UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K/A
/x/ |
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the fiscal year ended DECEMBER 31, 2000
OR
| / / | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the transition period from to
Commission file number 1-10934
LAKEHEAD PIPE LINE PARTNERS, L.P.
(Exact name of Registrant as specified in its charter)
| Delaware (State of incorporation) |
39-1715850 (I.R.S. Employer Identification No.) |
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Lake Superior Place 21 West Superior Street Duluth, Minnesota 55802-2067 (Address of principal executive offices and zip code) |
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(218) 725-0100
(Registrant's telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act:
| Title of each class Class A Common Units |
Name of each exchange on which registered New York Stock Exchange |
Securities registered pursuant to Section 12(g) of the Act: NONE
Indicate by check mark whether the Registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the Registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes /x/ No / /
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of the Registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. /x/
As of July 10, 2001, the aggregate market value of the Registrant's Class A Common Units held by non affiliates of the Registrant was $1,212,596,402 based on the reported closing sale price of such units on the New York Stock Exchange on that date.
As of July 10, 2001, there were 26,803,634 of the Registrant's Class A Common Units outstanding.
DOCUMENTS INCORPORATED BY REFERENCE: NONE
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Page |
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| Items 1 & 2. | Business and Properties | 3 | ||
| Item 10. | Directors and Executive Officers of the Registrant | 15 | ||
| Item 13. | Certain Relationships and Related Transactions | 17 |
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Items 1 & 2. Business and Properties
Overview
Lakehead Pipe Line Partners, L.P. ("Registrant" or "Partnership") is a publicly traded Delaware limited partnership, which owns a 99% limited partner interest in Lakehead Pipe Line Company, Limited Partnership ("Operating Partnership"), also a Delaware limited partnership. Unless the context otherwise requires, references in this Form 10-K to the Partnership include the Registrant and the Operating Partnership.
The Partnership was formed in 1991 to acquire, own and operate the regulated crude oil and natural gas liquids pipeline business of Lakehead Pipe Line Company, Inc. ("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 13.4% limited partner interest (in the form of 3,912,750 Class B Common Units) and a 1% general partner interest in the Registrant, as well as a 1% general partner interest in the Operating Partnership (an effective 15.3% combined interest in the Partnership). The remaining 84.7% limited partner interest in the Partnership is represented by 24,990,000 publicly traded Class A Common Units.
The Partnership and Enbridge Pipelines transport crude oil and other liquid hydrocarbons for others through the world's longest liquid petroleum pipeline system ("System"). The System is the primary transporter of crude oil from western Canada to the United States and is the only pipeline that transports crude oil from western Canada to 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. Enbridge Pipelines owns 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 1,880 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 and through the Lakehead System, to the Great Lakes and Midwest regions of the United States and to the Province of Ontario. These deliveries are made principally to refineries either directly or through connecting pipelines of other companies.
All scheduling of shipments (including routes and storage) is handled by Enbridge Pipelines in coordination with the Partnership. The Lakehead System includes 15 connections to pipelines and refineries at various locations in the United States, including the refining areas in and around Chicago, Illinois, Minneapolis-St. Paul, Minnesota, Detroit, Michigan, Toledo, Ohio, Buffalo and Patoka/Wood River. The Lakehead System has three main terminals at Clearbrook, Minnesota, Superior, Wisconsin 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.
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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:
Estimated annual capacities noted above take into account receipt and delivery patterns and ongoing pipeline maintenance, and reflect achievable pipeline capacity over long periods of time.
The Partnership believes that the Lakehead System has been constructed and is maintained substantially in accordance with applicable federal, state and local laws and regulations, standards prescribed by the American Petroleum Institute 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
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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 the benefit of the Partnership. See "Item 13. Certain Relationships and Related Transactions." Substantially all of the Lakehead System assets are subject to a first mortgage securing indebtedness of the Operating Partnership.
Risk Factors
The Lakehead System is dependent upon the level of supply of crude oil and other liquid hydrocarbons from western Canada. In 1999 and 2000, the Partnership's crude oil deliveries declined compared with 1998. This decline resulted primarily from decreased crude oil production in western Canada, which in turn resulted primarily from reduced spending levels for exploration and development activities in western Canada and a focus on natural gas drilling rather than oil. These reduced spending levels resulted from low oil prices in 1998 and the first part of 1999. The Partnership's ability to increase deliveries and to expand the Lakehead System in the future also depend upon increased supplies of western Canadian crude oil. For a discussion of the forecast for the future supply of crude oil produced in western Canada, see "—Supply 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 several advantages over other transporters of crude oil with which it competes and the System is among the lowest cost transporters of crude oil and NGL in North America based on costs per barrel mile transported. See "—Competition."
The 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 offshore crude oil supply has resulted in a decrease in the Partnership's level of deliveries into the Ontario market. However, the Partnership expects that this decrease will be offset by an increase in deliveries to the Chicago area and other markets it serves.
The Partnership is subject to the risk that changes may occur in existing economic conditions, fuel conservation measures, alternative fuel requirements, governmental regulation or technological advances in fuel economy and energy generation devices. Any of these factors could reduce the demand for crude oil and other liquid hydrocarbons in the areas in which deliveries are made by the Lakehead System. In addition, reduced throughput on the System could result from testing, line repair, reduced operating pressures, reduced crude oil supply, regulatory restrictions on System utilization or other causes.
The operations of the Partnership are subject to federal and state laws and regulations relating to environmental protection and operational safety. 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
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other expansion projects. Notwithstanding this agreement, any shipper who is not a party to the agreement could challenge any existing or future rate filings. Any challenge, if successful, could have a material adverse effect on the Partnership. For a discussion of FERC regulation, Partnership tariff rates and the tariff agreement, see "—Regulation" and "—Tariffs."
The Partnership's ability to increase earnings and cash distributions will depend, in part, upon the ability to identify and complete acquisition opportunities. Growth through acquisitions, and the future operating results and success of such acquisitions, may be subject to the effects of, and changes in laws and regulations, political and economic developments, inflation rates, taxes, financing capability and operating conditions.
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. The FERC can also choose to suspend the proposed change for up to seven months from the proposed date of the change. A complaint, by comparison, typically applies to an existing rate or practice and subjects the pipeline, in certain circumstances, to possible two year retroactive liability for past rates or practices found to be unlawful.
The FERC utilizes a simplified ratemaking methodology for oil pipelines that prescribes an indexing methodology for setting rate ceilings. As described in FERC Orders No. 561 and No. 561-A, the index used is the 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, 2000, was approximately 0.8%. 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. 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.
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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 were fully repaid.
The Settlement Agreement also provided for the terms of an incremental tariff rate surcharge for a period of 15 years to recover the cost of, and allow a return on, the Partnership's investment in SEP II. The rate of return on this investment 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. See "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations,—Future Prospects,—Regulatory Issues."
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 the Terrace Expansion Program ("Terrace") and the transportation of heavy crude oil. See "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations,—Future Prospects,—Lakehead System Growth,—Projects Recently Completed or Under Development." 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
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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. Effective April 1, 2001, Enbridge and the Partnership agreed to reallocate the Cdn. $0.05 per barrel Terrace toll surcharge, Cdn. $0.04 to the Partnership and Cdn. $0.01 to Enbridge. This reallocation is permitted under the terms of the Agreement and was done in an effort to rebalance the project economics between the parties as a result of volume shortfalls, for which the Partnership is completely at risk. The toll increase is also subject to increase or decrease based on changes in other 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. See "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations,—Future Prospects,—Lakehead System Growth—Projects Recently Completed or Under Development."
Other Pipeline Rate Cases
On January 13, 1999, the FERC issued an opinion and order in a case involving Santa Fe Pacific Pipelines, L.P. ("SFPP") ("Opinion No. 435"), which addressed various issues of interest to FERC-regulated publicly traded partnerships and other oil pipelines. These included application of FERC's Opinion No. 154-B/C rate methodology and income tax allowances for publicly traded partnerships. On May 17, 2000, the FERC issued an order on rehearing ("Opinion No. 435-A") that largely reconfirmed the rulings in Opinion No. 435. This order is subject to further rehearing on certain issues, as well as judicial review. The SFPP opinion is not anticipated to have an impact on the Partnership's current rates due to the Tariff Agreement with customers. If the SFPP opinion is not changed on further rehearing by FERC or on review by a court of appeals, and if it were applied to the Partnership in some future rate proceedings, the impact to the Partnership, positive or negative, would be dependent upon the specific application of the rulings in that opinion to the Partnership.
Many of the ratemaking issues contested in the Partnership's rate cases, in particular the FERC's oil pipeline ratemaking methodology, have not been reviewed by a federal appellate court. Judicial review (whether or not in a case directly involving the Partnership) could ultimately result in the implementation of alternative ratemaking methodologies that could have a material adverse effect on the Partnership.
Tariffs
Under published tariffs for transportation by the Lakehead System, the rates for light crude oil from key receipt locations to principal delivery points at January 1, 2001 (including the tariff surcharges related to SEP II and Terrace) are set forth below.
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Published Tariff Per Barrel |
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| Canadian border near Neche to Clearbrook | $ | 0.163 | |
| Canadian border near Neche to Superior | $ | 0.316 | |
| Canadian border near Neche to Chicago area | $ | 0.642 | |
| Canadian border near Neche to Marysville area | $ | 0.767 | |
| Canadian border near Neche to Buffalo area | $ | 0.785 | |
| Chicago to the international border near Marysville | $ | 0.286 | |
The rates at January 1, 2001, 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
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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, 2001. This filing will include any differences between the SEP II surcharge filed in 2000 and actual results for the year, as well as an estimate for 2001. Overall, the surcharge should remain relatively consistent with 2000 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, Ontario, 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 over the next 10 years. In addition, these publications project the total supply of crude oil from producing areas in the U.S. southwest, Rocky Mountains and Midwest that currently serve the entire PADD 2 market, to decline in the near term as reserves are depleted, resulting in a need for additional supplies of crude oil to replace the continuing demand. As a result of these factors, the Partnership believes that the Lakehead System will be able to exceed its current level of deliveries into PADD 2 during 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, 2000.
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Deliveries |
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2000 |
1999 |
1998 |
1997 |
1996 |
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(thousands of barrels per day) |
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| United States | |||||||||||
| Light crude oil | 321 | 299 | 338 | 282 | 309 | ||||||
| Medium and heavy crude oil | 630 | 575 | 627 | 652 | 569 | ||||||
| NGL | 25 | 24 | 27 | 26 | 23 | ||||||
| Total United States | 976 | 898 | 992 | 960 | 901 | ||||||
| Ontario | |||||||||||
| Light crude oil | 174 | 282 | 366 | 355 | 348 | ||||||
| Medium and heavy crude oil | 85 | 87 | 97 | 98 | 102 | ||||||
| NGL | 103 | 102 | 107 | 99 | 100 | ||||||
| Total Ontario | 362 | 471 | 570 | 552 | 550 | ||||||
| Total Deliveries | 1,338 | 1,369 | 1,562 | 1,512 | 1,451 | ||||||
| Barrel miles (billions per year) | 341 | 350 | 391 | 389 | 384 | ||||||
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Supply of 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 directly affect movements through the Enbridge Pipelines System and, therefore, the supply available for transportation through the Lakehead System. Due to the integration of the Enbridge and Lakehead Systems, Enbridge Pipelines regularly prepares forecasts of western Canadian crude oil, which take into account deliveries on the Lakehead System.
The low crude oil prices experienced during 1998 and early 1999 caused a decline in western Canadian producers' expenditures for oil exploration and development, which in turn adversely affected the crude oil supply available in western Canada. As a result, Enbridge Pipelines has updated its forecast of western Canadian crude oil supply and the markets served by the System. This long-term outlook involves updated 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.
Enbridge Pipelines forecast completed in February, 2001, projects that the supply of western Canadian crude oil will be approximately 2,150,000 barrels per day in 2001 and approximately 2,300,000 barrels per day in 2002. This updated forecast projects the supply of crude oil to rise to approximately 2,500,000 barrels per day in 2003 and to approximately 2,940,000 barrels per day by 2010. The forecast quantity of crude oil was made subject to numerous uncertainties and assumptions, including a crude oil price of $21.95 per barrel in 2000 rising to $27.00 in 2010. On December 29, 2000, the benchmark West Texas Intermediate crude oil price closed at $26.70 per barrel.
While the projected supply of crude oil for 2001 and 2002 is lower than the forecast that supported the Terrace Expansion Project, the updated Enbridge Pipelines forecast supports the need for additional pipeline facilities beyond the Terrace Phase I facilities. Phase II includes construction of facilities to increase capacity on the Canadian portion of the System. While Phase II does not involve construction on the Lakehead System, the Partnership expects to benefit directly from the approximately 40,000 barrels per day increase in capacity as additional volumes from the Alberta Oil Sands come on stream. Subject to final NEB approval, Phase II is expected to be placed in service during 2002.
The NEB had previously 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 that was modestly lower than the Enbridge Pipelines most recent forecast by approximately 100,000 barrels per day in 2005. CAPP had also previously released its forecast of western Canadian crude oil production on May 18, 1999. The Enbridge forecast is higher than the CAPP forecast by about 70,000 bpd in 2005.
The Partnership believes that the outlook for increased crude oil production in western Canada continues to be positive, as evidenced by the Enbridge Pipelines forecast, the NEB study and CAPP's recent request to proceed with Terrace Phase II. The timing of growth in the supply of western Canadian crude oil, however, will depend upon the level of crude oil prices, oil and drilling activity and the timing of completion of projects to produce heavy and synthetic oil from the Alberta Oil Sands. It
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is anticipated that 2001 deliveries on the Lakehead System will be approximately 1,400,000 to 1,450,000 barrels per day based on a recent survey of shippers.
Demand
The Partnership believes that modestly increasing 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 PADD 2 market consists of the states of Illinois, Indiana, Iowa, Kansas, Kentucky, Michigan, Minnesota, Missouri, Nebraska, North Dakota, Ohio, Oklahoma, South Dakota, Tennessee and Wisconsin. The Partnership also 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 balancing supply to the PADD 2 region. In the short-term, Latin American deliveries to PADD 2 are expected to decrease as the supply of western Canadian crude oil continues to recover from the negative impact of the 1998/99 price decline. 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. The PADD 3 market consists of the states of Alabama, Arkansas, Louisiana, Mississippi, New Mexico and Texas and the PADD 5 market consists of the states of Alaska, Arizona, California, Hawaii, Nevada, Oregon and Washington.
Based on the most recent forecast completed by Enbridge Pipelines, exports from western Canada to the United States are forecast to increase to approximately 1,835,000 barrels per day in 2005 and remain at that level or above through 2010. This is approximately 700,000 barrels per day higher than 1999 exports. Of the exports to the United States, PADD 2 would receive approximately 1,365,000 barrels per day in 2005, approximately 500,000 barrels per day higher than 1999.
Deliveries to Ontario averaged approximately 362,000 barrels per day in 2000. Demand in Ontario is expected to grow to approximately 640,000 barrels per day over the next several years. Since 1999, Partnership deliveries to Ontario have been impacted by the reversal of Enbridge Line 9 from Montreal to Sarnia. Based on the Partnership's forecast, and assuming no expansion of Line 9, Partnership deliveries to Ontario are expected to approximate 2000 levels in 2001 and grow modestly thereafter.
Crude oil refineries in Ontario generally process light sweet and light sour crude oil, and 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 declined following the reversal of Enbridge's Line 9 in 1999, averaging approximately 63,500 barrels per day for 1999, and approximately 15,000 barrels per day in 2000. Line 9 has an annual capacity of approximately 240,000 barrels per day and, in 2000, operated at approximately 210,000 barrels per day. The ongoing utilization level of Line 9 will be dependent upon global crude oil market dynamics.
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Customers
The Lakehead System operates under month-to-month transportation arrangements with its shippers. During 2000, 47 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 Ontario, major oil companies, refiners and marketers. Shipments by the top ten shippers during 2000 accounted for approximately 87% of total revenues during that period. Revenue from BP Amoco (through affiliated companies), Mobil Oil Company of Canada Ltd. and PDV Midwest accounted for approximately 25%, 16% and 11%, respectively, of total operating revenue generated by the Lakehead System during 2000. The remaining shippers each accounted for less than 10% of total revenues. See Note 8 to the Partnership's Consolidated Financial Statements.
Capital Expenditures
In 2000, the Partnership made capital expenditures of $21.7 million, of which $10.9 million was for core maintenance and $10.8 million for pipeline system enhancements. See "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations."
Taxation
For federal and state income tax purposes, the Partnership and Operating Partnership are not taxable entities. Federal and state income taxes on Partnership taxable income are borne by the individual partners through the allocation of Partnership taxable income. Such taxable income may vary substantially from net income reported in the statement of income.
Competition
Because pipelines are the lowest cost method for intermediate and long haul movement of crude oil over land, the System's most significant existing competitors for the transportation of western Canadian crude oil are other pipelines. In 2000, the Enbridge Pipelines System transported approximately 65% of total western Canadian crude oil production, of which approximately 90% was transported by the Lakehead System. The remainder of 2000 western Canadian crude oil production was refined in Alberta or Saskatchewan or transported through other pipelines. Of the pipelines transporting western Canadian crude oil out of Canada, the System provides approximately 75% of the total pipeline design capacity. The remaining 25% of design capacity is shared by five other pipelines transporting crude oil to British Columbia, Washington, Montana and other states in the U.S. Northwest.
Competition among common carrier pipelines is based primarily on transportation charges, access to producing areas and proximity to end users. The Partnership believes that high capital requirements, environmental considerations and the difficulty in acquiring rights of way and related permits make it difficult for a competing pipeline system comparable in size and scope to the System to be built in the foreseeable future.
Express Pipeline Ltd. ("Express Pipeline") owns and operates a 170,000 barrel per day capacity pipeline that carries western Canadian crude oil to the U.S. Rocky Mountain region, where it connects to a 150,000 barrels per day capacity pipeline system. This connecting pipeline serves the Patoka/Wood River market area. The Express Pipeline began service in early 1997. 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 alternative opportunities for transporting liquid hydrocarbons from their sources to customers. In selecting the destination for their supplies of crude oil, sellers generally desire to use the alternative that results in
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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 50% of all crude oil deliveries into the Chicago area, approximately 80% of all crude oil deliveries into the Minneapolis-St. Paul area and approximately 55% of all deliveries of crude oil to Ontario and Buffalo.
Environmental and Safety Regulation
General
The operations of the Partnership are subject to federal, state and local laws and regulations relating to protection of the environment and safety. Although the Partnership believes that the operations of the Lakehead System are in substantial compliance with applicable environmental and safety laws and regulations, the risk of substantial liabilities is inherent in pipeline operations, and 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 ("CAA") and comparable state statutes. Expenses of routine compliance with these and other similar regulations are not expected to have a material adverse impact on the Partnership.
Water
The federal Clean Water Act ("CWA") as amended, imposes strict controls on the discharge of any pollutant, including oil, into the waters of the United States. The CWA provides penalties for any such discharge, imposes liability for clean-up costs and natural resource damage, and allows for third party lawsuits. As required by the CWA, the Partnership has developed Facility Response Plans, which are designed to prevent contamination of waters in the event of a petroleum overflow, rupture or leak, and has submitted these plans to, and received the approval of, the 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
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may have resulted in soil or groundwater contamination. The Partnership is addressing known sites through monitoring and remediation programs. Currently, expenses relating to such remediation programs are not expected to have a material adverse impact on the Partnership.
Superfund
The Comprehensive Environmental Response, Compensation and Liability Act of 1989 ("CERCLA"), as amended, also known as "Superfund," and comparable state laws impose liability, without regard to fault or the legality of the original act, on certain classes of persons that contribute to the release of a "hazardous substance" into the environment. In the course of its ordinary operations, the 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. The Partnership is unaware of any such obligations at this time.
Waste
The Partnership generates hazardous and non-hazardous solid wastes that are subject to requirements of the federal Resource Conservation and Recovery Act ("RCRA") 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 under the Pipeline Safety Act ("Act") as applied by the DOT and OPS, as well as various other federal, state and local agencies. The Act has been amended periodically requiring OPS to consider environmental impacts and cost-benefit analysis, in addition to its traditional public safety considerations, when developing safety regulations. Among the amendments, OPS was mandated to establish pipeline operator qualification rules that were issued in 1999 and come into effect during 2001. Other requirements include mandating OPS to establish a national pipeline mapping and records system, evaluating the feasibility of requiring additional valves and/or remotely operated valves and completing the identification of areas "unusually environmentally sensitive" to leaks from liquid pipelines. In December 2000, the OPS issued final rules defining "unusually environmentally sensitive areas" following a comment period and pilot test. As well, in December 2000 OPS issued final rules for "Integrity Management Plans for Liquid Pipelines in High Consequence Areas" as well as proposed rules for more prescriptive corrosion protection standards. The Partnership has submitted pipeline maps and descriptive detail to OPS as part of their voluntary national mapping and records system now in progress. The recently issued rules or proposed rules are comprehensive, but are not expected to have a material adverse financial effect on the Partnership.
Following an unsuccessful legislative attempt to approve additional sweeping amendments of the Act during 2000, an Executive Memorandum was issued by the President. This Executive Memorandum directed OPS to evaluate their enforcement program and aggressively pursue safety mandates to require risk-based integrity management programs, broader external communication, and meaningful involvement of states in interstate pipeline safety. It also called for initiation of research and development programs, development of a definition for "unusually sensitive areas', and reinforcement of a quick resolution of rules for increased corrosion protection.
These legislative and regulatory proposals are largely prompted by a significant incident in June 1999 on the Olympic Pipeline system in Bellingham, Washington and an August 2000 incident on the El Paso natural gas pipeline in New Mexico. The Partnership has been monitoring these proposals and will work closely with Congress and industry associations to advocate strong but cost-effective
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provisions. As this legislative initiative is still evolving, the financial impact of additional new regulations cannot be determined at this time. See "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations,—Future Prospects,—New Safety Legislation."
Employees
Neither the General Partner nor the Partnership has any employees. The General Partner is responsible for the management and operation of the Partnership and to fulfill these obligations, it has entered into agreements with Enbridge and several of its subsidiaries to provide the necessary services. The Partnership reimburses service providers for expenses incurred in performing these services at cost.
Item 10. Directors and Executive Officers of the Registrant
The Registrant is a limited partnership and has no officers, directors or employees. Set forth below is certain information concerning the directors and executive officers of the General Partner. Enbridge Pipelines, the sole stockholder of the General Partner, elects the directors of the General Partner on an annual basis. All officers of the General Partner serve at the discretion of the directors of the General Partner.
| Name |
Age |
Position with General Partner |
||
|---|---|---|---|---|
| J.R. Bird | 52 | Director | ||
| P.D. Daniel | 54 | Director | ||
| E.C. Hambrook | 63 | Director | ||
| G.K. Petty | 59 | Director | ||
| C.A. Russell | 67 | Director | ||
| D.P. Truswell | 57 | Director | ||
| D.C. Tutcher | 52 | President | ||
| L.H. DeBriyn | 54 | Vice President, Special Projects | ||
| Greg Sevick | 45 | Vice President, Operations | ||
| Mark Maki | 36 | Controller | ||
| J.K. Whelen | 41 | Treasurer | ||
| J.L. Balko | 35 | Chief Accountant | ||
| S.M. Curwin | 40 | Corporate Secretary |
Mr. Bird was elected Director of the General Partner in September 2000 and served as President from September 2000 until June 2001. Mr. Bird previously served as Treasurer of the General Partner from October 1996 through October 1997. He has also served as Group Vice President, Transportation of Enbridge and President of Enbridge Pipelines since September 2000. Prior thereto, he served as Senior Vice President, Corporate Planning and Development of Enbridge from August 1997 through August 2000 and as Vice President and Treasurer of Enbridge from January 1995 to August 1997.
Mr. Daniel was elected a Director of the General Partner in July 1996 and served as its President from July 1996 through October 1997. Mr. Daniel has served as President of Enbridge since September 2000 and as Chief Executive Officer of Enbridge since January 2001. Prior thereto, Mr. Daniel also served as President and Chief Operating Officer—Energy Delivery of Enbridge from June 1998 to December 2000. 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.
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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., a real estate investment, marketing and sales company.
Mr. Petty was elected Director of the General Partner on February 22, 2001 and serves on the Audit, Finance & Risk Committee. Mr. Petty has served as Director of Enbridge Inc. since January 2001 and as Director of CAE Incorporated since August 1996. Mr. Petty served as President and Chief Executive Officer of Telus Corporation, a Canadian telecommunications company, from November 1994 to November 1999. Mr. Petty is a business consultant providing executive management consulting services to the telecommunications industry.
Mr. Russell was elected Director of the General Partner in October 1985 and serves as the Chairman of the Audit, Finance & Risk Committee. Mr. Russell served as Chairman and Chief Executive Officer of Norwest Bank Minnesota North, N.A., from January through December 1995. He also served as a Director of Minnesota Power and Light Co. until May 1996. Other than in his service as Director of the General Partner, Mr. Russell is retired.
Mr. Truswell was elected Director of the General Partner in 1991. Since September 2000, Mr. Truswell has served as Group Vice President and Chief Financial Officer of Enbridge and from May 1994 through August 2000 served as Senior Vice President and Chief Financial Officer of Enbridge.
Mr. Tutcher was appointed President of the General Partner in June 2001. He also currently serves as Group Vice President, Transportation Group South, of Enbridge Inc., as well as President of Enbridge Midcoast Energy Inc. He was previously Chairman of the Board, President and Chief Executive Officer of Midcoast Energy Resources, Inc. from its formation in 1992 until its merger with Enbridge on May 15, 2001. He also served as Treasurer of Midcoast from 1995 to 1996. Since 1989, Mr. Tutcher has also been President and Chief Executive Officer of Magic Gas Corp., a Texas corporation controlled by Mr. Tutcher. Prior to its merger into Midcoast in 1992, Mr. Tutcher served as Director of Nugget Oil Corporation, from 1990 to 1992. He also serves on the board of the Interstate Natural Gas Association of America and the Gas Processors Association.
Mr. DeBriyn was elected Vice President, Special Projects of the General Partner in June 2001 and served as Vice President and Director from July 1999 until June 2001. Prior 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. Sevick was elected Vice President, Operations of the General Partner in June 2001. Prior thereto, he served as Vice President, Canadian Operations for Enbridge Pipelines from 1999 to June 2001. Prior thereto, he served as Vice President, Engineering & Logistics of Enbridge Consumers Gas from 1998 to 1999 and Senior Vice President, Distribution Operations of Enbridge Consumers Gas from 1996 to 1998.
Mr. Maki was elected Controller of the General Partner in June 2001. Prior thereto he served as Controller, Enbridge Pipelines Inc. from September 1999 to June 2001. Prior thereto, he served as Chief Accountant of the General Partner from June 1997 to August 1999. Prior thereto, Mr. Maki served in various supervisory and professional positions with the General Partner or Enbridge affiliates.
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.
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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, and was with The Westaim Corporation, an investor in, and manufacturer of, industrial technologies in various industries, including the biomedical and semiconductor industries, from November 1995 to December 1997.
Mr. Curwin has served as Corporate Secretary of the General Partner since October 2000. He served as Assistant Secretary of the General Partner since October 1999. Prior thereto, he was employed in the private practice of law as an attorney-at-law by Aafedt, Forde, Gray & Monson, P.A., Minneapolis, Minnesota from October 1995 through July 1999 and Messerli & Kramer P.A., Minneapolis Minnesota from July 1999 to October 1999.
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 7 to the Partnership's Consolidated Financial Statements.
The Partnership has entered into an Agency Agreement dated March 3, 2000 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 crude oil storage tanks at its Hartsdale facility in Schererville, Indiana. See Note 7 to the Partnership's Consolidated Financial Statements.
The Partnership has entered into an easement acquisition agreement dated October 20, 1997 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. See Note 7 to the Partnership's Consolidated Financial Statements.
The Partnership has entered into an agreement dated March 3, 1998 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.
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The General Partner believes that the terms of the agreements described in the preceding three paragraphs are at least as favorable to you as terms that could have been obtained from unaffiliated third parties.
Under the terms of the Revolving Credit Facility Agreement, the Partnership and the General Partner may draw down funds up to a combined maximum of $350.0 million. For additional details, see Note 6 to the Partnership's Consolidated 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 Consolidated Financial Statements.
The Partnership also expects to have the opportunity to acquire a number of oil and gas pipeline assets of its affiliate, Enbridge, as these systems achieve risk and return profiles attractive to the Partnership. On March 8, 2001 a definitive agreement to acquire the assets of Enbridge Pipelines (North Dakota) from Enbridge was announced. The assets consist of a 900-mile crude oil pipeline system with capacity of 85,000 barrels per day, which transports crude oil from Montana, North Dakota and western Canadian oil fields to the Lakehead System and a connecting carrier at Clearbrook, Minnesota. The purchase price for this transaction is approximately $33.0 million, and the closing is expected to occur around April 1, 2001. The terms of this acquisition were negotiated and approved by a special committee of independent directors.
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Pursuant to the requirements of Section 13 or 15(d) of the Signatures Securities Exchange Act of 1934, the Registrant has duly caused this amendment to Report to be signed on its behalf by the undersigned, thereunto duly authorized.
| LAKEHEAD PIPE LINE PARTNERS, L.P. (Registrant) |
||
By: Lakehead Pipe Line Company, Inc., as General Partner |
||
/s/ J.L. BALKO J.L. Balko Chief Accountant (Principal Financial and Accounting Officer) |
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