt ratio target, and its allocation of fixed and
floating rate debt. The table below provides information about
 
                                       21
<PAGE>   24
 
the Partnership's financial instruments that are sensitive to changes in
interest rates. For debt obligations the table presents principal cash flows and
related weighted average interest rates by expected maturity date.
 
<TABLE>
<CAPTION>
                                           EXPECTED MATURITY DATE OF DEBT INSTRUMENTS
                                         ----------------------------------------------
                                                                                 THERE-                   FAIR
         DECEMBER 31, 1998               1999 - 2001      2002        2003       AFTER       TOTAL       VALUE
         -----------------               -----------      ----        ----       ------      -----       -----
                                                                  ($U.S. IN MILLIONS)
<S>                                      <C>              <C>        <C>         <C>         <C>         <C>
FIXED RATE:
  First Mortgage Notes.............          $0           $31.0      $ 31.0      $248.0      $310.0      $369.0
  Interest Rate....................          --            9.15%       9.15%       9.15%
 
  Senior Unsecured Notes...........          $0           $   0      $    0      $200.0      $200.0      $209.0
  Interest Rate....................          --              --          --        7.06%
 
VARIABLE RATE:
  Revolving Credit Facility........          $0           $   0      $305.0      $    0      $305.0      $305.0
  Interest Rate....................          --              --         5.8%         --
</TABLE>
 
     The average interest rate of debt outstanding on the Partnership's
Revolving Credit facility was 5.8% during 1998. For additional information
concerning the Partnership's debt obligations, please see Note 6 to the
Partnership's Consolidated Financial Statements.
 
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
 
     The consolidated financial statements of the Partnership together with the
notes thereto and the independent accountants' reports thereon, appear on pages
F-2 through 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.
 
                                    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.
 
<TABLE>
<CAPTION>
               NAME                    AGE       POSITION WITH GENERAL PARTNER
               ----                    ---       -----------------------------
<S>                                    <C>    <C>
E. C. Hambrook.....................    61     Chairman and Director
P. D. Daniel.......................    52     Director
S. J. Wuori........................    41     President and Director
R. C. Sandahl......................    48     Vice President and Director
F. W. Fitzpatrick..................    66     Director
C. A. Russell......................    65     Director
D. P. Truswell.....................    55     Director
S. R. Wilson.......................    41     Vice President (since January 14,
                                              1999) and Treasurer
M. A. Maki.........................    34     Chief Accountant
S. D. Lenczewski...................    38     Secretary
</TABLE>
 
                                       22
<PAGE>   25
 
     Mr. Hambrook was elected a Director of the General Partner in January 1992
and has served as Chairman of the General Partner since July 1996. He also
serves on the Audit Committee. Mr. Hambrook is the President of Hambrook
Resources Inc.
 
     Mr. Daniel was elected a Director of the General Partner in July 1996 and
served as its President from July 1996 through October, 1997. Since June 1998,
Mr. Daniel has also served as President and Chief Operating Officer Energy
Delivery of Enbridge. Prior thereto, 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.
Prior to May 1994, he served as Vice President, Planning of Enbridge.
 
     Mr. Wuori was appointed President and elected a Director of the General
Partner as of November 1, 1997. He has served as President of Enbridge Pipelines
since September 1997. Prior thereto, he served as Vice President, Operations of
Enbridge Pipelines from May 1994 to August 1997, and, prior thereto, as District
Manager of the General Partner.
 
     Mr. Sandahl was elected a Director and appointed Vice President of the
General Partner in July 1996. He served as Vice President, Operations of the
General Partner from May 1994 to August 1996. Prior thereto, he was employed by
Enbridge Pipelines for six years where he served in various capacities, most
recently as Director of Engineering Services from June 1990 to May 1994.
 
     Mr. Fitzpatrick was elected a Director of the General Partner in April 1993
and serves on the Audit Committee. He is also a Director of Enbridge and serves
as Chairman of the Audit, Finance and Risk Committee of the Board of Enbridge.
 
     Mr. Russell was elected a Director of the General Partner in October 1985
and serves as the Chairman of the Audit Committee. Mr. Russell served as
Chairman and Chief Executive Officer of Norwest Bank Minnesota North, N.A. from
January through December 1995. Prior to January 1995, he served as President of
Norwest Bank Minnesota North, N.A. He also served as a Director of Minnesota
Power and Light Co. until May 1996.
 
     Mr. Truswell was elected a Director of the General Partner in May 1991 and
served as a Vice President of the General Partner from October 1991 to May 1994.
Mr. Truswell has served as Senior Vice President and Chief Financial Officer of
Enbridge since May 1994 and prior thereto, as Vice President, Finance of
Enbridge from 1992 to May 1994. He also served in various senior executive
capacities with Enbridge Pipelines, including as Vice President, Finance from
May 1991 to May 1994.
 
     Mr. Wilson was appointed Treasurer of the General Partner as of November 1,
1997. He has served as Treasurer of Enbridge since September 1997 and, prior
thereto, as its Assistant Treasurer from September 1995 to August 1997. Mr.
Wilson has served as Treasurer of The Consumers' Gas Company Ltd., a subsidiary
of Enbridge since April 1991.
 
     Mr. Maki has served as Chief Accountant of the General Partner since June
1997. Prior thereto, he served in various supervisory and professional positions
with the General Partner or Enbridge affiliates in the areas of Internal Audit,
Rate Regulation and Accounting.
 
     Ms. Lenczewski has served as Secretary of the General Partner since June
1998. Prior thereto, she served as Assistant Secretary of the General Partner,
from July 1996 to June 1998.
 
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
 
                                       23
<PAGE>   26
 
Enbridge (U.S.) Inc., ("Enbridge U.S.") and other affiliates to provide the
services required by the Partnership.
 
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
 
     (a) Security Ownership of Certain Beneficial Owners
 
<TABLE>
<CAPTION>
         TITLE OF CLASS                      NAME AND ADDRESS              AMOUNT      PERCENT OF CLASS
         --------------                      ----------------              ------      ----------------
<S>                                  <C>                                  <C>          <C>
Class A Common Units.............    No person or group is known to be
                                     the beneficial owner of more than
                                     5% of the Class A Common Units as
                                     at February 5, 1999
Class B Common Units.............    Lakehead Pipe Line Company, Inc.     3,912,750           100
                                     Lake Superior Place
                                     21 West Superior Street
                                     Duluth, Minnesota 55802-2067
</TABLE>
 
     (b) Security Ownership of Management
 
     As of February 5, 1999, E. C. Hambrook beneficially owned 1,000 Class A
Common Units and R. C. Sandahl beneficially owned 200 Class A Common Units.
Class A Common Units beneficially held by all directors and officers as a group
represented less than 1% of the Partnership's outstanding Class A Common Units.
 
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
 
     The Partnership is managed by the General Partner pursuant to the Amended
and Restated Agreements of Limited Partnership of the Partnership and the
Operating Partnership, as amended ("Partnership Agreements"). The General
Partner has entered into a services agreement with Enbridge U.S. 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 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 7 to the Partnership's Consolidated Financial
Statements.
 
     The Partnership has entered into an easement acquisition agreement with
Enbridge Holdings (Mustang) Inc. ("Enbridge Mustang" formerly IPL Patoka
Pipeline Holdings (U.S.A.) Inc.), a subsidiary of Enbridge U.S. For the benefit
of the Partnership, Enbridge Mustang has acquired certain real property for
purposes of granting a pipeline easement to the Partnership. Enbridge Mustang is
reimbursed for all net 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. This agreement was
entered into to facilitate easement acquisitions for SEP II. Enbridge Mustang
will begin to dispose of real property acquired in 1997 and 1998 and repay
advances from the Partnership as properties are sold beginning in 1999.
 
     The Partnership has implemented an agreement with Mustang Pipe Line
Partners to provide for a joint tariff covering shipments of western Canadian
crude oil to the Patoka/Wood River market area south of Chicago. These shipments
travel on the Lakehead System to Chicago and on the Patoka/Wood River market
area through the Mustang pipeline system. The joint tariff agreement provides
for lower transportation costs to shippers desiring access to the Patoka/Wood
River market area, an incentive which the Partnership believes complements its
expansion programs. Mustang Pipe Line Partners is a Delaware general partnership
owned by Mobil Illinois Pipe Line Company and a wholly owned subsidiary of
Enbridge U.S.
 
     Under the terms of the Revolving Credit Facility Agreement, the
Partnership, Lakehead Services, Limited Partnership ("Services Partnership") and
the General Partner may draw down funds up to a combined maximum of $350.0
million. The Partnership has a 1% general partner interest in the Services
 
                                       24
<PAGE>   27
 
Partnership, with the General Partner having a 99% limited partner interest. For
additional details, see Note 6 to the Partnership's Consolidated Financial
Statements.
 
     The Partnership has entered into a $200 million uncommitted lending
facility with the General Partner. This uncommitted facility provided an
alternative source of funds at market interest rates in the event that a
disruption in the capital markets delayed access to debt and equity markets. In
late September 1998, the Partnership borrowed, and subsequently repaid in early
October, $37.0 million under this arrangement.
 
     For discussion of distribution restrictions and incentive distributions
payable to the General Partner, see Note 3 to the Partnership's Consolidated
Financial Statements.
 
                                    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 Registrant filed the following reports on Form 8-K during the
fourth quarter of 1998: A report on Form 8-K was filed on December 28, 1998,
submitting a press release of the Registrant dated December 21, 1998, announcing
a tariff filing and net income expectations for 1999.
 
     (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.
 
<TABLE>
<CAPTION>
EXHIBIT
NUMBER                             DESCRIPTION
-------                            -----------
<C>        <S>
 3.1       Certificate of Limited Partnership of the Partnership.
           (Partnership's Registration Statement No.
           33-43425 -- Exhibit 3.1)
 4.1       Form of Certificate representing Class A Common Units.
           (Registrant's Form 8-A/A, dated May 2, 1997)
 4.2       Amended and Restated Agreement of Limited Partnership of the
           Partnership, dated April 15, 1997. (Registrant's Form 8-A/A,
           dated May 2, 1997)
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 Operating
           Partnership. (Partnership's Registration Statement No.
           33-43425 -- Exhibit 10.1)
10.8       Amended and Restated Agreement of Limited Partnership of the
           Operating Partnership, dated December 27, 1991. (1991 Form
           10-K -- Exhibit 10.6)
10.9       Certificate of Limited Partnership of Lakehead Services,
           Limited Partnership. (Partnership's Registration Statement
           No. 33-43425 -- Exhibit 10.4)
10.10      Amendment No. 1 to the Certificate of Limited Partnership of
           Lakehead Services, Limited Partnership. (Partnership's
           Registration Statement No. 33-43425 -- Exhibit 10.16)
</TABLE>
 
                                       25
<PAGE>   28
 
<TABLE>
<CAPTION>
EXHIBIT
NUMBER                             DESCRIPTION
-------                            -----------
<C>        <S>
10.11      Amended and Restated Agreement of Limited Partnership of
           Lakehead Services, Limited Partnership, dated December 27,
           1991. (1991 Form 10-K -- Exhibit 10.9)
10.12      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)
10.13      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)
10.14      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)
10.15      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)
10.16      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)
10.17      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)
10.18      Settlement Agreement, dated August 28, 1996, between
           Lakehead Pipe Line Company, Limited Partnership and the
           Canadian Association of Petroleum Producers and the Alberta
           Department of Energy. (1996 Form 10-K -- Exhibit 10.17)
10.19      Promissory Note, dated as of September 30, 1998, among
           Lakehead Pipe Line Company, Inc. as lender and Lakehead Pipe
           Line Company, Limited Partnership as borrower.
10.20      Treasury Services Agreement, dated January 1, 1996, between
           IPL Energy Inc. and Lakehead Pipe Line Company, Inc. (1996
           Form 10-K -- Exhibit 10.18)
10.21      Tariff Agreement as filed with the Federal Energy Regulatory
           Commission for the System Expansion Program II, and Terrace
           Expansion Project.
10.22      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 4.1, dated October 20, 1998)
10.23      First Supplemental Indenture dated September 15, 1998,
           between Lakehead Pipe Line Company, Limited Partnership and
           the Chase Manhattan Bank. (1998 Form 8-K of Lakehead Pipe
           Line Company, Limited Partnership -- Exhibit 4.2, dated
           October 20, 1998)
10.24      Second Supplemental Indenture dated September 15, 1998,
           between Lakehead Pipe Line Company, Limited Partnership and
           the Chase Manhattan Bank. (1998 Form 8-K of Lakehead Pipe
           Line Company, Limited Partnership -- Exhibit 4.3, dated
           October 20, 1998)
10.25      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)
</TABLE>
 
                                       26
<PAGE>   29
 
<TABLE>
<CAPTION>
EXHIBIT
NUMBER                             DESCRIPTION
-------                            -----------
<C>        <S>
21         Subsidiaries of the Registrant.
27         Financial Data Schedule as of and for the year ended
           December 31, 1998.
</TABLE>
 
     All Exhibits listed above, with the exception of Exhibits 10.19, 10.21, 21,
and 27 are incorporated herein by reference to the documents identified in
parentheses.
 
     Copies of Exhibits may be obtained upon written request of any Unitholder
to Investor Relations, Lakehead Pipe Line Company, Inc., Lake Superior Place, 21
West Superior Street, Duluth, Minnesota 55802-2067.
 
     (d) As to financial statement schedules, reference is made to "Financial
Statement Schedules" on page F-1 of this report.
 
                                       27
<PAGE>   30
 
                                   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.
 
                                          Lakehead Pipe Line Partners, L.P.
                                          (Registrant)
 
                                          By: Lakehead Pipe Line Company, Inc.,
                                            as General Partner
 
Date: March 9, 1999                       By:        /s/ S.J. WUORI
                                            ------------------------------------
                                                         S.J. Wuori
                                                        (President)
 
     Pursuant to the requirements of the Securities Exchange Act of 1934, this
Report has been signed below on March 9, 1999 by the following persons on behalf
of the Registrant and in the capacities indicated with Lakehead Pipe Line
Company, Inc., General Partner.
 
<TABLE>
<S>                                                <C>
              /s/ S.J. WUORI                                   /s/ E.C. HAMBROOK
------------------------------------------         ------------------------------------------
                S.J. Wuori                                       E.C. Hambrook
          President and Director                             Chairman and Director
      (Principal Executive Officer)
 
             /s/ R.C. SANDAHL                                    /s/ M.A. MAKI
------------------------------------------         ------------------------------------------
               R.C. Sandahl                                        M.A. Maki
       Vice President and Director                              Chief Accountant
                                                      (Principal Financial and Accounting
                                                                    Officer)
 
           /s/ F.W. FITZPATRICK                                 /s/ P.D. DANIEL
------------------------------------------         ------------------------------------------
             F.W. Fitzpatrick                                     P.D. Daniel
                 Director                                           Director
 
             /s/ C.A. RUSSELL                                  /s/ D.P. TRUSWELL
------------------------------------------         ------------------------------------------
               C.A. Russell                                      D.P. Truswell
                 Director                                           Director
</TABLE>
 
                                       28
<PAGE>   31
 
          INDEX TO FINANCIAL STATEMENTS, SUPPLEMENTARY INFORMATION AND
                         FINANCIAL STATEMENT SCHEDULES
 
                       LAKEHEAD PIPE LINE PARTNERS, L.P.
 
<TABLE>
<CAPTION>
                                                                PAGE
                                                                ----
<S>                                                             <C>
 
Financial Statements
  Report of Independent Accountants.........................    F-2
  Consolidated Statement of Income for the Years Ended
     December 31, 1998, 1997, 1996..........................    F-3
  Consolidated Statement of Cash Flows for the Years Ended
     December 31, 1998, 1997, 1996..........................    F-4
  Consolidated Statement of Financial Position as at
     December 31, 1998 and 1997.............................    F-5
  Consolidated Statement of Partners' Capital for the Years
     Ended December 31, 1998, 1997, 1996....................    F-6
  Notes to the 1998 Consolidated 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>   32
 
                       REPORT OF INDEPENDENT ACCOUNTANTS
 
To the Partners of
  Lakehead Pipe Line Partners, L.P.
 
     In our opinion, the accompanying consolidated statements of financial
position and the related consolidated statements of income, of partners' capital
and of cash flows present fairly, in all material respects, the financial
position of Lakehead Pipe Line Partners, L.P. and its subsidiary (the
"Partnership") at December 31, 1998 and 1997, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 1998 in conformity with generally accepted accounting principles.
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 generally accepted auditing standards 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 the opinion expressed
above.
 
PRICEWATERHOUSECOOPERS LLP
 
Minneapolis, Minnesota
January 8, 1999
 
                                       F-2
<PAGE>   33
 
                       LAKEHEAD PIPE LINE PARTNERS, L.P.
 
                        CONSOLIDATED STATEMENT OF INCOME
 
<TABLE>
<CAPTION>
                                                                   YEAR ENDED DECEMBER 31,
                                                                -----------------------------
                                                                 1998       1997       1996
                                                                 ----       ----       ----
                                                                    (DOLLARS IN MILLIONS,
                                                                  EXCEPT PER UNIT AMOUNTS)
<S>                                                             <C>        <C>        <C>
Operating Revenue (Note 9)..................................    $ 287.7    $ 282.1    $ 274.5
                                                                -------    -------    -------
Expenses
  Power.....................................................       69.0       65.9       62.0
  Operating and administrative..............................       71.9       68.0       66.7
  Depreciation..............................................       41.4       40.1       38.3
  Provision for prior years' rate refunds (Note 9)..........         --         --       20.1
                                                                -------    -------    -------
                                                                  182.3      174.0      187.1
                                                                -------    -------    -------
Operating Income............................................      105.4      108.1       87.4
Interest and Other Income...................................        6.0        9.7        9.6
Interest Expense (Note 6)...................................      (21.9)     (38.6)     (43.9)
Minority Interest...........................................       (1.0)      (0.9)      (0.7)
                                                                -------    -------    -------
Net Income..................................................    $  88.5    $  78.3    $  52.4
                                                                =======    =======    =======
Net Income Per Unit (Note 4)................................    $  3.07    $  3.02    $  2.11
                                                                =======    =======    =======
Weighted Average Units Outstanding (millions)...............       26.2       24.4       24.0
                                                                =======    =======    =======
</TABLE>
 
The accompanying notes to the consolidated financial statements are an integral
                           part of these statements.
 
                                       F-3
<PAGE>   34
 
                       LAKEHEAD PIPE LINE PARTNERS, L.P.
 
                      CONSOLIDATED STATEMENT OF CASH FLOWS
 
<TABLE>
<CAPTION>
                                                                   YEAR ENDED DECEMBER 31,
                                                                -----------------------------
                                                                 1998       1997       1996
                                                                 ----       ----       ----
                                                                    (DOLLARS IN MILLIONS)
<S>                                                             <C>        <C>        <C>
Cash Provided from Operating Activities
  Net income................................................    $  88.5    $  78.3    $  52.4
  Adjustments to reconcile net income to cash provided from
     operating activities:
       Depreciation.........................................       41.4       40.1       38.3
       Accrued rate refunds and related interest (Note 9)...        2.1        3.5       42.6
       Minority interest....................................        1.0        0.9        0.7
       Other................................................        0.1        0.5        0.6
       Changes in operating assets and liabilities:
          Accounts receivable and other.....................       (2.8)       4.8       (0.7)
          Materials and supplies............................         --       (0.1)      (1.6)
          General Partner and affiliates....................       (1.0)       2.4        0.2
          Accounts payable and other........................        2.1        1.5        3.6
          Interest payable..................................        0.2        2.1        0.7
          Property and other taxes..........................        0.5        0.3       (1.1)
          Payment of rate refunds and related interest (Note
            9)..............................................      (28.5)     (27.7)     (41.8)
                                                                -------    -------    -------
                                                                  103.6      106.6       93.9
                                                                -------    -------    -------
Investing Activities
  Short-term investments, net...............................       53.9       29.8       (8.0)
  Advances to affiliate (Note 7)............................      (25.5)      (6.5)        --
  Additions to property, plant and equipment................     (487.3)    (126.9)     (76.7)
  Changes in construction payables..........................       31.0        1.9         --
                                                                -------    -------    -------
                                                                 (427.9)    (101.7)     (84.7)
                                                                -------    -------    -------
Financing Activities
  Variable rate financing, net (Note 6).....................      152.0         --       68.0
  Fixed rate financing, net (Note 6)........................      196.9         --         --
  Proceeds from unit issuance, net (Note 1).................         --       99.2         --
  Distributions to partners (Note 3)........................      (95.3)     (75.3)     (63.9)
  Minority interest.........................................       (0.9)       0.2       (0.7)
                                                                -------    -------    -------
                                                                  252.7       24.1        3.4
                                                                -------    -------    -------
Increase (Decrease) in Cash and Cash Equivalents............      (71.6)      29.0       12.6
Cash and Cash Equivalents at Beginning of Year..............      118.6       89.6       77.0
                                                                -------    -------    -------
Cash and Cash Equivalents at End of Year....................    $  47.0    $ 118.6    $  89.6
                                                                =======    =======    =======
</TABLE>
 
The accompanying notes to the consolidated financial statements are an integral
                           part of these statements.
 
                                       F-4
<PAGE>   35
 
                       LAKEHEAD PIPE LINE PARTNERS, L.P.
 
                  CONSOLIDATED STATEMENT OF FINANCIAL POSITION
 
<TABLE>
<CAPTION>
                                                                     DECEMBER 31,
                                                                ----------------------
                                                                  1998         1997
                                                                  ----         ----
                                                                (DOLLARS IN MILLIONS)
<S>                                                             <C>          <C>
                           ASSETS
Current Assets
  Cash and cash equivalents.................................    $    47.0    $   118.6
  Short-term investments....................................           --         53.9
  Advances to affiliate (Note 7)............................         32.0          6.5
  Accounts receivable and other.............................         25.2         22.4
  Materials and supplies....................................          7.1          7.1
                                                                ---------    ---------
                                                                    111.3        208.5
Deferred Charges and Other..................................          6.9          4.4
Property, Plant and Equipment, Net (Note 5).................      1,296.2        850.3
                                                                ---------    ---------
                                                                $ 1,414.4    $ 1,063.2
                                                                =========    =========
             LIABILITIES AND PARTNERS' CAPITAL
Current Liabilities
  Due to General Partner and affiliates.....................    $     2.9    $     3.9
  Accounts payable and other................................         53.3         20.2
  Interest payable..........................................          5.5          5.3
  Property and other taxes..................................         11.9         11.4
  Current portion of accrued rate refunds and related
     interest (Note 9)......................................         28.7         29.0
                                                                ---------    ---------
                                                                    102.3         69.8
 
Long-Term Debt (Note 6).....................................        814.5        463.0
Accrued Rate Refunds and Related Interest (Note 9)..........           --         26.1
Minority Interest...........................................          2.6          2.5
Contingencies (Note 10).....................................
                                                                ---------    ---------
                                                                    919.4        561.4
                                                                ---------    ---------
Partners' Capital
  Class A Common Unitholders (Units authorized and
     issued -- 22,290,000)..................................        453.4        461.6
  Class B Common Unitholder (Units authorized and
     issued -- 3,912,750)...................................         37.3         36.7
  General Partner...........................................          4.3          3.5
                                                                ---------    ---------
                                                                    495.0        501.8
                                                                ---------    ---------
                                                                $ 1,414.4    $ 1,063.2
                                                                =========    =========
</TABLE>
 
     The accompanying notes to the consolidated financial statements are an
integral part of these statements.
 
                                       F-5
<PAGE>   36
 
                       LAKEHEAD PIPE LINE PARTNERS, L.P.
 
                  CONSOLIDATED STATEMENT OF PARTNERS' CAPITAL
 
<TABLE>
<CAPTION>
                                                            CLASS A       CLASS B
                                                            COMMON         COMMON      GENERAL
                                                          UNITHOLDERS    UNITHOLDER    PARTNER     TOTAL
                                                          -----------    ----------    -------     -----
                                                                       (DOLLARS IN MILLIONS)
<S>                                                       <C>            <C>           <C>        <C>
Partners' capital at December 31, 1995................      $ 387.9       $  21.7      $   1.5    $ 411.1
Net income allocation.................................         40.6          10.2          1.6       52.4
Distributions to partners.............................        (52.2)        (10.2)        (1.5)     (63.9)
                                                            -------       -------      -------    -------
Partners' capital at December 31, 1996................        376.3          21.7          1.6      399.6
Allocation of net proceeds from unit issuance (Note
  1)..................................................         85.6          12.6          1.0       99.2
Net income allocation.................................         60.1          13.8          4.4       78.3
Distributions to partners.............................        (60.4)        (11.4)        (3.5)     (75.3)
                                                            -------       -------      -------    -------
Partners' capital at December 31, 1997................        461.6          36.7          3.5      501.8
Net income allocation.................................         66.7          13.8          8.0       88.5
Distributions to partners.............................        (74.9)        (13.2)        (7.2)     (95.3)
                                                            -------       -------      -------    -------
Partners' capital at December 31, 1998................      $ 453.4       $  37.3      $   4.3    $ 495.0
                                                            =======       =======      =======    =======
</TABLE>
 
The accompanying notes to the consolidated financial statements are an integral
                           part of these statements.
 
                                       F-6
<PAGE>   37
 
                       LAKEHEAD PIPE LINE PARTNERS, L.P.
 
              NOTES TO THE 1998 CONSOLIDATED FINANCIAL STATEMENTS
                 (DOLLARS IN MILLIONS, EXCEPT PER UNIT AMOUNTS)
 
1. PARTNERSHIP ORGANIZATION AND NATURE OF OPERATIONS
 
     Lakehead Pipe Line Partners, L.P. ("Lakehead Partnership") is a publicly
traded limited partnership that owns a 99% limited partner interest in Lakehead
Pipe Line Company, Limited Partnership ("Operating Partnership"), both Delaware
limited partnerships, and collectively known as the "Partnership". The
Partnership was formed in 1991 to acquire, own and operate the crude oil and
natural gas liquids pipeline business of Lakehead Pipe Line Company, Inc. (the
sole "General Partner"). The General Partner is a wholly-owned subsidiary of
Enbridge Pipelines Inc. ("Enbridge Pipelines") (formerly Interprovincial Pipe
Line Inc.), a Canadian company owned by Enbridge Inc. (formerly IPL Energy Inc.)
of Calgary, Alberta, Canada.
 
     In October 1997, the Lakehead Partnership issued an additional 2,200,000
Class A Common Units for total net proceeds of $99.2 million, including the
General Partner's contribution, bringing the total number of Class A Common
Units issued to 22,290,000. Class A Common Units are publicly traded and
represent an 83.4% limited partner interest in the Partnership. The General
Partner has a 14.8% limited partner (in the form of 3,912,750 Class B Common
Units) and 1.0% general partner interest in the Lakehead Partnership, as well as
a 1.0% general partner interest in the Operating Partnership (an effective 16.6%
combined interest in the Partnership).
 
     The Lakehead Partnership holds a 1% general partner interest in Lakehead
Services, Limited Partnership ("Services Partnership"), a Delaware limited
partnership, originally formed to facilitate the financing of the Operating
Partnership.
 
     The Operating 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 Operating 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 Canadian Province of Ontario, principally to refineries,
either directly or through the connecting pipelines of other companies.
 
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
 
     The consolidated financial statements of the Partnership are prepared in
accordance with generally accepted accounting principles in the United States
and conform in all material respects with the historical cost accounting
standards of the International Accounting Standards Committee. 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.
 
PRINCIPLES OF CONSOLIDATION
 
     The financial statements of the Partnership include the accounts of the
Lakehead Partnership and the Operating Partnership on a consolidated basis. The
equity method is used to account for the Partnership's 1% general partner
interest in the Services Partnership. The General Partner's 1% interest in the
Operating Partnership is accounted for by the Partnership as a minority
interest.
 
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").
 
                                       F-7
<PAGE>   38
                       LAKEHEAD PIPE LINE PARTNERS, L.P.
 
        NOTES TO THE 1998 CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
 
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
REVENUE RECOGNITION
 
     Substantially all pipeline system revenues are derived from transportation
of crude oil and natural gas liquids and are recognized in income upon delivery.
Amounts provided for accrued rate refunds are recognized as a direct reduction
from revenues except for amounts related to prior years (Note 9), which are
separately stated as a provision for prior years' rate refunds.
 
CASH EQUIVALENTS AND SHORT-TERM INVESTMENTS
 
     Cash equivalents are defined as all highly marketable securities with a
maturity of three months or less when purchased. Short-term investments are
marketable securities with a maturity of more than three months when purchased.
Both are accounted for as held-to-maturity securities and valued at amortized
cost.
 
MATERIALS AND SUPPLIES
 
     Materials and supplies are stated at the lower of cost or market value.
 
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
 
     Expenditures for system expansion and major renewals and betterments are
capitalized; maintenance and repair costs are expensed as incurred. An allowance
for interest incurred on external borrowings during construction is capitalized.
Depreciation of property, plant and equipment is provided on the straight line
basis over their estimated service lives. When property, plant and equipment are
retired or otherwise disposed of, the cost less net proceeds is normally charged
to accumulated depreciation and no gain or loss 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 Partnership net income is borne by the
individual partners through the allocation of taxable income. Such taxable
income reportable to Unitholders may vary substantially from financial income as
a result of differences between the tax basis and financial reporting basis of
assets and liabilities and the taxable income allocation requirements under the
Partnership Agreement. The aggregate difference in the basis of the
Partnership's net assets for financial and tax reporting purposes cannot be
readily determined due to inaccessible information regarding each partner's tax
attributes in the Partnership.
 
COMPARATIVE AMOUNTS
 
     Certain comparative amounts are reclassified to conform with the current
year's financial statement presentation.
 
3. CASH DISTRIBUTIONS
 
     The Partnership distributes quarterly all of its "Available Cash", which is
generally defined in the Partnership Agreement as cash receipts less cash
disbursements and net additions to reserves for future requirements. These
reserves are retained to provide for the proper conduct of the Partnership
business and as necessary to comply with the terms of any agreement or
obligation of the Partnership. Distributions by the
                                       F-8
<PAGE>   39
                       LAKEHEAD PIPE LINE PARTNERS, L.P.
 
        NOTES TO THE 1998 CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
 
3. CASH DISTRIBUTIONS (CONTINUED)
Partnership of its Available Cash generally are made 98% to the Class A and B
Common Unitholders and 2% to the General Partner, subject to the payment of
incentive distributions to the General Partner to the extent that certain target
levels of cash distributions to the Unitholders are achieved. The incremental
incentive distributions payable to the General Partner are 15%, 25% and 50% of
all quarterly distributions of Available Cash that exceed target levels of
$0.59, $0.70, and $0.99 per Class A and B Common Units, respectively.
 
     In 1998, the Partnership paid cash distributions of $3.36 per unit
consisting of $0.78 per unit paid in February and $0.86 per unit paid in May,
August and November. In 1997, the Partnership paid cash distributions of $2.92
per unit consisting of $0.68 per unit paid in February and May, and $0.78 per
unit paid in August and November. In 1996, distributions of $2.60 per unit
consisted of $0.64 per unit paid in February, May and August, and $0.68 per unit
paid in November.
 
     The cash distribution in respect of the fourth quarter 1996 was the last
distribution subject to certain preferential rights of the Class A Common Units
and certain support obligations of the General Partner. These rights terminated
with the distribution paid in February 1997 and, with respect to subsequent cash
distributions, Class A and B Common Units are treated as one class of units.
 
4. NET INCOME PER UNIT
 
     Net income per unit is computed by dividing net income, after deduction of
the General Partner's allocation, by the weighted average number of Class A and
Class B Common Units outstanding. The General Partner's allocation is equal to
an amount based upon its 1% general partner interest, adjusted to reflect an
amount equal to incentive distributions and an amount required to reflect
depreciation on the General Partner's historical cost basis for assets
contributed on formation of the Partnership. Net income per unit was determined
as follows:
 
<TABLE>
<CAPTION>
                                                                 YEAR ENDED DECEMBER 31,
                                                                --------------------------
                                                                 1998      1997      1996
                                                                 ----      ----      ----
<S>                                                             <C>       <C>       <C>
Net income..................................................    $ 88.5    $ 78.3    $ 52.4
                                                                ------    ------    ------
Net income allocated to General Partner.....................      (0.9)     (0.8)     (0.5)
Adjusted to reflect:
  Incentive distributions...................................      (7.0)     (3.5)     (1.0)
  Historical cost basis depreciation........................      (0.1)     (0.1)     (0.1)
                                                                ------    ------    ------
                                                                  (8.0)     (4.4)     (1.6)
                                                                ------    ------    ------
Net income allocable to Common Units........................    $ 80.5    $ 73.9    $ 50.8
                                                                ======    ======    ======
Weighted average units outstanding (millions)...............      26.2      24.4      24.0
                                                                ======    ======    ======
Net income per unit.........................................    $ 3.07    $ 3.02    $ 2.11
                                                                ======    ======    ======
</TABLE>
 
                                       F-9
<PAGE>   40
                       LAKEHEAD PIPE LINE PARTNERS, L.P.
 
        NOTES TO THE 1998 CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
 
5. PROPERTY, PLANT AND EQUIPMENT, NET
 
<TABLE>
<CAPTION>
                                                                  AVERAGE           DECEMBER 31,
                                                                DEPRECIATION    --------------------
                                                                   RATES          1998        1997
                                                                ------------      ----        ----
<S>                                                             <C>             <C>         <C>
Land........................................................          --        $    6.2    $    6.1
Rights-of-way...............................................         3.6%          126.4        12.6
Pipeline....................................................         4.1%          783.0       519.6
Pumping equipment, buildings and tanks......................         4.6%          427.1       355.4
Vehicles, office and communications equipment...............        13.9%           28.8        27.4
Construction in progress....................................          --           115.8        87.4
                                                                                --------    --------
                                                                                 1,487.3     1,008.5
Accumulated depreciation....................................                      (191.1)     (158.2)
                                                                                --------    --------
                                                                                $1,296.2    $  850.3
                                                                                ========    ========
</TABLE>
 
6. DEBT
 
<TABLE>
<CAPTION>
                                                                   DECEMBER 31,
                                                                ------------------
                                                                 1998       1997
                                                                 ----       ----
<S>                                                             <C>        <C>
First Mortgage Notes........................................    $ 310.0    $ 310.0
Revolving Credit Facility Agreement.........................      305.0      153.0
Senior Unsecured Notes, Net.................................      199.5         --
                                                                -------    -------
                                                                $ 814.5    $ 463.0
                                                                =======    =======
</TABLE>
 
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 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 current
expansion projects. Under the Note Agreements, the Partnership is permitted to
make cash distributions not more frequently than quarterly in an amount not to
exceed Available Cash (Note 3) for the immediately preceding calendar quarter.
 
REVOLVING CREDIT FACILITY AGREEMENT
 
     The Partnership has a $350.0 million ($205.0 million prior to June 18,
1998) Revolving Credit Facility Agreement scheduled to mature during September
2003, but is subject to extension. Each year, on the anniversary date of the
facility, the current maturity date may be extended by one year subject to the
approval of the lending banks. 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 currently
attracts a facility fee of 0.075% (1997 - 0.075%, 1996 - 0.085%) per annum on
the entire $350.0 million ($205.0 million prior to June 18, 1998). At December
31, 1998, $305.0 million of the facility was utilized and is classified as
long-term debt (1997 - $153.0 million). The interest rate on loans averaged 5.8%
(1997 - 6.2%; 1996 - 6.8%) and was 5.5% at the end of 1998 (1997 - 6.2%).
 
                                      F-10
<PAGE>   41
                       LAKEHEAD PIPE LINE PARTNERS, L.P.
 
        NOTES TO THE 1998 CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
 
6. DEBT (CONTINUED)
SENIOR UNSECURED NOTES
 
     On October 1, 1998, the Operating Partnership issued a total of $200.0
million Senior Unsecured Notes in two tranches of $100.0 million. The first
tranche of $100 million carries an interest rate of 7.00% and matures in 2018.
The second tranche carries an interest rate of 7.125% and matures in 2028.
Interest on both tranches is payable semi-annually. The Senior Unsecured Notes
do not contain any financial tests restricting the issuance of additional
indebtedness.
 
INTEREST
 
     Interest expense includes $2.1 million related to accrued rate refunds
(1997 -$3.5 million; 1996 - $9.7 million) and is net of amounts capitalized of
$25.5 million (1997 - $3.3 million; 1996 - $2.4 million). Interest paid amounted
to $44.4 million (1997 - $39.9 million; 1996 - $44.8 million).
 
7. 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 $34.9 million (1997 - $33.2 million; 1996 -$33.9
million) and are included in operating and administrative expenses. At December
31, 1998, the Partnership has accounts payable to the General Partner and
affiliates of $2.9 million (1997 - $3.9 million).
 
     Under the terms of the Revolving Credit Facility Agreement, the Services
Partnership and the Partnership may draw down funds up to a combined maximum of
$350.0 million ($205.0 million prior to June 18, 1998). The Partnership is
entitled to require the Services Partnership to repay any amounts owed by the
Services Partnership in order to allow the Partnership to borrow thereunder.
During 1996, the Partnership paid the Services Partnership a standby fee of $0.4
million for this entitlement. Effective September 1996, the standby fee was
eliminated and replaced with a facility fee, which the Partnership pays directly
to the lenders. The Partnership will continue to have borrowing priority over
the Services Partnership. At December 31, 1998, the Services Partnership had no
borrowings under the facility.
 
     The Partnership has entered into an easement acquisition agreement with
Enbridge Holdings (Mustang) Inc. ("Enbridge Mustang") (formerly IPL Patoka
Pipeline Holdings (U.S.A.) Inc.), an affiliate of the General Partner. Enbridge
Mustang has acquired certain real property for the purpose of granting pipeline
easements to the Partnership for a new pipeline constructed by the Partnership
from Superior, Wisconsin to Chicago, Illinois. The Partnership has made
non-interest bearing cash advances to Enbridge Mustang in order to provide for
these real property acquisitions by Enbridge Mustang. These advances amounted to
$32.0 million at December 31, 1998 (1997 - $6.5 million).
 
     During the third quarter of 1998, the Board of Directors of the General
Partner approved a $200.0 million lending facility from the General Partner to
the Partnership to provide an alternative backup source of funds in the event
that a temporary disruption in the capital markets delays anticipated debt and
equity issuances. Under this facility, in late September 1998, the Partnership
borrowed $37.0 million from the General Partner at an interest rate of 8.75%.
This loan was repaid in early October upon completion of the Operating
Partnership's Senior Unsecured Note offering. No amounts were outstanding at
December 31, 1998.
 
                                      F-11
<PAGE>   42
                       LAKEHEAD PIPE LINE PARTNERS, L.P.
 
        NOTES TO THE 1998 CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
 
8. MAJOR CUSTOMERS
 
     Operating revenue received from major customers was as follows:
 
<TABLE>
<CAPTION>
                                                                YEAR ENDED DECEMBER 31,
                                                                -----------------------
                                                                1998     1997     1996
                                                                ----     ----     ----
<S>                                                             <C>      <C>      <C>
Amoco Oil Company...........................................    $57.9    $60.7    $63.2
Mobil Oil Company of Canada Ltd.............................    $40.0    $42.5    $37.2
Imperial Oil Limited........................................    $33.6    $33.2    $35.4
</TABLE>
 
     The Partnership has a concentration of trade receivables from companies
operating in the oil and gas industry. These receivables are collateralized by
the crude oil and other products contained in the Partnership's pipeline and
storage facilities.
 
9. ACCRUED RATE REFUNDS AND RELATED INTEREST
 
     In October 1996, the FERC approved a July 1996 agreement ("Settlement
Agreement") between the Partnership and customer representatives on all
outstanding contested tariff rates. The Settlement Agreement resulted in an
approximate tariff rate reduction of 6% and total rate refunds and related
interest of $120.0 million through the effective date of October 1, 1996.
 
     The Partnership provided for $42.6 million of rate refunds and related
interest in 1996 to reflect the Settlement Agreement. Of the amount provided,
rate refunds related to 1996 of $12.8 million have reduced operating revenue,
with prior years' portion, $20.1 million, separately stated as a provision for
prior years' rate refunds. Rate refund interest expense for 1996 and prior year
amounts totaling $9.7 million were recorded in interest expense. The balance of
the $120.0 million of accrued rate refunds and related interest required under
the Settlement Agreement was provided for prior to 1996.
 
     Refunds required under the Settlement Agreement began in 1996 with $41.8
million repaid during the fourth quarter of 1996, with the remaining balance
being repaid through a 10% reduction on future rates. This reduction will
continue until all refunds have been made, which is expected to remain effective
until sometime during the second half of 1999. During 1998, refunds of $28.5
million (1997 - $27.7 million) were made to customers and interest expense of
$2.1 million (1997 - $3.5 million) was recorded by the Partnership. Interest
will continue to accrue on the unpaid balance based on the 90-day Treasury bill
rate.
 
10. 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 (if not covered through
insurance), the General Partner has agreed to indemnify the Partnership from and
against any costs relating to environmental liabilities associated with the
pipeline system prior to its 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 for the purpose
of assessing whether any remediation is required in light of current
regulations, and to date no material environmental risks have been identified.
 
                                      F-12
<PAGE>   43
                       LAKEHEAD PIPE LINE PARTNERS, L.P.
 
        NOTES TO THE 1998 CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
 
10. CONTINGENCIES (CONTINUED)
OIL IN CUSTODY
 
     The Partnership transports crude oil and natural gas liquids ("NGL") owned
by its customers for a fee. The volume of liquid hydrocarbons in the
Partnership's pipeline system at any one time approximates 12 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 NGL in the Partnership's custody.
 
11. FAIR VALUE OF FINANCIAL INSTRUMENTS
 
     The carrying amounts of cash equivalents and short-term investments
approximate fair value. The short-term investments consist of high quality
commercial paper.
 
     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 $369 million (1997 - $363 million) and the
fair value of the Senior Unsecured Notes approximates $209 million. Due to
defined contractual arrangements, refinancing of the First Mortgage Notes and
Senior Unsecured Notes would not result in any financial benefit to the
Partnership.
 
                                      F-13
<PAGE>   44
 
                       LAKEHEAD PIPE LINE PARTNERS, L.P.
 
                     SUPPLEMENTARY INFORMATION (UNAUDITED)
                       SELECTED QUARTERLY FINANCIAL DATA
                 (DOLLARS IN MILLIONS, EXCEPT PER UNIT AMOUNTS)
 
<TABLE>
<CAPTION>
                                         FIRST     SECOND    THIRD     FOURTH     TOTAL
                                         -----     ------    -----     ------     -----
<S>                                      <C>       <C>       <C>       <C>       <C>
1998 QUARTERS
Operating revenue....................    $ 72.9    $ 74.4    $ 70.2    $ 70.2    $ 287.7
Operating income.....................    $ 28.0    $ 28.6    $ 27.2    $ 21.6    $ 105.4
Net income...........................    $ 22.9    $ 24.2    $ 22.6    $ 18.8    $  88.5
Net income per unit(1)...............    $ 0.80    $ 0.85    $ 0.78    $ 0.64    $  3.07
</TABLE>
 
<TABLE>
<CAPTION>
                                         FIRST     SECOND    THIRD     FOURTH     TOTAL
                                         -----     ------    -----     ------     -----
<S>                                      <C>       <C>       <C>       <C>       <C>
1997 QUARTERS
Operating revenue....................    $ 68.7    $ 66.9    $ 72.3    $ 74.2    $ 282.1
Operating income.....................    $ 25.7    $ 26.9    $ 27.1    $ 28.4    $ 108.1
Net income...........................    $ 17.7    $ 19.2    $ 19.4    $ 22.0    $  78.3
Net income per unit(1)...............    $ 0.71    $ 0.75    $ 0.76    $ 0.80    $  3.02
</TABLE>
 
---------------
(1) The General Partner's allocation of net income has been deducted before
    calculating net income per unit.
 
                                      F-14