LAKEHEAD PIPELINE CO LP, 10-K405, 2000-03-24

LAKEHEAD PIPELINE CO LP
10-K405, 2000-03-24
PIPE LINES (NO NATURAL GAS)

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

FORM 10-K

/x/	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended DECEMBER 31, 1999

/ /	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from to

Commission File Number: 333-59597

LAKEHEAD PIPE LINE COMPANY, LIMITED PARTNERSHIP
(Exact name of Registrant as specified in its charter)

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

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: None

Securities registered pursuant to Section 12(g) of the Act: NONE

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

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

DOCUMENTS INCORPORATED BY REFERENCE: NONE

TABLE OF CONTENTS

		Page
	PART I
Items 1 & 2.	Business and Properties	3
Item 3.	Legal Proceedings	14
Item 4.	Submission of Matters to a Vote of Security Holders	15
	PART II
Item 5.	Market for Registrant's Common Equity and Related Stockholder Matters	16
Item 6.	Selected Financial Data	16
Item 7.	Management's Discussion and Analysis of Financial Condition and Results of Operations	17
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	23
Item 8.	Financial Statements and Supplementary Data	24
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	24
	PART III
Item 10.	Directors and Executive Officers of the Registrant	25
Item 11	Executive Compensation	26
Item 12.	Security Ownership of Certain Beneficial Owners and Management	26
Item 13.	Certain Relationships and Related Transactions	26
	PART IV
Item 14.	Exhibits, Financial Statement Schedules and Reports on Form 8-K	28
Signatures		30
Index to Financial Statements, Supplementary Information and Financial Statement Schedules		F-1

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,
•: regulation of the Partnership's tariffs by the Federal Energy Regulatory Commission and the possibility of unfavorable outcomes of future tariff proceedings, 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.

PART I

Items 1 & 2. Business and Properties

Overview

Lakehead Pipe Line Company, Limited Partnership ("Registrant," "Operating Partnership" or "Partnership") is a 98.9899% owned operating subsidiary partnership of Lakehead Pipe Line Partners, L.P. ("Lakehead Partnership"), a publicly traded Delaware limited partnership. The Registrant is, also a Delaware limited partnership. Unless the context requires, references in this Form 10-K to the Partnership include the Registrant and the Lakehead 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"). Enbridge Pipelines is a Canadian company owned by Enbridge Inc. ("Enbridge") of Calgary, Alberta, Canada. The General Partner owns a 1.0101% general partner interest in the Registrant. The remaining 98.9899% limited partner interest in the Partnership is owned by the Lakehead Partnership.

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 the province of Ontario, Canada. The System serves all the major refining centers in the Great Lakes region of the United States, as well as Ontario and the Patoka/Wood River pipeline hub and refining center 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 3,100 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 15 connections to pipelines and refineries at various locations in the United States, including the refining areas in and around Chicago, Illinois, Minneapolis-St. Paul, Minnesota, Detroit, Michigan, Toledo, Ohio, Buffalo and Patoka/Wood River. The Lakehead System has three main terminals at Clearbrook, Minnesota, Superior, and Griffith, Indiana. The terminals are used to gather crude oil prior to injection into the Lakehead System and to provide tankage in order to allow for more flexible scheduling of oil movements.

Properties

The Lakehead System consists of approximately 3,300 miles of pipe with diameters ranging from 12 inches to 48 inches, 63 main line pump station locations with a total of approximately 667,000 installed

horsepower and 58 crude oil storage tanks with an aggregate working capacity of approximately 10 million barrels. The volume of liquid hydrocarbons in the Lakehead System required at all times for operation is approximately 14 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, respectively, and a fifth line consisting of 36- and 48-inch diameter pipe with a total annual capacity of 1,738,000 barrels per day;
•: 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 includes approximately 80 miles of 48-inch pipeline looping that increases the annual capacity of this segment;
•: 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 consisting of a 30-inch diameter pipe with an annual capacity of 333,000 barrels per day;
•: Canadian border to Buffalo segment consisting of 12- and 20-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 reflect the additional capacity provided by Phase I of the Terrace Expansion Program ("Terrace"), which was completed during 1999. See "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations, —Terrace Expansion Program."

The Partnership believes that the Lakehead System has been constructed and is maintained substantially in accordance with applicable federal, state and local laws and regulations, standards prescribed by the American Petroleum Institute 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. At intervals not exceeding 3 weeks, but at least 26 times each calendar year, the entire pipeline right of way is inspected from the air. In addition, trained and skilled operators use computerized monitoring systems to identify pressure drops 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.

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 and occupied by the Partnership, pursuant to easements or permits. An affiliate of the General

Partner acquired parcels of property for the benefit of the Partnership to allow for the construction of the System Expansion Program II ("SEP II"). The affiliate is in the process of selling these parcels to third parties while retaining an easement for transfer to the Partnership at fair market value. 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. Although the price of crude oil has recovered from the extreme low prices experienced in late 1998 and early 1999, throughput on the system has not returned to early 1998 levels. Drilling activity and production volumes have been slow to rebound due to tight access to equity markets. For a discussion of the forecast for 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 U.S. Midwest, 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."

The Enbridge Pipelines System includes a section that extends from Sarnia, Ontario to Montreal, Quebec ("Line 9") which, at one time, flowed in a west-to-east direction. During 1999, Enbridge Pipelines and a group of refiners reversed the flow of Line 9. Consequently, crude oil is now imported into the province of Quebec, Canada from foreign sources through the facilities of Portland Pipe Line Corporation, Montreal Pipe Line Limited and Enbridge Pipelines. This new offshore crude oil supply has resulted in a decrease in the Partnership's 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 is subject to the risk that changes may occur in existing economic conditions, fuel conservation measures, alternative fuel requirements, governmental regulation or technological advances in fuel economy and energy generation devices, any of 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 essentially in 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 periodically files tariff rate increases and decreases with the Federal Energy Regulatory Commission ("FERC"). A tariff agreement between the Partnership and customer representatives sets forth parameters governing the tariff changes associated with SEP II, Terrace, and other expansion projects. Not withstanding this agreement, any shipper who is not a party to the agreement could challenge any existing or future rate filings. Any challenge, if successful, could have a material adverse effect on the Partnership. For a discussion of FERC regulation, Partnership tariff rates, and the tariff agreement, see "—Regulation" and "—Tariffs."

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 index for use beginning on July 1, 1999, was approximately negative 1.8%. Inflationary rate changes prescribed under the FERC's indexing methodology may be different than changes in the Partnership's costs. Indexed rates are subject both to protests and to complaints, but in either case the FERC's existing regulations specify that the party challenging a rate must show reasonable grounds for asserting that the amount of any rate increase resulting from application of the index is so substantially in excess of the pipeline's increase in costs as to be unjust and unreasonable (or 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 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 from 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.

Tariffs

Rate Cases

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

In October 1996, the FERC approved 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 were made. Effective November 22, 1999, the 10% reduction in tariff rates was removed and the $120.0 million refund and related interest have now been fully repaid.

The Settlement Agreement also provided for the terms of an incremental tariff rate surcharge for a period of 15 years to recover the cost of, and allow a return on, the Partnership's investment in SEP II. The rate of return on this investment 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 is 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 a case involving Santa Fe Pacific Pipeline, L.P. ("SFPP") that addressed various issues of interest to FERC-regulated publicly traded partnerships and other oil pipelines. These included application of FERC's Opinion No. 154-B/C rate

methodology and income tax allowances for publicly traded partnerships. The 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 is not changed on rehearing by FERC or on review by a court of appeals, and if it were applied to the Partnership in some future rate proceedings, the impact to the Partnership, positive or negative, would be dependent upon the specific application of the rulings in that opinion to the Partnership.

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 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 key receipt locations to principal delivery points at January 1, 2000 (including the tariff surcharges related to SEP II and Terrace) are set forth below.

	Published Tariff Per Barrel
Canadian border near Neche to Clearbrook	$	0.164
Canadian border near Neche to Superior	$	0.319
Canadian border near Neche to Chicago area	$	0.650
Canadian border near Neche to Marysville area	$	0.751
Canadian border near Neche to Buffalo area	$	0.796
Chicago to the international border near Marysville	$	0.289

The rates at January 1, 2000, 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 an updated SEP II surcharge to be effective April 1, 2000. This filing will include any differences between the SEP II surcharge filed in 1999 and actual results for the year, as well as an estimate for 2000. Overall, the surcharge should remain relatively consistent with 1999 levels.

Deliveries from the Lakehead System

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

The U.S. government segregates the United States into five 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 through the next 10 years.

The following table sets forth Lakehead System average deliveries per day and barrel miles for each of the years in the five-year period ended December 31, 1999.

	Deliveries
	1999	1998	1997	1996	1995
	(thousands of barrels per day)
United States
Light crude oil	299	338	282	309	345
Medium and heavy crude oil	575	627	652	569	513
NGL	24	27	26	23	18

Total United States	898	992	960	901	876

Ontario
Light crude oil	282	366	355	348	332
Medium and heavy crude oil	87	97	98	102	96
NGL	102	107	99	100	105

Total Ontario	471	570	552	550	533

Total Deliveries	1,369	1,562	1,512	1,451	1,409

Barrel miles (billions per year)	350	391	389	384	385

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 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 complements the Terrace Phase I facilities 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 ("Terrace Forecast"). 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 Terrace 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 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 Terrace Forecast quantity of crude oil supply 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.

The low crude oil prices experienced during 1998 and early 1999 have impacted the crude oil supply available in western Canada. Enbridge Pipelines has updated its forecast of western Canadian crude oil supply and the related markets. This long-term outlook is partially based on supply projections from the oil sands projects currently operating, being expanded or proposed in western Canada. The Partnership believes that production from these projects is less sensitive to the short-term fluctuations in the price of crude oil due to the magnitude of committed capital expenditures involved. The updated forecast projects the supply of western Canadian crude oil to be lower during the period 2000 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 rise to 2,500,000 barrels per day in 2003, rising to over 2,600,000 barrels per day from 2004 through 2010. Crude oil prices have recovered from the unprecedented long low price period in 1998 due to the supply constraints imposed in April 1999 by OPEC. At December 31, 1999, the benchmark West Texas Intermediate ("WTI") crude oil price closed at $25.60 per barrel, up from the 1998 low of $10.73 per barrel. Current expectations are for WTI prices to average $24.00 per barrel in 2000, which would continue to support the projected growth in supply from western Canada.

The NEB released a report titled "Canadian Energy Supply and Demand to 2025" on June 30, 1999, in which it provided several scenarios of supply and demand for western Canadian crude oil. The most realistic scenario from the Partnership's perspective is a case that is based on a WTI price of $18.00 per barrel in constant 1997 dollars and assumes low cost energy supply and current trends in demand. This scenario resulted in total western Canadian production which was modestly lower than the Enbridge Pipelines forecast by 35,000 barrels per day in 2000, 84,000 barrels per day in 2005 and 59,000 barrels per day in 2010. CAPP released its forecast of western Canadian crude oil production on May 18, 1999. The Enbridge Pipelines forecast is higher than CAPP's forecast by 30,000 barrels per day in 2000, 50,000 barrels per day in 2005 and 43,000 barrels per day by 2010. Comparison of the Enbridge Pipelines forecast to these two forecasts indicates that they are all very close with the greatest variance of approximately 3%.

Despite the slow recovery in drilling activity in western Canada, it is anticipated that 2000 deliveries on the Lakehead System could be approximately 100,000 barrels per day more than 1999 delivery levels of 1,369,000 barrels per day.

The Partnership believes that the outlook regarding future growth prospects continues to be positive, as evidenced by the NEB and the CAPP forecast, and that the potential for increased crude oil production in western Canada remains encouraging. The timing of growth in the supply of western Canadian crude oil, however, will depend upon the level of crude oil prices and drilling activity.

Demand

Constant 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. The Partnership believes that 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 over the past year. 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 compared to PADD 2.

Based on the most 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 550,000 barrels per day higher than 1998 exports. Of the exports to the United States, PADD 2 would receive approximately 1,470,000 barrels per day in 2005, approximately 570,000 barrels per day higher than 1998. 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. Recovery in PADD 2 exports is expected in 2000 with long-term exports surpassing Terrace Forecast levels by 2005.

Deliveries to Ontario averaged approximately 471,000 barrels per day in 1999. Demand in Ontario is expected to grow to approximately 640,000 barrels per day over the next several years. Partnership deliveries to Ontario are, however, expected to continue to decline due to the availability of offshore crude oil supply through 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 Ontario are generally configured to process light sweet and light sour crude oil. While Canadian crude oil supplies have generally increased over the last several years, the supply of conventional light sweet and light sour crude oil in western Canada is expected to decline. Ontario refiners cannot process significantly greater amounts of western Canadian heavy crude oil without substantial reconfiguration of their refineries. To the extent Ontario refiners have found it difficult to obtain light crude oil supply from western Canada at an economic price, refiners have been recently accessing foreign light crude volumes through the reversed facilities of Line 9. This has had an impact on the volumes moving through the Lakehead System pipeline connections in the Chicago area. Light crude oil movements originating in the Chicago area for delivery to Ontario had increased from approximately 70,000 barrels per day in 1997 to approximately 110,000 barrels per day in 1998. However, these movements declined following the reversal of the Enbridge's Line 9 in 1999, averaging approximately 65,000 barrels per day for the year, and 30,000 barrels in the fourth quarter of 1999.

Customers

The Lakehead System operates under month-to-month transportation arrangements with its shippers. During 1999, 49 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 Ontatio, major oil companies, refiners and marketers. Shipments by the top ten shippers during 1999 accounted for approximately 84% of total revenues during that period. Revenue from BP Amoco (through affiliated companies), Mobil Oil Company of Canada Ltd. and Imperial Oil Limited accounted for approximately 24%, 14% and 10%, respectively, of total operating revenue generated by the Lakehead System during 1999. The remaining shippers each accounted for less than 10% of total revenues.

Capital Expenditures

In 1999, the Partnership made capital expenditures of $82.9 million, of which $30.8 million was for SEP II, $33.2 million for Terrace and $18.9 million for core maintenance and pipeline system enhancements. 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 Lakehead 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 1999, the Enbridge Pipelines System transported approximately 65% of total western Canadian crude oil production, of which more than 85% was transported by the Lakehead System. The remainder of 1999 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 U.S. Northwest.

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

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, which began service in early 1997, serves the Patoka/Wood River market area. The System, however, offers lower tolls into Chicago and Patoka and competitive tolls into Wood River and, furthermore, the System does not require shipper volume commitments as currently required by Express Pipeline.

The System encounters competition in serving shippers to the extent that shippers have 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 65% of all crude oil deliveries into the Minneapolis-St. Paul area and approximately 90% of all deliveries of crude oil to Ontario and Buffalo.

Please refer to "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations, —Montreal Extension Reversal," for discussion of the reversal of the Montreal Extension which resulted in availability of competing offshore crude oil supplies in 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 (if not recovered through insurance), the Partnership could be subject to material costs.

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

Air

The operations of the Partnership are subject to the federal Clean Air Act and comparable state statutes.

Water

The federal Clean Water Act ("CWA") (consisting of the Water Pollution Control Act of 1972, as amended by the Clean Water Act of 1977, and as further amended by the Oil Pollution Act of 1990) imposes strict controls on the discharge of any pollutant, including oil, into the waters of the United States. The CWA provides penalties for any such discharge, imposes liability for clean-up costs and natural resource damage, and allows for third party lawsuits. As required by the CWA, the Partnership has developed Facility Response Plans, which are designed to prevent contamination of waters in the event of a petroleum overflow, rupture or leak, and has submitted these Plans to, and received the approval of, the Office of Pipeline Safety ("OPS") of the U.S. Department of Transportation ("DOT"). The federal Safe Drinking Water Act of 1974, as amended, further regulates discharges into groundwater. State laws also provide varying civil and criminal penalties and liabilities in the case of a release of pollutants into surface water or groundwater. Expenses of routine compliance with these and other similar regulations are not expected to have a material adverse impact on the Partnership.

Remediation Matters

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

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 has been amended periodically requiring OPS to consider environmental impacts and cost-benefit analysis, in addition to its traditional public safety considerations, when developing safety regulations. The amendments also mandated OPS to establish pipeline operator qualification rules which were issued in 1999. Other requirements in the amendments include mandating OPS to establish a national pipeline mapping and records system, evaluating the feasibility of requiring additional valves and/or remotely operated valves and completing the identification of areas "unusually environmentally sensitive" to leaks from liquid pipelines. Accordingly, in December 1999, the OPS announced the proposed definition of "unusually environmentally sensitive" and a pilot test validating the definition with respect to liquid pipelines. Additional legislation has recently been proposed which could, if fully enacted by Congress, require OPS to delegate authority for interstate pipeline safety oversight to states, certify pipeline employee's qualifications and require extensive internal and pressure testing on a five-year frequency, in addition to other proposals. The OPS has also committed to issue new regulations by December 2000 which would mandate enhanced integrity assurance through internal or pressure testing in certain high consequence areas defined by their population or environmental sensitivity.

These most recent legislative and regulatory proposals are prompted by a significant accident in June 1999 on the Olympic Pipeline system in Bellingham, Washington. The Partnership has been monitoring these proposals closely and working with industry associations to advocate alternative amendments that will result in cost-effective pipeline safety. As these proposals are still before Congress, the financial impact of any new mandates can not be determined at this time.

Employees

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

On three occasions in the summer and fall of 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 and the State of Illinois have entered into an agreement wherein the State has agreed to release the Partnership from liability resulting from the discharges. In return, the Partnership has agreed to transfer to the Illinois Department of Natural Resources ("DNR") seven acres of the affected wetlands and to pay the State $10,000 for educational or conservation purposes and $14,000 for the DNR to carry out invasive species removal in the wetlands.

In a separate action related to the drilling mud discharge in the wetlands area, the U.S. Environmental Protection Agency ("EPA") filed an administrative complaint against the Partnership on August 20, 1999, proposing a civil penalty of approximately $83,000 for violations of the CWA resulting from the bentonite discharges into the wetlands. Representatives of the Partnership met with the EPA and negotiated a Consent Order that has been signed by both the EPA and the Partnership and took effect

November 5, 1999. Pursuant to the Consent Order, the Partnership paid a civil penalty of approximately $14,000 and has performed a Supplemental Environmental Project consisting of a contribution of approximately $46,000 to a conservation foundation in Illinois used to purchase twelve acres of environmentally sensitive property on the Fox River near Chicago. As part of the Project, the conservation foundation has contributed this property to the Illinois DNR for management and preservation. This Project was undertaken in connection with the settlement of an enforcement action taken by the U.S. EPA for alleged violation of Section 301 of the Clean Water Act, 33 United States Code Section 1311.

In December 1999, the Partnership paid to the Illinois DNR a penalty of $98,000 and costs of $2,000 for a May 28, 1998 release of crude oil caused by a third party in Orland Park, Illinois. The Partnership, the third party and the Illinois Attorney General have executed a Consent Order which was entered in district court in November 1999. The Partnership is in the midst of litigation against the third party to recoup the penalty and all other costs incurred by the Partnership in connection with the May 28 release.

The Partnership received a draft complaint on September 21, 1999, from the Department of Justice for the State of Wisconsin alleging violations of state pollution control regulations during construction on SEP II in the summer of 1998. The first violation alleges that the Partnership failed to monitor all discharges of water from SEP II construction trenches and, on certain occasions, exceeded the effluent limitations set forth in a permit. The second and unrelated violation alleged in the draft complaint states that the Partnership failed to immediately report a release of NGL from its Superior terminal in mid-January 1999. The Partnership is currently in negotiations with the Attorney General's office regarding the amount of the penalty to be paid. It is anticipated that the penalty will not 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 1999.

PART II

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

None.

Item 6. Selected Financial Data

The following table sets forth, for the periods and at the dates indicated, summary historical financial and operating data for the Partnership. The table is derived from the consolidated financial statements of the Partnership and notes thereto, and should be read in conjunction with those audited financial statements.

	Year ended December 31,
	1999			1998			1997			1996(1)			1995(1)
	(dollars in millions, except per unit amounts)
Income Statement Data:
Operating revenue	$	312.6		$	287.7		$	282.1		$	274.5		$	268.5
Operating expenses(2)		182.3			182.3			174.0			187.1			195.2

Operating income		130.3			105.4			108.1			87.4			73.3
Interest and other income		3.4			5.9			9.7			9.6			7.1
Interest expense		(54.1	)		(21.9	)		(38.6	)		(43.9	)		(40.3	)

Net Income		79.6			89.4			79.2			53.1			40.1

Financial Position Data (at year end):
Property, plant and equipment, net	$	1,321.3		$	1,296.2		$	850.3		$	763.5		$	725.1
Total assets	$	1,413.5		$	1,414.2		$	1,063.1		$	975.8		$	915.1
Long-term debt	$	784.5		$	814.5		$	463.0		$	463.0		$	395.0
Partners' capital
Limited Partner		585.9			494.8			501.7			399.5			411.0
General Partner		3.6			2.6			2.5			1.4			1.4

	$	586.1		$	495.0		$	501.8		$	399.6		$	411.1

	$	589.5		$	497.4		$	504.2		$	400.9		$	412.4

Cash Flow Data:
Cash provided from operating activities	$	101.6		$	103.6		$	106.6		$	93.9		$	121.5
Cash used in investing activities	$	(91.1	)	$	(427.9	)	$	(101.7	)	$	(84.7	)	$	(54.0	)
Cash provided from (used in) financing activities	$	(17.5	)	$	252.7		$	24.1		$	3.4		$	(32.5	)
Capital expenditures included in investing activities	$	(82.9	)	$	(487.3	)	$	(126.9	)	$	(76.7	)	$	(35.5	)
Operating Data:
Barrel miles (billions)		350			391			389			384			385
Deliveries
(thousands of barrels per day)
United States		898			992			960			901			876
Ontario		471			570			552			550			533

		1,369			1,562			1,512			1,451			1,409

(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.

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

1999 was a challenging year for the Partnership. Major capacity expansions of the System were completed; however, deliveries of crude oil decreased compared to 1998 levels due to low world crude oil prices experienced in 1998 and early 1999. Despite the downturn in volumes on the System in 1999, the Board of Directors of the General Partner announced the fourth consecutive annual increase in the quarterly cash distribution on April 15, 1999, given the positive outlook for the long-term utilization of the System. The quarterly cash distributions increased to $0.875 per unit ($3.50 on an annualized basis) from $0.86 per unit.

While pipeline capacity has increased 18% over the past two years, deliveries fell during 1999 from record levels achieved in 1998. Crude oil and NGL deliveries averaged 1,369,000 barrels per day in 1999, down from the record 1,562,000 barrels in 1998, representing a 12% decline in Lakehead System deliveries. After hitting a 10-year low in 1998, world crude oil prices increased significantly during 1999. However, the extreme low prices in 1998 and early 1999 caused drilling and production activity in western Canada to drop to its lowest level since 1993.

Although prices started to improve late in the first quarter of 1999, producers of crude oil have been cautious to reinvest in exploration and production until the higher prices could be sustained. Also, western Canadian producers had limited access to capital markets while uncertainty over crude oil prices prevailed for most of the year. As oil prices continued to rise during 1999, western Canadian crude oil producers developed confidence in the sustainability of the price, and drilling activity started to increase in the fourth quarter. Despite the volatile crude oil price situation over the last two years, western Canadian producers remain committed to their heavy oil development projects, and long-term prospects for increased crude oil production remain positive. See "—Future Prospects".

Results of Operations

Net income for 1999 was $78.7 million ($2.48 per unit) compared with $88.5 million ($3.07 per unit) for 1998 and $78.3 million ($3.02 per unit) for 1997. Net income for 1999 was $9.8 million lower than 1998 primarily due to higher interest and depreciation costs offset partially by increased operating revenue and lower power costs. Net income per unit decreased $0.59 primarily due to the reduction in net income and an increase in the number of weighted average units outstanding during 1999 compared with 1998. Due to the issuance of 2.7 million Class A Common Units during April 1999, the weighted average number of Common Units outstanding increased from 26.2 million in 1998 to 28.0 million in 1999.

Net income in 1998 improved $10.2 million in comparison with 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 despite a greater number of weighted average units outstanding during 1998 compared with 1997.

Operating revenue for 1999 was $312.6 million, or $24.9 million greater than 1998. The increase was primarily due to higher tariffs implemented for SEP II on January 1, 1999 and for Terrace on April 1, 1999. The SEP II tariff rate varies with utilization of the SEP II capacity and is recomputed on a cost of service basis and filed with the FERC each year. For Terrace, a fixed toll increase of $0.013 per barrel for the movement of light crude oil from the Canadian border to the Chicago area was implemented. The increase in operating revenue from the impact of the tariffs was partially offset by the decrease in deliveries and by a tariff reduction of 1.83% on July 1, 1999, as required under the FERC's indexing methodology.

Crude oil and NGL deliveries averaged 1,369,000 barrels per day in 1999, down from the record 1,562,000 barrels in 1998, which increased 3% when compared with 1997. The decline in deliveries in 1999 was due to the impact of low world crude oil prices in 1998 and early 1999. Until 1999, higher deliveries resulted from greater crude oil production in western Canada and increased transportation of foreign and U.S. crude received in the Chicago area for transportation to Ontario, combined with increased pipeline

capacity from the Partnership's expansion programs. System utilization, measured in barrel miles, decreased during 1999 primarily due to crude oil price related production declines.

Operating revenue for 1998 was $287.7 million, or $5.6 million greater than 1997, primarily due to increased deliveries and the transportation of a greater proportion of heavy crude oil (up 9% to 625,000 barrels per day). The Partnership's tariff rate for medium and heavy crude oil deliveries to the Chicago area was approximately 8% and 20% higher, respectively, than that for lighter crude oils. Operating revenue was also favorably impacted by the full year effect of a July 1997 tariff rate increase of 1.6%, which was partially offset by a 0.6% tariff decrease on July 1, 1998.

Total operating expenses of $182.3 million in 1999 were at the same level as 1998. Power costs declined due to lower throughput volumes and operating efficiencies gained from the expanded pipeline facilities. Operating and administrative costs were relatively stable, as increased oil losses due to operational changes on the System, were offset by lower maintenance activities during 1999. Increased depreciation charges, pertaining to the expansions, commenced effective with the tariff increases, although the higher expense was partially mitigated by a FERC approved reduction of depreciation rates effective January 1, 1999.

Total 1998 operating expenses 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 slightly mainly due to higher rents for rights-of-way as a result of the renewal of certain lease agreements that expired during the year and additional maintenance costs associated with an increased level of internal pipeline inspection. Depreciation expense increased due to the growth in property, plant and equipment.

Interest expense of $54.1 million in 1999 increased $32.2 million from 1998 primarily due to additional debt financing arranged to fund a portion of the recent expansion projects. As well, capitalized interest was higher in 1998 due to the significant construction projects ongoing throughout the year. Interest is capitalized as part of the cost of constructing capital projects and interest capitalization generally ceases once a capital project is complete and ready for service.

Interest expense for 1998 decreased $16.7 million from 1997 due to the capitalization of interest costs associated with SEP II and Terrace.

Liquidity and Capital Resources

At December 31, 1999, cash and cash equivalents totaled $40.0 million, down $7.0 million from December 31, 1998. Of this $40.0 million, $27.9 million ($0.875 per unit) was set aside for the cash distribution payable on February 14, 2000, with the remaining $12.1 million available for capital expenditures and other business needs.

Cash generated from operating activities in 1999 decreased by $2.0 million from 1998 to $101.6 million as the impact of lower net income and changes in operating assets and liabilities was primarily offset by higher non-cash depreciation expense. Cash generated from operating activities in 1998 decreased by $3.0 million from 1997 to $103.6 million, as higher net income was offset by changes in operating assets and liabilities.

In response to the October 1996 Settlement Agreement, the Partnership made rate refunds of $29.4 million in 1999, $28.5 million in 1998 and $27.7 million in 1997 through a 10% reduction in tariff rate collections. The rate refund obligation was repaid during 1999 and the 10% tariff credit was cancelled effective November 22, 1999.

In 1999, the Partnership made capital expenditures of $82.9 million, of which $30.8 million was for SEP II, $33.2 million for Terrace, and $18.9 million for core maintenance and pipeline system enhancements. In 1998, the Partnership incurred capital expenditures of $487.3 million, including $358.0 million for SEP II and $112.7 million for Terrace.

The Partnership anticipates spending approximately $11.5 million for pipeline system enhancements and $9.7 million for core maintenance activities in 2000. Excluding major expansion projects, ongoing capital expenditures are expected to average approximately $20.0 million on an annual basis (approximately 50% for core maintenance and 50% for enhancement of the pipeline system). Core maintenance activities, such as the replacement of equipment and preventive maintenance programs, will be undertaken to enable the Partnership's pipeline 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 it 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. Based on existing legislation, future environment and safety expenditures are not anticipated to have a material impact on the Partnership's results of operations.

At December 31, 1999, the Partnership had outstanding $7.5 million of advances made to an affiliate of the General Partner. The advances relate to acquisitions of real property associated with the construction of SEP II. As the real property is disposed of, the advances are repaid to the Partnership. During 1999, $24.5 million was repaid. See Note 6 to the Partnership's Financial Statements.

At December 31, 1999, 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. The Partnership has a $350.0 million Revolving Credit Facility. Total borrowings of $275.0 million were outstanding under the facility at December 31, 1999. Interest rates on this facility are variable and at the end of 1999 were approximately 5.9%.

In October 1998, pursuant to a $400.0 million shelf registration statement filed with the Securities and Exchange Commission ("SEC"), $200.0 million face amount of senior unsecured notes were issued to retire borrowings under the Revolving Credit Facility and to repay a loan of $37.0 million that had been advanced by the General Partner. The Partnership issued the senior unsecured notes in two tranches of $100.0 million, each, with maturities of 2018 (with an interest rate of 7.0%) and 2028 (with an interest rate of 7.125%), respectively. At December 31, 1999, $200.0 million face amount remains available under the shelf registration statement. For additional details relating to the Partnership's debt, see Note 5 to the Partnership's Financial Statements.

In April 1999, the Partnership issued an additional 2.7 million Class A Common Units, increasing the total number of Class A Common Units outstanding to 24,990,000. Net proceeds from the offering, including the General Partner's contribution, were $119.7 million. Proceeds were used to repay indebtedness under the Partnership's Revolving Credit Facility incurred to finance SEP II and Terrace. Subsequent to this repayment, additional funds have been borrowed under the revolving credit facility to fund capital expenditures made during 1999.

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, and proceeds were used to finance a portion of SEP II.

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 14, 2000, the Partnership paid a $0.875 per unit distribution related to the fourth quarter of 1999.

Distributions paid to Unitholders have increased over the three year period due to increases in the quarterly distribution to $0.875 per unit in April 1999 and to $0.86 per unit in April 1998, from $0.78 per unit in 1997. The distribution levels have also been impacted by the unit issuances in 1999 and 1997, as well as higher incentive distributions paid to the General Partner as a result of increased levels of cash distributions per unit.

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 ongoing capital expenditures with the proceeds from future debt and equity offerings, other borrowings, cash generated from operating activities, and existing cash and cash equivalents. Cash distributions are expected to be funded with internally generated cash. The Partnership's ability to 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 the 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 U.S. Midwest. See "Items 1 & 2. Business and Properties, —Supply and Demand for Western Canadian Crude Oil."

In particular, Canada has substantial reserves of non-conventional hydrocarbon resources consisting predominantly of oil sands deposits in the province of Alberta. Firms involved in the production of heavy and synthetic crude oil from the oil sands region of western Canada have announced and begun construction of expansion programs in excess of Cdn. $17 billion. If these projects are completed, they are projected to provide substantial increases in the production of heavy and synthetic crude oil in western Canada in the next several years, which will support the long-term utilization of the Lakehead System.

The System serves as a strategic link between the western Canadian oil fields and the markets of the U.S. Midwest and Ontario. Until 1999, the System 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 U.S. Midwest, the Partnership plans to expand its capacity where appropriate. The SEP II and Terrace expansions are projects that were requested by shippers to meet these long-term supply and demand opportunities. These projects, when fully utilized, will increase cash generated from operations, and will enhance future cash distributions, which is consistent with the principal business objective of the Partnership. This strategy has enabled the Partnership to increase quarterly cash distributions to Common Unitholders from $0.59 per unit in 1992 to $0.875 per unit currently.

The Partnership expects world crude oil prices to remain strong during 2000, which is anticipated to stimulate an increase in conventional crude oil exploration and production in western Canada. The

Partnership is well positioned to benefit from increases in crude oil supply through a combination of existing capacity and planned future expansion. Due to a lack of crude oil drilling activity in late 1998 and 1999 and depletion of existing reserves, recovery of Partnership deliveries will be ongoing through 2000, thus limiting projected 2000 earnings to approximately 1999 levels. Based on current projections, the Partnership anticipates generating sufficient cash from operating activities to continue its current level of cash distribution through 2000.

Lakehead System Expansion Projects

Key current and future expansion projects of the Partnership are summarized below:

•: SEP II—This expansion was completed in early 1999. SEP II involved the construction of a new pipeline from the Partnership's pipeline terminal at Superior to the Chicago market area. The pipeline provides an additional 170,000 barrels per day of delivery capacity on the Lakehead System. Under the Tariff Agreement with its customers a tariff surcharge has been implemented that recovers the costs of, and equity 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 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). The rate of return on equity within the range is determined by measuring SEP II capacity utilization on the Enbridge Pipelines System in Canada. During 1999, SEP II capacity utilization of the Enbridge Pipeline System was at minimal levels; therefore, the rate of return on equity for the year was at 7.5%. It is expected that this rate will continue to apply to the SEP II toll through 2000, based on current throughput levels.
•: Terrace Expansion Program—This expansion program is a phased expansion that is expected to ultimately provide an additional net 350,000 barrels per day of capacity for western Canadian producers seeking greater access to U.S. Midwest markets. Phase I of Terrace was completed in 1999 and included construction of new 36-inch diameter pipeline facilities from Kerrobert, Saskatchewan, to Clearbrook and added 170,000 barrels per day of capacity. The new facilities joined existing 48-inch diameter pipeline loops between Kerrobert and Clearbrook, creating another separate pipeline joining those locations. Subsequent phases of Terrace are dependent upon continued industry support, customer requirements and receipt of regulatory approvals, and, if completed, are expected to provide up to 180,000 barrels per day of capacity in addition to the 170,000 barrels per day from Phase I. A tariff surcharge for Terrace, of approximately $0.013 per barrel (for light crude oil from the Canadian border to Chicago) went into effect on April 1, 1999. The tariff surcharge is premised on the completion of Phases II and III of Terrace. Should these later phases not proceed, the Tariff Agreement approved by the FERC provides that 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. The rate of return would be based on the NEB multi-pipeline rate of return. 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 PPIFG-1 index. The Partnership expects the PPIFG-1 index to increase approximately 0.8% for 2000. This increase in the PPIFG-1 index should not have a material effect on 2000 operating revenue since the increase does not apply to SEP II or Terrace and will be effective mid-year 2000. The FERC is scheduled to review the appropriateness of the indexing methodology, and specifically the PPIFG-1 index, commencing in 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. 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, 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 Partnership believes that certain of these projects are complementary to future expansion projects even though they are not owned by the Partnership, since the projects will result in increased deliveries on the Lakehead System. Projects completed in 1999 are summarized below:

•: 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 area. This pipeline has a capacity of 80,000 barrels per day in heavy crude oil service and began service in early 1999.
•: Enbridge Athabasca—In March 1999, Enbridge completed 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. At Hardisty, the Athabasca pipeline accesses other pipeline systems including Enbridge Pipelines System in western Canada. This project provides 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 approximately 570,000 barrels per day. Enbridge has entered into a 30-year transportation arrangement with the initial shipper on the pipeline.

Montreal Extension Reversal

The Enbridge Pipelines System includes a section which extends from Sarnia to Montreal (the "Montreal Extension" or "Line 9"), which at one time flowed in a west-to-east direction. Enbridge Pipelines and a group of refiners developed the Line 9 reversal project which enables crude oil to be imported into Quebec through facilities of Portland Pipe Line Corporation and Montreal Pipe Line Limited. Line 9 was reversed in two stages, allowing shipments from an east-to-west direction from Montreal to the major refining centers in Ontario. The first stage entered service in the second quarter of 1999 with a capacity of 120,000 barrels per day from Montreal to North Westover, Ontario. Full reversal was completed in October 1999 at a capacity of 240,000 barrels per day from Montreal to Sarnia. The reversal of the Montreal Extension has resulted in the availability of competing offshore crude oil supplies in the Ontario market. This reversal is expressly referenced in the agreements entered into at the time of formation of the Partnership.

The reversal of Line 9 has resulted in decreased deliveries over the Lakehead System to Ontario beginning with the second quarter of 1999. The Partnership anticipates that displaced volumes originating in western Canada will be diverted to other markets in the U.S. Midwest. It is anticipated that increasing heavy crude oil production from western Canada delivered to the U.S. Midwest will offset reductions in light crude deliveries to Ontario. Deliveries of U.S. domestic and foreign crude oil volumes between Chicago and Ontario decreased approximately 75,000 barrels per day for the second half of 1999 as compared to the same period last year due to the reversal of Line 9. The level of decline in deliveries over the Lakehead System to Ontario will be dependent upon global crude oil market dynamics and the level of utilization of Line 9.

Year 2000 Issue

To the reporting date, the Year 2000 issue has not had a negative impact on the Partnership's ability to conduct normal business operations, nor to the knowledge of the Partnership, has had an effect on the operations of its customers, suppliers or other third parties providing critical services. The Partnership will continue monitoring its pipeline systems, information technology and equipment for potential date

sensitive issues in 2000. As of December 31, 1999, the Partnership had incurred $2.2 million of operating and $0.4 million of capital costs for Y2K remediation and business continuity initiatives.

Item 7A. Quantitative and Qualitative Disclosures About Market Risk

To the extent that a portion of its indebtedness carries a floating rate, the Partnership's earnings are exposed to movement in interest rates. This exposure is managed through long-term debt to equity ratio targets, appropriate allocation of fixed and floating rate debt and the use of interest rate risk management agreements. The Partnership's 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 has minimal foreign exchange risk, and has entered into forward contracts to hedge its exposure to movements of future exchange rates. For additional details relating to the Partnership's foreign exchange hedging, see Note 10 to the Partnership's Financial Statements. The Partnership does not currently hold or issue derivative instruments for trading purposes.

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

	Expected Maturity Date
December 31, 1999	2000			2001		2002			2003			2004			There- After			Total		Fair Value
	(dollars in millions)
*Liabilities*
Fixed Rate:
First Mortgage Notes	$	0		$	0	$	31.0		$	31.0		$	31.0		$	217.0		$	310.0	$	334.1
Interest Rate		—			—		9.15	%		9.15	%		9.15	%		9.15	%
Senior Unsecured Notes	$	0		$	0	$	0		$	0		$	0		$	200.0		$	200.0	$	177.2
Interest Rate		—			—		—			—			—			7.06	%
Variable Rate:
Revolving Credit Facility	$	0		$	0	$	0		$	0		$	275.0		$	0		$	275.0	$	275.0
Interest Rate		—			—		—			—			5.9	%		—
*Interest Rate Derivatives*
Interest Rate Swaps:
Variable to Fixed	$	80.0		$	0	$	50.0		$	0		$	0		$	0		$	130.0	$	0.7
Average Pay Rate		5.87	%		—		6.23	%		—			—			—			—		—

The fair value of the First Mortgage Notes and Senior Unsecured Notes at December 31, 1999, was $334.1 million (1998—$369.0 million) and $177.2 million (1998—$209.0 million), respectively. The Partnership had $275.0 million (1998—$305.0 million) of variable rate debt outstanding under the Revolving Credit Facility at December 31, 1999, with a fair value of $275.0 million (1998—$305.0 million), at an interest rate of 5.9% (1998—5.8%). It is the Partnership's intention to roll over short-term debt under the Revolving Credit Facility as the debt matures. The Revolving Credit Facility matures during September 2004. The maturity date may be extended by one year, on the anniversary date of the facility, subject to the approval of the lending banks. The fair value of the interest rate swap agreements at December 31,

1999 was $0.7 million. The Partnership did not have any interest rate derivatives outstanding at December 31, 1998. For additional information concerning the Partnership's debt obligations, please see Note 5 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' report thereon, appear on pages F-2 through F-13 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.

Name	Age	Position with General Partner
P.D. Daniel	53	Director
L.H. DeBriyn	53	Vice President and Director
F.W. Fitzpatrick	67	Director
E.C. Hambrook	62	Director
C.A. Russell	66	Director
D.P. Truswell	56	Director
S.J. Wuori	42	President and Director
S.R. Wilson	42	Treasurer (until January 20, 2000)
J.K. Whelen	40	Treasurer (since January 20, 2000)
J.L. Balko	34	Chief Accountant
S.D. Lenczewski	39	Corporate Secretary

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.

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

Mr. Fitzpatrick was elected Director of the General Partner in April 1993 and serves on the Audit, Finance & Risk 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. Hambrook was elected Director of the General Partner in January 1992 and served as Chairman of the General Partner from July 1996 until July 1999. He also serves on the Audit, Finance & Risk Committee. Mr. Hambrook is the President of Hambrook Resources Inc.

Mr. Russell was elected Director of the General Partner in October 1985 and serves as the Chairman of the Audit, Finance & Risk Committee. Mr. Russell served as Chairman and Chief Executive Officer of Norwest Bank Minnesota North, N.A., from January through December 1995. He also served as a Director of Minnesota Power and Light Co. until May 1996.

Mr. Truswell was elected Director of the General Partner in 1991 and has served as the Senior Vice President and Chief Financial Officer of Enbridge since May 1994.

Mr. Wuori was appointed President and elected a Director of the General Partner in November 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.

Mr. Wilson served as Treasurer of the General Partner from November 1997 until January 2000. He has served as Vice President and Treasurer of Enbridge since April 1998, prior thereto as Treasurer since September 1997 and, prior thereto, as its Assistant Treasurer from September 1995 to August 1997. Mr. Wilson is also the Treasurer of The Consumers' Gas Company Ltd., a subsidiary of Enbridge.

Mr. Whelen was elected Treasurer of the General Partner in January 2000. He has served as Assistant Treasurer of Enbridge since November 1997. Prior thereto, he served as Manager, Corporate Finance, of Enbridge from December 1995 to October 1997, and prior thereto, as Manager, Corporate Finance, of The Consumers' Gas Company Ltd.

Ms. Balko has served as Chief Accountant since October 1999. Prior thereto, she served in supervisory positions in accounting with Enbridge Pipelines since January 1998, with The Westaim Corporation from November 1995 to December 1998 and prior thereto, with Gateway Refrigeration Ltd.

Ms. Lenczewski has served as Corporate 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. Ms. Lenczewski also serves as Senior Counsel of Enbridge (U.S.) Inc. ("Enbridge U.S.").

Item 11. Executive Compensation

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

Item 12. Security Ownership of Certain Beneficial Owners and Management

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

Security Ownership of Management

None.

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 service 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 at cost for all direct and indirect expenses it incurs or payments it makes on behalf of the Partnership. The General Partner also receives certain administrative, engineering, treasury and computer services from Enbridge and Enbridge Pipelines for the benefit of the Partnership. The Partnership reimburses the General Partner for the cost of these services. For information about reimbursements to the General Partner, see Note 6 to the Partnership's Financial Statements.

The Partnership has entered into an Agency Agreement with Tidal Energy Marketing Inc., a joint venture owned 50% by Enbridge, for a term of five years. For a fee and a share of the lease payments in

excess of a specified base lease rate, Tidal has agreed to serve as leasing agent for the Partnership's tanks at its Hartsdale storage facility in Schererville, Indiana.

The Partnership has entered into an easement acquisition agreement with Enbridge Holdings (Mustang) Inc. ("Enbridge Mustang"), a subsidiary of Enbridge U.S. Pursuant to this agreement, using funds advanced by the Partnership, Enbridge Mustang acquired properties for the purpose of granting a pipeline easement to the Partnership to allow construction of SEP II's new Line 14. Enbridge Mustang is in the process of reselling these properties. As each parcel is resold, Enbridge Mustang retains an easement for transfer to the Partnership and repays the Partnership for the funds advanced to make the original purchase of the property (less the cost of the easement). Enbridge Mustang is being reimbursed for all costs associated with this process at cost by the Partnership and will be indemnified by the Partnership from and against all liabilities that may arise in connection with this process.

The Partnership has entered into an agreement with Mustang Pipe Line Partners ("Mustang") and Mobil Pipe Line Company ("Mobil") to provide for a joint tariff covering shipments of western Canadian crude oil to the Patoka pipeline hub south of Chicago. Mustang is a Delaware general partnership owned by Mobil Illinois Pipe Line Company and Enbridge Mustang. Shipments covered by the joint tariff travel on the Lakehead System to Chicago and to the Patoka pipeline hub through the Mustang pipeline system. The Partnership has also entered into an agreement with Mustang, Mobil, and Equilon Pipeline Company L.L.C. ("Equilon") to provide for a joint tariff covering shipments of western Canadian crude oil to the Wood River refining center west of Patoka through the Partnership's, Mustang's, and Equilon's pipelines. The joint tariff agreements provide 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.

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 Partnership, with the General Partner having a 99% limited partner interest. For additional details, see Note 5 to the Partnership's Financial Statements.

The Partnership has an arrangement with the General Partner, under which the General Partner may, at its discretion, provide loans to the Partnership in an amount not to exceed $200.0 million. This uncommitted facility provides 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 March 1999, the Partnership borrowed, and subsequently repaid in early April, $25.0 million under this arrangement.

For discussion of distribution restrictions and incentive distributions payable to the General Partner, see Note 3 to the Partnership's 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) No reports on Form 8-K were filed during the fourth quarter of 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.

Exhibit Number		Description
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)
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, given by Lakehead Pipe Line Company, Limited Partnership, as borrower, to Lakehead Pipe Line Company, Inc., as lender.
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)
10.26		Promissory Note, dated as of March 31, 1999, given by Lakehead Pipe Line Company, Limited Partnership, as borrower, to Lakehead Pipe Line Company, Inc., as lender.
21		Subsidiaries of the Registrant.
27		Financial Data Schedule as of and for the year ended December 31, 1999.

All Exhibits listed above, with the exception of Exhibits 10.19, 10.21, 10.26, 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.

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 Company, Limited Partnership (Registrant)
	By:	Lakehead Pipe Line Company, Inc., as General Partner
Date: March 8, 2000	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 8, 2000 by the following persons on behalf of the Registrant and in the capacities indicated with Lakehead Pipe Line Company, Inc., General Partner.

/s/ S.J. WUORI S.J. Wuori President and Director (Principal Executive Officer)		/s/ E.C. HAMBROOK E.C. Hambrook Director
/s/ L.H. DEBRIYN L.H. DeBriyn Vice President and Director		/s/ J.L. BALKO J.L. Balko Chief Accountant (Principal Financial and Accounting Officer)
/s/ F.W. FITZPATRICK F.W. Fitzpatrick Director		/s/ P.D. DANIEL P.D. Daniel Director
/s/ C.A. RUSSELL C.A. Russell Director		/s/ D.P. TRUSWELL D.P. Truswell Director

INDEX TO FINANCIAL STATEMENTS, SUPPLEMENTARY INFORMATION AND
FINANCIAL STATEMENT SCHEDULES

LAKEHEAD PIPE LINE COMPANY, LIMITED PATNERSHIP

		Page
Financial Statements
Report of Independent Accountants		F-2
Statement of Income for the Years Ended December 31, 1999, 1998, 1997		F-3
Statement of Cash Flows for the Years Ended December 31, 1999, 1998, 1997		F-4
Statement of Financial Position as at December 31, 1999 and 1998		F-5
Statement of Partners' Capital for the Years Ended December 31, 1999, 1998, 1997		F-6
Notes to the 1999 Financial Statements		F-7
Supplementary Information (Unaudited)
Selected Quarterly Financial Data		F-14

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

REPORT OF INDEPENDENT ACCOUNTANTS

To the Partners of
Lakehead Pipe Line Company, Limited Partnership.

In our opinion, the accompanying statement of financial position and the related statements of income, partners' capital and of cash flows present fairly, in all material respects, the financial position of Lakehead Pipe Line Company, Limited Partnership at December 31, 1999 and 1998, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 1999 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 7, 2000

F-2

LAKEHEAD PIPE LINE COMPANY, LIMITED PARTNERSHIP

STATEMENT OF INCOME

	Year ended December 31,
	1999			1998			1997
	(dollars in millions)
Operating Revenue	$	312.6		$	287.7		$	282.1

Expenses
Power		53.0			69.0			65.9
Operating and administrative		71.5			71.9			68.0
Depreciation		57.8			41.4			40.1

		182.3			182.3			174.0

Operating Income		130.3			105.4			108.1
Interest and Other Income		3.4			5.9			9.7
Interest Expense (Note 5)		(54.1	)		(21.9	)		(38.6	)

Net Income	$	79.6		$	89.4		$	79.2

The accompanying notes to the financial statements are an integral part of these statements.

F-3

LAKEHEAD PIPE LINE COMPANY, LIMITED PARTNERSHIP

STATEMENT OF CASH FLOWS

	Year ended December 31,
	1999			1998			1997
	(dollars in millions)
Cash Provided from Operating Activities
Net income	$	79.6		$	89.4		$	79.2
Adjustments to reconcile net income to cash provided from operating activities:
Depreciation		57.8			41.4			40.1
Interest on accrued rate refunds (Note 8)		0.7			2.1			3.5
Other		0.9			0.2			0.5
Changes in operating assets and liabilities:
Accounts receivable and other		(6.3	)		(2.8	)		4.8
Materials and supplies		(0.3	)		—			(0.1	)
General Partner and affiliates		(1.2	)		(1.0	)		2.4
Accounts payable and other		(2.4	)		2.1			1.5
Interest payable		0.8			0.2			2.1
Property and other taxes		1.4			0.5			0.3
Payment of rate refunds and related interest (Note 8)		(29.4	)		(28.5	)		(27.7	)

		101.6			103.6			106.6

Investing Activities
Repayments from (advances to) affiliate (Note 6)		24.5			(25.5	)		(6.5	)
Short-term investments, net		—			53.9			29.8
Additions to property, plant and equipment		(82.9	)		(487.3	)		(126.9	)
Changes in construction payables		(32.7	)		31.0			1.9

		(91.1	)		(427.9	)		(101.7	)

Financing Activities
Partners' contributions, net		120.9			—			100.2
Distributions to partners (Note 3)		(108.4	)		(96.2	)		(76.1	)
Variable rate financing, net (Note 5)		(30.0	)		152.0			—
Fixed rate financing, net (Note 5)		—			196.9			—

		(17.5	)		252.7			24.1

Increase (Decrease) in Cash and Cash Equivalents		(7.0	)		(71.6	)		29.0
Cash and Cash Equivalents at Beginning of Year		47.0			118.6			89.6

Cash and Cash Equivalents at End of Year	$	40.0		$	47.0		$	118.6

The accompanying notes to the financial statements are an integral part of these statements.

F-4

LAKEHEAD PIPE LINE COMPANY, LIMITED PARTNERSHIP

STATEMENT OF FINANCIAL POSITION

	December 31,
	1999		1998
	(dollars in millions)
ASSETS
Current Assets
Cash and cash equivalents	$	40.0	$	47.0
Accounts receivable and other		31.5		25.2
Advances to affiliate (Note 6)		7.5		32.0
Materials and supplies		7.4		7.1

		86.4		111.3
Deferred Charges and Other		5.8		6.7
Property, Plant and Equipment, Net (Note 4)		1,321.3		1,296.2

	$	1,413.5	$	1,414.2

LIABILITIES AND PARTNERS' CAPITAL
Current Liabilities
Due to General Partner and affiliates	$	1.7	$	2.9
Accounts payable and other		18.2		53.3
Interest payable		6.3		5.5
Property and other taxes		13.3		11.9
Accrued rate refunds and related interest (Note 8)		—		28.7

		39.5		102.3
Long-Term Debt (Note 5)		784.5		814.5
Contingencies (Note 9)

		824.0		916.8

Partners' Capital
Limited Partner		585.9		494.8
General Partner		3.6		2.6

		589.5		497.4

	$	1,413.5	$	1,414.2

The accompanying notes to the financial statements
are an integral part of these statements.

F-5

LAKEHEAD PIPE LINE COMPANY, LIMITED PARTNERSHIP

STATEMENT OF PARTNERS' CAPITAL

	Limited Partner			General Partner			Total
	(dollars in millions)
Partners' capital at December 31, 1996	$	399.5		$	1.4		$	400.9
Partners' contributions, net		99.2			1.0			100.2
Net income allocation		78.3			0.9			79.2
Distributions to partners		(75.3	)		(0.8	)		(76.1	)

Partners' capital at December 31, 1997		501.7			2.5			504.2
Net income allocation		88.4			1.0			89.4
Distributions to partners		(95.3	)		(0.9	)		(96.2	)

Partners' capital at December 31, 1998		494.8			2.6			497.4
Partners' contributions, net		119.7			1.2			120.9
Net income allocation		78.7			0.9			79.6
Distributions to partners		(107.3	)		(1.1	)		(108.4	)

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

The accompanying notes to the financial statements are an integral part of these statements.

F-6

LAKEHEAD PIPE LINE COMPANY, LIMITED PARTNERSHIP

NOTES TO THE 1999 FINANCIAL STATEMENTS

(dollars in millions)

1. PARTNERSHIP ORGANIZATION AND NATURE OF OPERATIONS

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

The 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 financial statements of the Operating Partnership are prepared in accordance with generally accepted accounting principles. The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses and related disclosures. Actual results could differ from those estimates and assumptions; however, management believes that such differences would not be material.

Regulation of Pipeline System

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

Revenue Recognition

Substantially all pipeline system revenues are derived from transportation of crude oil and natural gas liquids and are recognized in income upon delivery.

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.

F-7

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 Operating 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 Operating Partnership net income is borne by the individual partners through the allocation of taxable income. Net income for financial statement purposes may differ significantly from taxable income reportable to the partners as a result of differences between the tax basis and financial reporting basis of assets and liabilities and the taxable income allocation requirements under the Partnership Agreement.

Net Income Allocation

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

Off Balance Sheet Financial Instruments

Gains and losses on financial instruments used to hedge the Operating Partnership's exposure to movements of future interest rates on its borrowings under the Revolving Credit Facility are recognized currently with the related interest expense.

The Operating Partnership uses the services of the General Partner and its affiliates for managing and operating its pipeline business. Under the terms of service agreements, services provided from the General Partner's Canadian affiliates are reimbursed at cost in Canadian currency. In order to hedge these transactions for 2000, the Operating Partnership has entered into an average rate forward contract that settles at the end of each month during the year to coincide with the related service payments. The gains and losses on these financial instruments are deferred and will be recognized concurrently with the monthly service agreement payments and included in operating and administrative expenses.

Comparative Amounts

Comparative amounts are reclassified to conform with the current year's financial statement presentation.

F-8

3. CASH DISTRIBUTIONS

The Operating 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 Operating Partnership business and as necessary to comply with the terms of any agreement or obligation of the Operating Partnership.

Distributions by the Operating Partnership of its Available Cash generally are made 99% to the Lakehead Partnership and 1% to the General Partner. In 1999, 1998 and 1997, the Operating Partnership paid cash distributions of $108.4 million, $96.2 million and $76.1 million, respectively.

4. PROPERTY, PLANT AND EQUIPMENT, NET

		December 31,
	Average Depreciation Rates	December 31,
	Average Depreciation Rates	1999			1998
Land	—	$	6.4		$	6.2
Rights-of-way	3.8%		110.4			108.4
Pipeline	3.6%		957.1			801.0
Pumping equipment, buildings and tanks	4.2%		458.2			427.1
Vehicles, office and communications equipment	9.6%		31.6			28.8
Construction in progress	—		4.7			115.8

			1,568.4			1,487.3
Accumulated depreciation			(247.1	)		(191.1	)

		$	1,321.3		$	1,296.2

Revised depreciation rates were approved by the Federal Energy Regulatory Commission, effective January 1, 1999, better representing the expected remaining service life of the pipeline system and coinciding with the in-service date for the Operating Partnership's system expansion programs. Prior to this change, the average depreciation rate for rights-of-way was 3.6%, pipeline was 4.1%, pumping equipment, buildings and tanks was 4.6% and vehicles, office and communication equipment was 13.9%. The change in depreciation rates resulted in 1999 depreciation expense being $7.1 million lower than it would have been utilizing the prior rates.

5. DEBT

	December 31,
	1999		1998
First Mortgage Notes	$	310.0	$	310.0
Revolving Credit Facility Agreement		275.0		305.0
Senior Unsecured Notes, Net		199.5		199.5

	$	784.5	$	814.5

F-9

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 Operating 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 Operating 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 Operating Partnership's ability to finance future expansion projects. Under the Note Agreements, the Operating 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 Operating Partnership has a $350.0 million ($205.0 million prior to June 18, 1998) Revolving Credit Facility Agreement scheduled to mature during September 2004. 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 has a facility fee of 0.085% (1998—0.075%) per annum on the entire $350.0 million ($205.0 million prior to June 18, 1998). At December 31, 1999, $275.0 million of the facility was utilized and is classified as long-term debt (1998—$305.0 million). The interest rate on loans averaged 5.4% (1998—5.8%; 1997—6.2%) and was 5.9% at the end of 1999 (1998—5.5%).

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 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 $0.7 million related to accrued rate refunds (1998—$2.1 million; 1997—$3.5 million) and is net of amounts capitalized of $4.4 million (1998—$25.5 million; 1997—$3.3 million). Interest paid amounted to $56.1 million (1998—$44.4 million; 1997—$39.9 million).

Debt Service Reserve

Under the terms of the First Mortgage Notes and the Revolving Credit Facility, the Operating Partnership is required to establish at the end of each quarter a debt service reserve in an amount equal to 50% of the prospective debt service payments for the immediate following calendar quarter. At December 31, 1999, this debt service reserve was $1.1 million (1998—$1.3 million).

F-10

6. RELATED PARTY TRANSACTIONS

The Operating 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 $34.3 million (1998—$34.9 million; 1997—$33.2 million) and are included in operating and administrative expenses. At December 31, 1999, the Operating Partnership has accounts payable to the General Partner and affiliates of $1.7 million (1998—$2.9 million).

The Operating Partnership had entered into an easement acquisition agreement with Enbridge Holdings (Mustang) Inc. ("Enbridge Mustang"), an affiliate of the General Partner. Enbridge Mustang acquired certain real property for the purpose of granting pipeline easements to the Operating Partnership for construction of a new pipeline, completed during 1998, by the Operating Partnership from Superior, Wisconsin to Chicago, Illinois. In order to provide for these real property acquisitions by Enbridge Mustang, the Operating Partnership had made non-interest bearing cash advances to Enbridge Mustang. As Enbridge Mustang disposes of the real property, the advances are repaid. The advances amounted to $7.5 million at December 31, 1999 (1998—$32.0 million). Under the terms of the agreement, the Operating Partnership will reimburse Enbridge Mustang the net cost of acquiring, holding and disposing of the real property.

In late March 1999, the Operating Partnership borrowed $25.0 million from the General Partner under an uncommitted lending facility authorized by the Board of Directors of the General Partner. The loan was repaid in early April 1999 and had an interest rate of 7.75%. In late September 1998, the Operating Partnership borrowed $37.0 million from the General Partner. This loan was repaid in early October 1998, and had an interest rate of 8.75%. The General Partner is authorized to make loans from time to time to the Operating Partnership, on an uncommitted basis, in an amount not to exceed $200.0 million.

7. MAJOR CUSTOMERS

Operating revenue received from major customers was as follows:

	Year ended December 31,
	1999		1998		1997
BP Amoco	$	71.9	$	59.5	$	61.4
Mobil Oil Company of Canada Ltd.	$	42.2	$	40.0	$	42.5
Imperial Oil Limited	$	33.3	$	33.6	$	33.2

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

8. ACCRUED RATE REFUNDS AND RELATED INTEREST

In October 1996, FERC approved a settlement agreement between the Operating Partnership and customer representatives on all then outstanding contested tariff rates. The agreement resulted in an approximate tariff rate reduction of 6% and total rate refunds and related interest of $120.0 million

F-11

through the effective date of October 1, 1996. Refunds required under the agreement began in 1996 with $41.8 million repaid during the fourth quarter of 1996, with the balance being repaid through a 10% reduction on future rates. Interest was accrued on the unpaid balance based on the 90-day Treasury Bill rate. Effective November 22, 1999, the 10% reduction in tariff rates was removed and during December 1999, the $120.0 million and related interest was fully repaid.

During 1999, refunds of $29.4 million (1998—$28.5 million), including the related interest, were made to customers by the Operating Partnership.

9. CONTINGENCIES

Environment

The Operating 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 Operating 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 Operating Partnership. To the extent that the Operating Partnership is unable to recover environmental costs in its rates (if not recovered through insurance), the General Partner has agreed to indemnify the Operating Partnership from and against any costs relating to environmental liabilities associated with the pipeline system prior to its transfer to the Operating Partnership in 1991. This excludes any liabilities resulting from a change in laws after such transfer. The Operating 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.

Oil in Custody

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

10. FINANCIAL INSTRUMENTS

Fair Value of Financial Instruments

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

Based on the borrowing rates currently available for instruments with similar terms and remaining maturities, the carrying value of borrowings under the Revolving Credit Facility approximate fair value, the fair value of the First Mortgage Notes approximates $334.1 million (1998—$369.0 million) and the fair value of the Senior Unsecured Notes approximates $177.2 million (1998—$209.0 million). Due to defined

F-12

contractual make-whole arrangements, refinancing of the First Mortgage Notes and Senior Unsecured Notes would not result in any financial benefit to the Operating Partnership.

Fair Value of Off Balance Sheet Financial Instruments

At December 31, 1999, the Operating Partnership had interest rate swap agreements with a notional principal amount of $80.0 million maturing on April 3, 2000 and $50.0 million maturing on July 21, 2002, to hedge its exposure to movements of future interest rates on its borrowings under the Revolving Credit Facility. The fair value receivable of the agreements is approximately $0.7 million, reflecting the estimated amount that the Operating Partnership would receive to terminate the contracts at the year end date.

To hedge its exposure to movements of future exchange rates for payments in Canadian dollars to the General Partner's Canadian affiliates for committed operating and management services to be provided during 2000, the Operating Partnership has entered into average rate forward contracts. The contracts provide for the Operating Partnership to buy a total of Canadian $16.2 million for U.S. $11.0 million. At December 31, 1999, the fair value receivable of the contracts is approximately $0.3 million, reflecting the estimated amount that the Operating Partnership would receive to terminate the contracts at the year-end date.

F-13

LAKEHEAD PIPE LINE COMPANY, LIMITED PARTNERSHIP

SUPPLEMENTARY INFORMATION (UNAUDITED)
SELECTED QUARTERLY FINANCIAL DATA

(dollars in millions)

1999 Quarters	First		Second		Third		Fourth		Total
Operating revenue	$	74.0	$	80.4	$	79.6	$	78.6	$	312.6
Operating income	$	33.2	$	35.4	$	33.4	$	28.3	$	130.3
Net income	$	22.0	$	22.7	$	20.0	$	14.9	$	79.6
1998 Quarters	First		Second		Third		Fourth		Total
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	$	23.2	$	24.4	$	22.8	$	19.0	$	89.4