-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, BIj3oj81qqfJB9eWxoowOxM2b94ShONg9uier6ZucwbrengtCvJNOMZAdkxBA2iw gmsa6SPCf7ZmnUwp3hYGkw== 0000950124-99-001948.txt : 19990323 0000950124-99-001948.hdr.sgml : 19990323 ACCESSION NUMBER: 0000950124-99-001948 CONFORMED SUBMISSION TYPE: 10-K405 PUBLIC DOCUMENT COUNT: 2 CONFORMED PERIOD OF REPORT: 19981231 FILED AS OF DATE: 19990322 FILER: COMPANY DATA: COMPANY CONFORMED NAME: LAKEHEAD PIPELINE CO LP CENTRAL INDEX KEY: 0001066629 STANDARD INDUSTRIAL CLASSIFICATION: PIPE LINES (NO NATURAL GAS) [4610] IRS NUMBER: 391715851 STATE OF INCORPORATION: DE FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-K405 SEC ACT: SEC FILE NUMBER: 333-59597 FILM NUMBER: 99570132 BUSINESS ADDRESS: STREET 1: 21 W SUPERIOR ST STE 400 STREET 2: LAKE SUPERIOR PLACE CITY: DULUTH STATE: MN ZIP: 55802-2067 BUSINESS PHONE: 2187250100 MAIL ADDRESS: STREET 1: LAKE SUPERIOR PL STREET 2: 21 WEST SUPERIOR ST CITY: DULUTH STATE: MN ZIP: 55802-2067 10-K405 1 FORM 10-K405 1 UNITED STATES SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 FORM 10-K [x] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the fiscal year ended DECEMBER 31, 1998 OR [ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the transition period from to ------ ------ Commission File Number: 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 (I.R.S. Employer incorporation or organization) 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 2
TABLE OF CONTENTS PAGE ---- PART I ITEMS 1 & 2. Business and Properties............................................................... 1 ITEM 3. Legal Proceedings..................................................................... 12 ITEM 4. Submission of Matters to a Vote of Security Holders................................... 12 PART II ITEM 5. Market for Registrant's Common Equity and Related Stockholder Matters................................................................. 13 ITEM 6. Selected Financial Data............................................................... 13 ITEM 7. Management's Discussion and Analysis of Financial Condition and Results of Operations........................................................... 14 ITEM 7A. Quantitative and Qualitative Disclosure About Market Risk............................. 21 ITEM 8. Financial Statements and Supplementary Data........................................... 22 ITEM 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure............................................................ 22 PART III ITEM 10. Directors and Executive Officers of the Registrant.................................... 23 ITEM 11. Executive Compensation................................................................ 25 ITEM 12. Security Ownership of Certain Beneficial Owners and Management........................ 25 ITEM 13. Certain Relationships and Related Transactions........................................ 25 PART IV ITEM 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K....................... 27 SIGNATURES ............................................................................................ 29 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 when prices are low, - regulation of the Partnership's tariffs by the Federal Energy Regulatory Commission and the possibility of unfavorable outcomes of future tariff proceedings, - the Partnership's ability to complete Year 2000 readiness activities, and - the effects of competition, in particular, by other pipeline systems. If one or more of these risks or uncertainties materialize, or if the underlying assumptions prove incorrect, actual results may vary materially from those described in this Form 10-K. Except as required by applicable securities laws, the Partnership does not intend to update these forward-looking statements. For additional discussion of such risks, uncertainties and assumptions, see "Items 1 & 2. Business and Properties - Business Risks" included elsewhere in this Form 10-K. 3 PART I ITEMS 1 & 2. BUSINESS AND PROPERTIES GENERAL 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 herein 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," formerly Interprovincial Pipe Line Inc.). Enbridge Pipelines is a Canadian company owned by Enbridge Inc. ("Enbridge," formerly IPL Energy Inc.) of Calgary, Alberta, Canada. The General Partner owns a 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 eastern Canada. The System serves all the major refining centers in the Great Lakes region of the United States, as well as the province of Ontario, Canada and the Patoka/Wood River refinery and pipeline hub in southern Illinois. Various subsidiaries of Enbridge own the Canadian portion of the System ("Enbridge Pipelines System") and the Partnership owns the U.S. portion of the System ("Lakehead System"). The System extends from Edmonton, Alberta, across the Canadian prairies to the U.S. border near Neche, North Dakota. From Neche the System continues on to Superior, Wisconsin, where it splits into two branches with one branch traveling through the upper Great Lakes region and the other through the lower Great Lakes region of the United States. Both branches reenter Canada near Marysville, Michigan. From Marysville the System continues on to Toronto, Ontario and Montreal, Quebec, with lateral lines to Nanticoke, Ontario and the Buffalo, New York area. The System is approximately 3,000 miles long, of which, approximately 1,750 are in the United States. Shipments tendered to the System primarily originate in oil fields in the western Canadian provinces of Alberta, Saskatchewan, Manitoba and British Columbia and in the Northwest Territories of Canada and reach the System through facilities owned and operated by third parties or affiliates of Enbridge Pipelines. Deliveries from the System are currently made in the prairie provinces of Canada, in the Great Lakes and Midwest regions of the United States and the province of Ontario, principally to refineries, either directly or through connecting pipelines of other companies. All scheduling of shipments (including routes and storage) is handled by Enbridge Pipelines in coordination with the Partnership. The Lakehead System includes 16 connections to pipelines and refineries at various locations in the United States, including the refining areas in and around Chicago, Illinois, Minneapolis-St. Paul, Minnesota, Detroit, Michigan, Toledo, Ohio, Buffalo and Patoka/Wood River. The Lakehead System has three main terminals at Clearbrook, Minnesota, Superior, and Griffith, Indiana. The terminals are used to gather crude oil prior to injection into the Lakehead System and to provide tankage in order to allow for more flexible scheduling of oil movements. 1 4 PROPERTIES The Lakehead System consists of approximately 3,200 miles of pipe with diameters ranging from 12 inches to 48 inches, 60 main line pump station locations with a total of approximately 663,000 installed horsepower and 54 crude oil storage tanks with an aggregate working capacity of approximately nine million barrels. The volume of liquid hydrocarbons in the Lakehead System required at all times for operation is approximately 13 million barrels, all of which is owned by the shippers on the Lakehead System. The Lakehead System regularly transports up to 45 different types of liquid hydrocarbons including light, medium and heavy crude oil (including bitumen), condensate, synthetic crudes and natural gas liquids ("NGL"). The Lakehead System is comprised of a number of separate segments as follows: - Canadian border to Clearbrook segment including portions of four pipelines consisting of 18-, 20-, 26-, and 34-inch diameter pipe with a total annual capacity of 1,571,000 barrels per day. This segment includes approximately 40 miles of 48-inch pipeline looping that increases the annual capacity of this segment; - Clearbrook to Superior segment including portions of three pipelines consisting of 18-, 26-, and 34-inch diameter pipe, respectively, with a total annual capacity of 1,337,000 barrels per day. This segment also includes approximately 80 miles of 48-inch pipeline looping; - Superior to Marysville segment consisting of 30-inch diameter pipe with an annual capacity of 509,000 barrels per day; - Superior to Chicago area segment including two pipelines of 24- and 34-inch diameter pipe with a total annual capacity of 889,000 barrels per day; - Chicago area to Marysville segment that is a 30-inch diameter pipe with an annual capacity of 333,000 barrels per day; - Canadian border to Buffalo segment consisting of 12-inch diameter pipe with an annual capacity of 74,000 barrels per day. Estimated annual capacities noted above take into account receipt and delivery patterns and ongoing pipeline maintenance, and reflect achievable pipeline capacity over long periods of time. Lakehead System capacities set forth above do not include the estimate of annual capacity upon completion of Phase I of the Terrace Expansion Program ("Terrace") which is expected to be completed in two stages during 1999. See "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations, - Terrace Expansion Program." Terrace will add an additional 170,000 barrels per day annual capacity to the Lakehead System from the Canadian border to Superior. The properties described above include facilities added during the System Expansion Program II ("SEP II") of the Lakehead System, consisting primarily of a new 24-inch diameter pipeline from Superior to the Chicago area (approximately 450 miles). This new pipeline, together with other pipeline system modifications, is projected to provide approximately 170,000 barrels per day of additional delivery capacity to the Midwest U.S. markets served by the Partnership. The new pipeline has an ultimate potential capacity of 350,000 barrels per day through the installation of additional pumping units. SEP II complements a Cdn. $160 million expansion of the Enbridge Pipelines System. The Partnership believes that the Lakehead System has been constructed and is maintained in accordance with applicable federal, state and local laws and regulations, standards prescribed by the American Petroleum Institute and accepted industry practice. The Partnership attempts to control corrosion of the pipeline through the use of pipe coatings and cathodic protection systems and monitors the integrity of the Lakehead System through a program of periodic internal inspections using electronic 2 5 instruments. On a bi-weekly basis, the entire pipeline right of way is inspected from the air. In addition, trained and skilled operators use computerized monitoring systems to identify pressure drops that might indicate potential disruptions in flow, and operate remote controlled valves and pumps that allow the Lakehead System to be shut down quickly if required. TITLE TO PROPERTIES The Partnership conducts business and owns properties located in seven states. In general, the Lakehead System is located on land owned by others and is operated under perpetual easements and rights of way, licenses or permits that have been granted by private land owners, public authorities, railways or public utilities. The pumping stations, tanks, terminals and certain other facilities of the Lakehead System are located on land that is owned by the Partnership, except for five pumping stations that are situated on land owned by others pursuant to easements or permits. An affiliate of the General Partner has acquired properties for the benefit of the Partnership in connection with SEP II. See "Item 13. Certain Relationships and Related Transactions." Substantially all of the Lakehead System assets are subject to a first mortgage securing indebtedness of the Operating Partnership. BUSINESS RISKS The Lakehead System is dependent upon the level of supply of crude oil and other liquid hydrocarbons from western Canada. Supply, in turn, is dependent upon a number of variables, one of which is the price of crude oil. In recent months, the price of crude oil has reached a twenty year low, resulting in reduced throughput on the System. For a discussion of the forecast of the future supply of crude oil produced in western Canada, see " - Supply and Demand for Western Canadian Crude Oil." Demand for western Canadian crude oil and NGL in the geographic areas served by the Lakehead System is affected by the delivery of other crude oil and refined products into the same areas. Existing pipeline capacity for the delivery of crude oil to the Midwest U.S., the primary destination market served by the Lakehead System, exceeds current refining capacity. The Partnership believes that the System has certain advantages over other transporters of crude oil with which it competes and the System is among the lowest cost transporters of crude oil and NGL in North America based on costs per barrel mile transported. See "- Competition." Enbridge Pipelines is in the process of modifying a pipeline segment from Sarnia, Ontario to Montreal, involving a reversal of a line to bring crude oil from Montreal to Sarnia ("Montreal Extension" or "Line 9"). The line reversal will result in Enbridge Pipelines becoming a competitor of the Partnership for supplying crude oil to the Ontario market which is anticipated to decrease the level of deliveries into the Ontario market. See "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations, - Montreal Extension Reversal." The Partnership cannot predict the impact of future economic conditions, fuel conservation measures, alternative fuel requirements, governmental regulation or technological advances in fuel economy and energy generation devices, all of which could reduce the demand for crude oil and other liquid hydrocarbons in the areas in which deliveries are made by the Lakehead System. In addition, reduced throughput on the System could result from testing, line repair, reduced operating pressures, reduced crude oil supply or other causes. The operations of the Partnership are subject to federal and state laws and regulations relating to environmental protection and operational safety. Although the Partnership believes that the operations of the Lakehead System are in substantial compliance with applicable environmental and safety regulations, risks of substantial costs and liabilities are inherent in pipeline operations, and there can be no assurance that such costs and liabilities will not be incurred, see "- Environmental and Safety Regulation." 3 6 The Partnership filed a rate increase with the Federal Energy Regulatory Commission ("FERC") in late 1998 to reflect the projected incremental costs and throughput resulting from SEP II. A Tariff Agreement previously reached between the Partnership and customer representatives sets forth parameters governing the tariff increase associated with SEP II, Terrace, and other expansion projects, although individual customers who are not parties to the agreement could potentially challenge any existing or future rate filing. Any challenge, if successful, could have a material adverse effect on the Partnership. For a discussion of FERC regulation, Partnership tariff rates, and the Tariff Agreement, see "- Regulation" and "- Tariffs." REGULATION FERC Regulation The Partnership's interstate common carrier pipeline operations are subject to rate regulation by the FERC under the version of the Interstate Commerce Act ("ICA") applicable to oil pipelines. The ICA requires that petroleum products and crude oil pipeline rates be just, reasonable and non-discriminatory. The ICA permits challenges to new, changed and existing rates through either a "protest" or "complaint." At the FERC, a protest normally applies only to a proposed change in a pipeline's rates or practices and subjects the pipeline to a forward-looking investigation and possible refund obligation if the FERC chooses to suspend the proposed change as it is empowered to do for up to seven months from the proposed date of the change. A complaint, by comparison, typically applies to an existing rate or practice and subjects the pipeline, in certain circumstances, to possible retroactive liability for past rates or practices found to be unlawful. The FERC utilizes a simplified ratemaking methodology for oil pipelines that prescribes an indexing methodology for setting rate ceilings. As described in FERC Orders No. 561 and No. 561-A, the index used is the Producer Price Index for Finished Goods minus 1% ("PPIFG-1"). Rate ceiling levels are increased or decreased each July 1. The PPIFG-1 for use on July 1, 1998, was approximately negative 0.6%. Inflationary rate increases allowed under the FERC's indexing methodology may be different than increases in the Partnership's costs. Indexed rates are subject both to protests and to complaints, but in either case the FERC's existing regulations specify that the party challenging a rate must show reasonable grounds for asserting that the amount of any rate increase resulting from application of the index is so substantially in excess of the pipeline's increase in costs as to be unjust and unreasonable (or that the amount of any rate decrease is so substantially less than the actual cost decrease incurred by the pipeline that the rate is unjust and unreasonable). The FERC has stated that, as a general rule, pipelines must utilize the indexing methodology to change rates. However, the FERC has retained cost-based ratemaking, market-based rates and settlements as alternatives to the indexing approach. A pipeline can follow a cost-based approach when it can demonstrate that there is a substantial divergence between the actual costs experienced by the carrier and the rates resulting from application of the index. Under FERC's cost-based methodology, crude oil pipeline rates are permitted to generate operating revenues, based on projected volumes, not greater than the total of the following components: - operating expenses, - depreciation and amortization, - federal and state income taxes and - an overall allowed rate of return on the pipeline's rate base. During the period 1992 to 1995, the Partnership implemented several rate filings in accordance with this methodology, see "- Tariffs, - Rate Cases." In addition, a pipeline can charge market-based rates if it first establishes that it lacks significant market power in a particular relevant market, and a pipeline can establish rates pursuant to a settlement if agreed upon by all current shippers. Initial rates for new services can be established through a cost-based filing or through an uncontested agreement between the pipeline and at least one shipper not affiliated with the pipeline. 4 7 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 included the applicability of the FERC's Opinion 154-B/C trended original cost methodology. The FERC issued decisions on the Partnership's 1992 tariff rate increase that determined the Partnership was entitled to use the FERC's Opinion No. 154-B/C rate methodology, although it was not entitled to recover in its cost of service a tax allowance with respect to income attributable to individual limited partners. In 1996, the FERC approved a settlement agreement ("Settlement Agreement") between the Partnership, the Canadian Association of Petroleum Producers ("CAPP") and the Alberta Department of Energy ("ADOE") on all then-outstanding contested tariff rates. The Settlement Agreement provided for a tariff rate reduction of approximately 6% and total rate refunds and interest of $120.0 million through the effective date of October 1, 1996, with interest accruing thereafter on the unpaid balance. The Partnership made rate refunds of $41.8 million in the fourth quarter of 1996, with the balance being paid through a 10% reduction of tariff rates until all refunds have been made, which is expected to occur sometime late in the second half of 1999. At December 31, 1998, the remaining liability for rate refunds was $28.7 million. The Settlement Agreement also provided for the terms of an incremental tariff rate surcharge for a period of 15 years to recover the cost of, and allow a rate of return on the Partnership's investment in, SEP II. The rate of return on this investment will be based, in part, on the utilization level of the additional capacity constructed. As specified in the Settlement Agreement, higher utilization will result in a greater rate of return, subject to a minimum and maximum rate of return of 7.5% and 15.0%, respectively. The tariff rate surcharge will be recomputed on a cost of service basis and filed with FERC each year. The Settlement Agreement provided that the agreed underlying tariff rates will be subject to indexing as prescribed by FERC regulation and that CAPP and ADOE will not challenge any rates within the indexed ceiling for a period of five years, expiring October 2001. Tariff Agreement In 1998, the Partnership filed an offer of settlement ("Tariff Agreement") with the FERC to facilitate the filing of tariff rate surcharges in late 1998 and early 1999. This filing consolidated the 1996 Settlement Agreement with respect to SEP II and other significant agreements with customers concerning Terrace and the transportation of heavy crude oil. The FERC found the Tariff Agreement a reasonable compromise and approved it on the grounds that it is fair, reasonable, and in the public interest. With respect to Terrace, the Tariff Agreement included terms governing a tariff surcharge associated with the project. A fixed toll increase of Cdn. $0.05 per barrel for the movement of light crude oil from Edmonton to the Chicago area will be allocated approximately Cdn. $0.02 ($0.013 U.S.) to the Partnership and Cdn. $0.03 to Enbridge Pipelines. The toll increase is also subject to increase or decrease based on changes in certain defined circumstances. The portion of the agreement associated with Terrace also establishes in-service and notice dates for future phases of the expansion program. Should CAPP not provide notice to construct later phases of Terrace by July 1, 2001, the toll increment will revert to a cost 5 8 of service recovery, including collection of both prospective and past variances between revenue generated by the Cdn. $0.05 toll increment and the Terrace cost of service. Other Pipeline Rate Cases On January 13, 1999, the FERC issued an opinion and order in the Santa Fe Pacific Pipeline, L.P. ("SFPP") case that addressed various issues of interest to FERC-regulated publicly traded partnerships and other oil pipelines including application of FERC's Opinion No. 154-B/C rate methodology and income tax allowances for publicly traded partnerships. The SFPP opinion is anticipated to have no impact on the Partnership's current rates due to the Tariff Agreement with customers. If the SFPP opinion were applied to the Partnership in some future rate proceedings, the impact to the Partnership, positive or negative, would be dependent upon the specific application of the rulings in that opinion to the Partnership. Many of the ratemaking issues contested in the Partnership's rate cases, in particular the FERC's own oil pipeline ratemaking methodology, have not previously been reviewed by a federal appellate court. Any decision ultimately rendered by the FERC on any rate case involving its oil pipeline ratemaking methodology, including the recent SFPP decision, may be subject to judicial review. Any such judicial review could ultimately result in alternative ratemaking methodologies that could have a material adverse effect on the Partnership. Tariffs Under published tariffs for transportation by the Lakehead System, the rates for light crude oil from the Canadian border near Neche to principal delivery points at January 1, 1999 (including a tariff surcharge related to SEP II) are set forth below. As previously discussed, the Partnership's published tariffs are subject to a 10% reduction; the tariffs less this 10% reduction are also set forth below.
PUBLISHED PUBLISHED TARIFF TARIFF PER BARREL PER BARREL LESS 10% REDUCTION Clearbrook, Minnesota.......................................... $ 0.165 $ 0.149 Superior, Wisconsin............................................ $ 0.318 $ 0.286 Chicago, Illinois area......................................... $ 0.647 $ 0.582 Canadian border near Marysville, Michigan...................... $ 0.747 $ 0.672 Buffalo, New York area......................................... $ 0.792 $ 0.713
The rates at January 1, 1999, for medium and heavy crude oils are higher, while those for NGL are lower, than the rates set forth in the table to compensate for differences in costs for shipping different types and grades of liquid hydrocarbons. The Partnership periodically adjusts its tariff rates as allowed under FERC's indexing methodology and the Tariff Agreement and will file a tariff surcharge for Terrace during the first half of 1999 of an estimated $0.013 per barrel for light crude oil to the Chicago market. See "- Tariffs, - Tariff Agreement." DELIVERIES FROM THE LAKEHEAD SYSTEM Deliveries from the Lakehead System are made in the Great Lakes and Midwest regions of the United States and in Ontario, principally to refineries, either directly or through connecting pipelines of other companies. Major refining centers within these regions are located near Sarnia, Nanticoke, Toronto, Minneapolis-St. Paul, Superior, Chicago, the Patoka/Wood River area, Detroit, Toledo, and Buffalo areas. Crude oils and NGL transported by the Lakehead System are feedstock for refineries and petrochemical plants. 6 9 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. The following table sets forth Lakehead System average deliveries per day and barrel miles for each of the years in the five-year period ending December 31, 1998.
DELIVERIES (THOUSANDS OF BARRELS PER DAY) UNITED STATES 1998 1997 1996 1995 1994 ---------------------------------------------------------- Light crude oil.................................. 338 282 309 345 335 Medium and heavy crude oil....................... 627 652 569 513 452 NGL.............................................. 27 26 23 18 8 ---------------------------------------------------------- Total United States.............................. 992 960 901 876 795 ---------------------------------------------------------- EASTERN CANADA Light crude oil.................................. 366 355 348 332 321 Medium and heavy crude oil....................... 97 98 102 96 108 NGL.............................................. 107 99 100 105 102 ---------------------------------------------------------- Total Eastern Canada............................. 570 552 550 533 531 ---------------------------------------------------------- TOTAL DELIVERIES...................................... 1,562 1,512 1,451 1,409 1,326 ========================================================== BARREL MILES (billions per year)...................... 391 389 384 385 366 ==========================================================
See "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations, - Montreal Extension Reversal." SUPPLY AND DEMAND FOR WESTERN CANADIAN CRUDE OIL Supply Substantially all of the shipments delivered through the Lakehead System originate in oilfields in western Canada. The Lakehead System also receives U.S. and Canadian production at Clearbrook through a connection with a pipeline owned by a subsidiary of Enbridge, U.S. production at Stockbridge and Lewiston, Michigan, and both U.S. and offshore production in the Chicago area. Changes in supply from western Canada would directly affect movements through the Enbridge Pipelines System and, therefore, the supply available for transportation through the Lakehead System. Enbridge Pipelines applied to the National Energy Board of Canada ("NEB") in December 1997 to construct its Terrace Phase I facilities in Canada which would complement the Terrace Phase I facilities to be constructed by the Partnership in the United States. As part of that application, Enbridge Pipelines submitted a forecast of supply of western Canadian crude oil and a projection of the markets in which it could be reasonably expected to be consumed. Forecasts by their nature are based upon numerous assumptions, including estimates provided by industry, many of which are beyond the control of Enbridge Pipelines or the Partnership. The forecast submitted to the NEB in 1997 showed the supply of western Canadian crude oil in the year 2003 at over 2,550,000 barrels per day, approximately 500,000 barrels per day above 1997 average daily production of western Canadian crude oil. The supply of western Canadian crude oil was expected to remain at over 2,500,000 barrels per day through 2010. While acknowledging 7 10 the uncertainty associated with forecasts of the supply of crude oil and other commodities shipped on the Enbridge Pipelines System, the NEB accepted as reasonable the forecasts of the supply of crude oil and other commodities submitted by Enbridge Pipelines and recommended that a certificate for construction be issued. The forecast quantity of crude oil was made subject to numerous uncertainties and assumptions, including a crude oil price of $17.50 per barrel in 1998 rising to $22.25 in 2010. At December 31, 1998, the benchmark West Texas Intermediate ("WTI") crude oil price closed at $12.05 per barrel, up from the 1998 low of $10.73 per barrel. This lower crude oil price, compared to that assumed in the 1997 forecast, has impacted the crude oil supply available in western Canada. Enbridge Pipelines has recently completed its updated forecast of western Canadian crude oil supply and markets for western Canadian crude oil. This long-term outlook is partially based on supply projections from the oil sands projects currently operating, being expanded or proposed in western Canada. The Partnership believes that production from these projects is less sensitive to the price of crude oil due to the size and committed capital expenditures involved. The updated forecast projects the supply of western Canadian crude oil to be lower during the period 1999 through 2002 than the Terrace forecast by approximately 120,000 to 190,000 barrels per day. The forecast supply of western Canadian crude oil is projected to recover to 2,500,000 barrels per day in 2003, rising to over 2,600,000 barrels per day from 2004 through 2010. The updated forecast assumes a WTI crude oil price of $14.50 per barrel in 1999, $19.50 in 2003, and $23.00 in 2010. As a result of the decline in crude oil prices, it is anticipated that 1999 deliveries on the Lakehead System could be approximately 50,000 to 75,000 barrels per day (on average) less than 1998 delivery levels of 1,562,000 barrels per day, a trend which could continue into the year 2000. Despite the downturn in crude oil prices and deliveries, the Partnership believes that the outlook regarding future growth prospects continues to be positive and that the potential for increased crude oil production in western Canada remains substantial. The timing of growth in supply of western Canadian crude oil, however, will be dependent upon recovery of crude oil prices. Demand Rising crude oil demand and declining inland U.S. domestic production are contributing to an increasing need for importing crude oil into the PADD 2 market. The Partnership believes that PADD 2 will continue to provide an excellent market for western Canadian shippers as returns to crude oil producers are expected to remain attractive. Moreover, the Partnership believes that PADD 2 will remain the most attractive market for western Canadian supply since it is currently the largest North American processor of western Canadian heavy crude oil and has the greatest potential for converting refining capacity from light to heavy crude. Although western Canadian producers experience competition from Venezuelan and Mexican heavy crude oil in PADD 2, western Canadian heavy crude oil is expected to remain the dominant supply source for the region. Latin American heavy crude oil will continue to provide the swing supply to the PADD 2 region. In the short-term, Latin American deliveries to PADD 2 are expected to increase due to reduced supply of western Canadian crude oil resulting from low crude oil prices and producer returns. However, over the long-term, it is expected that producers of Latin American heavy crude oil will concentrate on PADD 3 and PADD 5 markets, where they receive a higher return than compared to PADD 2. Based on the recent forecast completed by Enbridge Pipelines, exports from western Canada to the United States are forecast to increase to approximately 1,800,000 barrels per day in 2005 and remain at that level or above through 2010. This is approximately 700,000 barrels per day higher than 1997 exports. Of the exports to the United States, PADD 2 would receive approximately 1,470,000 barrels per day in 2005, approximately 600,000 barrels per day higher than 1997. Exports to PADD 2 would rise to approximately 1,540,000 barrels per day in 2007 and decline to approximately 1,430,000 barrels per day by 2010. Although in 1999 exports on the System to PADD 2 are anticipated to be marginally lower than 1998, recovery is expected in 2001 with long-term exports surpassing Terrace forecast levels by 2005. 8 11 Current low crude oil prices are expected to delay supply and market growth for western Canadian crude oil by approximately one to two years. Deliveries to eastern Canada averaged approximately 570,000 barrels per day in 1998. Demand in eastern Canada is expected to grow to approximately 640,000 barrels per day over the next several years. Partnership deliveries to eastern Canada are, however, expected to decline due to the reversal of Enbridge's Line 9 from Montreal to Sarnia. See "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations, - Montreal Extension Reversal." Crude oil refineries in eastern Canada are generally configured to process light sweet and light sour crude oil. While Canadian crude oil supplies have increased over the last several years, the supply of conventional light sweet and light sour crude oil in western Canada is expected to decline. Eastern Canadian refiners cannot process significantly greater amounts of western Canadian heavy crude oil without substantial reconfiguration of their refineries. To the extent eastern Canadian refiners have found it difficult to obtain light crude oil supply from western Canada at an economic price, refiners have been recently accessing U.S. and imported light crude volumes through Lakehead System pipeline connections in the Chicago area. Light crude oil movements originating in the Chicago area for delivery to eastern Canada have increased from approximately 70,000 barrels per day in 1997 to approximately 110,000 barrels per day in 1998. These movements are expected to decline following the reversal of the Enbridge's Line 9 in 1999. CUSTOMERS The Lakehead System operates under month-to-month transportation arrangements with its shippers. During 1998, 48 shippers tendered crude oil and NGL for delivery through the Lakehead System. These customers included integrated oil companies with production facilities in western Canada and refineries in eastern Canada, major oil companies, refiners and marketers. Shipments by the top ten shippers during 1998 accounted for approximately 80% of total revenues during that period. Revenue from Amoco (through affiliated companies), Mobil Oil Company of Canada Ltd. and Imperial Oil Limited accounted for approximately 20%, 14% and 12%, respectively, of total operating revenue generated by the Lakehead System during 1998. The remaining shippers each accounted for less than 10% of total revenues. CAPITAL EXPENDITURES In 1998, the Partnership made capital expenditures of $487.3 million, of which $470.7 million was for its two expansion programs SEP II and Terrace and $16.6 million was for other projects including core maintenance of $7.2 million. See "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations, - SEP II, - Terrace Expansion Program." TAXATION For federal and state income tax purposes, the Partnership and the 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 1998 the Enbridge Pipelines System transported approximately 65% of total western Canadian crude oil production, of which more than 90% was transported by the Lakehead System. The remainder of 1998 western Canadian crude oil production was refined in Alberta or Saskatchewan or transported through other pipelines. Of the pipelines transporting western Canadian crude oil out of Canada, the System provides approximately 70% of the total pipeline design capacity. 9 12 The remaining 30% of design capacity is shared by five other pipelines transporting crude oil to British Columbia, Washington, Montana and other states in the Northwest U.S. Competition among common carrier pipelines is based primarily on transportation charges, access to producing areas and proximity to end users. The Partnership believes that high capital requirements, environmental considerations and the difficulty in acquiring rights of way and related permits make it difficult for a competing pipeline system comparable in size and scope to the System to be built in the foreseeable future. Express Pipeline Ltd. ("Express Pipeline"), a joint venture between Alberta Energy Company, Ltd. and TransCanada PipeLines Limited, owns and operates a 170,000 barrel per day capacity pipeline that carries western Canadian crude oil to the U.S. Rocky Mountain region, where it connects to a 150,000 barrels per day capacity pipeline system. This connecting pipeline serves the Patoka/Wood River market area. Express Pipeline began service in early 1997. The General Partner believes, however, that the System is more attractive to western Canadian producers shipping to the Chicago or Patoka/Wood River market area as it offers lower tolls and shorter transit times than Express Pipeline and does not require shipper volume commitments as currently required by Express Pipeline. The System encounters competition in serving shippers to the extent that shippers have alternate opportunities for transporting liquid hydrocarbons from their sources to customers. In selecting the destination for their supplies of crude oil, sellers generally desire to use the alternative that results in the highest return to them. Generally, it is expected that sellers will receive the highest return from markets served by the System, but alternate markets may, for periods of time, offer equal or better returns for the seller. Such markets could potentially include the U.S. Rocky Mountain region for sweet crude oil and the Washington State market for light sour crude oil. In the United States, the Lakehead System encounters competition from other crude oil and refined product pipelines and other modes of transportation delivering crude oil and refined products to the refining centers of Minneapolis-St. Paul, Chicago, Detroit and Toledo and the refinery market and pipeline hub located in the Patoka/Wood River area. The Lakehead System transports approximately 45% of all crude oil deliveries into the Chicago area, approximately 75% of all crude oil deliveries into the Minneapolis-St. Paul area and virtually all deliveries of crude oil to Ontario. Please refer to "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations, - Montreal Extension Reversal," for discussion of a planned reversal of the Montreal Extension that will result in Enbridge Pipelines becoming a competitor of the Lakehead System for supplying crude oil to the Ontario market. ENVIRONMENTAL AND SAFETY REGULATION General The operations of the Partnership are subject to federal, state and local laws and regulations relating to protection of the environment and safety. Although the Partnership believes that the operations of the Lakehead System are in substantial compliance with applicable environmental and safety laws and regulations, the risk of substantial liabilities are inherent in pipeline operations, and there can be no assurance that substantial liabilities will not be incurred. To the extent that the Partnership is unable to recover environmental costs in its rates or through insurance, the Partnership could be subject to material costs. In general, the Partnership expects to incur future ongoing expenditures to comply with industry and regulatory environment and safety standards. Such expenditures cannot be accurately estimated at this time, although the Partnership does not expect that they will have a material adverse effect on the Partnership. 10 13 Air The operations of the Partnership are subject to the federal Clean Air Act and comparable state statutes. Water The federal Water Pollution Control Act, as amended by the Oil Pollution Act of 1990 ("WPCA"), imposes strict controls on the discharge of oil into navigable waters. The WPCA provides penalties for any discharges of petroleum products in reportable quantities, imposes liability for clean-up costs and natural resource damage, and allows for third party lawsuits. State laws also provide varying civil and criminal penalties and liabilities in the case of a release of petroleum into surface water or groundwater. Spill prevention control and countermeasure requirements of federal laws require diking and similar structures to help prevent contamination of navigable waters in the event of a petroleum overflow, rupture or leak. In response to regulations mandated by the WPCA, the Partnership has submitted to the Office of Pipeline Safety ("OPS") of the U.S. Department of Transportation ("DOT") oil spill emergency response plans, which have been approved, and a certification that it has the resources to respond to a worst case spill. Expenses of routine compliance with these and other similar regulations are not expected to have a material adverse impact on the Partnership. Remediation Matters Contamination resulting from spills of crude oil and petroleum products is not unusual within the petroleum pipeline industry. Historic spills along the Lakehead System as a result of past operations may have resulted in soil or groundwater contamination. The Partnership is addressing known sites through monitoring and remediation programs. Superfund The Comprehensive Environmental Response, Compensation and Liability Act of 1989, as amended, also known as "Superfund," and comparable state laws impose liability, without regard to fault or the legality of the original act, on certain classes of persons that contributed to the release of a "hazardous substance" into the environment. In the course of its ordinary operations, the Lakehead System generates wastes, some of which fall within the federal and state statutory definitions of a "hazardous substance" and some of which were historically disposed of at sites that may require cleanup under Superfund and related state statutes. Waste The Partnership generates hazardous and nonhazardous solid wastes that are subject to requirements of the federal Resource Conservation and Recovery Act and comparable state statutes. The Partnership believes that operations of the Lakehead System are in substantial compliance with such statutes in all states in which it operates. The Environmental Protection Agency ("EPA") is currently in the process of developing stricter disposal standards for nonhazardous waste. Safety Regulation The Partnership's operations are subject to construction, operating and safety regulation by the DOT and various other federal, state and local agencies. The Pipeline Safety Act of 1992, as amended by the Accountable Pipeline Safety and Partnership Act of 1996, requires the OPS to consider environmental impacts and do a risk assessment, as well as satisfy its traditional public safety mandate, when developing pipeline safety regulations. The Act also mandates the OPS to establish pipeline operator qualification rules, requires pipeline operators to provide maps and records to the OPS, and authorizes the OPS to require pipelines to be modified to accommodate internal inspection devices. Regulations issued pursuant to the Act require pipeline operators to implement drug and alcohol testing programs for employees and 11 14 contractors that are engaged in safety-sensitive activities. Additional legislation or regulations have been proposed requiring remotely controlled shutoff valves in populated or environmentally sensitive areas, increased public education of pipeline safety and accident prevention and periodic integrity testing of pipelines by internal inspection or hydrostatic testing. The Partnership currently has an integrity testing program utilizing internal inspection devices and has conducted additional hydrostatic testing for selected segments of the Lakehead System. The Partnership is also subject to the requirements of federal and state Occupational Safety and Health Acts. EMPLOYEES Neither the General Partner nor the Partnership has any employees. The General Partner is responsible for the management and operation of the Partnership and to fulfill these obligations, it has entered into agreements with Enbridge and certain of its subsidiaries to provide the required services. The Partnership reimburses the General Partner or its affiliates for expenses incurred in performing these services at cost. ITEM 3. LEGAL PROCEEDINGS The Partnership is a defendant in various lawsuits and a party to various legal proceedings arising in the ordinary course of business. Some of these lawsuits and proceedings are covered, in whole or in part, by insurance. The Partnership believes that the outcome of all these lawsuits and proceedings will not, individually or in the aggregate, have a material adverse effect on the financial condition of the Partnership. In connection with the transfer of its pipeline business to the Partnership, the General Partner agreed to indemnify the Partnership from and against substantially all liabilities, including liabilities relating to environmental matters, arising from operations prior to the transfer. This indemnification does not apply to amounts that the Partnership would be able to recover in its tariffs, through insurance, or to any liabilities relating to a change in laws after December 27, 1991. In late July 1998, the Partnership's directional drilling operations for SEP II construction caused a discharge of non-hazardous bentonite drilling mud in a wetlands area. The Partnership does not believe that any penalties that might be assessed by the EPA will have a material impact on the financial condition of the Partnership. The State of Illinois is pursuing an action relating to this discharge under Natural Resource Damage Assessment regulations of the Clean Water Act to seek compensation for damage to the wetlands area. It is expected that a settlement will be reached with the State to resolve the matter and that it will not have a material impact on the financial condition of the Partnership. In a letter dated August 19, 1998, the Illinois Attorney General informed the Partnership that it is seeking a penalty of $135,000 for a May 28, 1998, release of crude oil caused by a third party in Orland Park, Illinois. The Partnership and the Attorney General are in negotiations on this matter. The Partnership received a Notice of Violation, dated October 29, 1998, from the Wisconsin Department of Natural Resources ("Wisconsin DNR") that alleges the Partnership failed to monitor discharges of water from SEP II construction trenches on certain occasions and exceeded the effluent limitations set forth in a permit The Partnership has submitted its reply to the notice and intends to cooperate with the Wisconsin DNR in an effort to resolve the issue and any penalties that may ensue. It is not anticipated that any penalty will have a material impact on the financial condition of the Partnership. ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS No matters were submitted to a vote of security holders during the fourth quarter of 1998. 12 15 PART II ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS None. ITEM 6. SELECTED FINANCIAL The following table sets forth, for the periods and at the dates indicated, summary historical financial and operating data for the Partnership. The table is derived from the financial statements of the Partnership and notes thereto, and should be read in conjunction with those audited financial statements.
YEAR ENDED DECEMBER 31, ------------------------------------------------------------------- (DOLLARS IN MILLIONS) 1998 1997 1996(1) 1995(1) 1994 ----------- ----------- --------- --------- -------- INCOME STATEMENT DATA: Operating revenue...................... $ 287.7 $ 282.1 $ 274.5 $ 268.5 $ 246.0 Operating expenses(2).................. $ 182.3 174.0 187.1 195.2 159.7 ----------- ---------- ----------- ----------- -------- Operating income....................... $ 105.4 108.1 87.4 73.3 86.3 Interest and other income.............. $ 5.9 9.7 9.6 7.1 4.1 Interest expense....................... $ (21.9) (38.6) (43.9) (40.3) (29.8) ----------- ---------- ---------- ----------- -------- Net income............................. $ 89.4 $ 79.2 $ 53.1 $ 40.1 $ 60.6 =========== ========== ========== =========== ======== FINANCIAL POSITION DATA (AT YEAR END): Property, plant and equipment, net..... $ 1,296.2 $ 850.3 $ 763.5 $ 725.1 $ 727.6 Total assets........................... $ 1,414.4 $ 1,063.1 $ 975.8 $ 915.1 $ 868.5 Long-term debt......................... $ 814.5 $ 463.0 $ 463.0 $ 395.0 $ 364.0 Partners' capital...................... Limited Partner...................... $ 494.8 $ 501.7 $ 399.5 $ 411.0 $ 434.3 General Partner...................... $ 2.6 2.5 1.4 1.4 1.5 ----------- ---------- ---------- ----------- -------- $ 497.4 $ 504.2 $ 400.9 $ 412.4 $ 435.8 =========== ========== ========== =========== ======== CASH FLOW DATA: Cash provided from operating activities........................... $ 103.6 $ 106.6 $ 93.9 $ 121.5 $ 108.1 Cash used in investing activities...... $ (427.9) $ (101.7) $ (84.7) $ (54.0) $ (102.7) Cash provided from (used in) financing activities................. $ 252.7 $ 24.1 $ 3.4 $ (32.5) $ 27.7 Capital expenditures included in investing activities................. $ (487.3) $ (126.9) $ (76.7) $ (35.5) $ (136.9) OPERATING DATA: Barrel miles (billions)................ 391 389 384 385 366 Deliveries (thousands of barrels per day) United States....................... 992 960 901 876 795 Eastern Canada...................... 570 552 550 533 531 ----------- ---------- ---------- ----------- -------- 1,562 1,512 1,451 1,409 1,326 =========== ========== ========== =========== ========
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. 13 16 ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS 1998 was a successful year for the Partnership as record net income and crude oil deliveries were achieved despite a decline in world crude oil prices. The strong performance of the Partnership during 1998, coupled with expectations for strong long-term performance, influenced the Board of Directors of the General Partner to increase the Partnership's cash distributions for 1998 to $96.2 million from $76.1 million for 1997. This most recent increase in the distribution is primarily the result of earnings growth from capacity expansions. Challenges encountered by the Partnership during construction of the $450 million System Expansion Program II ("SEP II") were overcome and the targeted completion date of first quarter 1999 was met. During December 1998, the process of filling the new pipeline with crude oil was begun and deliveries from the new line will commence in March 1999. A tariff increase associated with the new line was filed with the Federal Energy Regulatory Commission ("FERC") in late December and became effective on January 1, 1999. See "- SEP II." The Partnership, together with Enbridge Pipelines Inc., of Edmonton, Alberta, ("Enbridge Pipelines" formerly Interprovincial Pipe Line Inc.), began construction of the first phase of the Terrace Expansion Program ("Terrace") in 1998. Terrace is a multi-phase program that will eventually add approximately 350,000 barrels per day of pipeline system delivery capability with the first phase of 170,000 barrels per day expected to be operational by September 1999. The remaining capacity may be added at customer request in stages over the next several years. See "- Terrace Expansion Program." Deliveries by the Partnership of crude oil and natural gas liquids ("NGL") increased 3% over the previous record levels attained in 1997. In late 1998, the Partnership began experiencing a decline in the level of crude oil deliveries compared with the first half of 1998. Producers of crude oil throughout North America began reducing production of less profitable crude oil due to the significant drop in world crude oil prices. At December 31, 1997, the benchmark West Texas Intermediate ("WTI") crude oil price was $17.83 per barrel. At December 31, 1998 the reference WTI price closed at $12.05 per barrel, up from the 1998 low of $10.73. While utilization of the Partnership's pipeline system historically has been fairly insensitive to modest changes in the price of crude oil, the current world crude oil price situation is anticipated to impact the supply of available crude oil and the Partnership's short-term results. Despite this forecast decrease in crude oil deliveries, the Partnership anticipates generating more than sufficient cash from operating activities to continue its current level of distribution through 1999. See " - Future Prospects." RESULTS OF OPERATIONS Net income for 1998 was $89.4 million compared with $79.2 million for 1997 and $53.1 million for 1996. Net income for 1996 was impacted by rate refunds ($20.1 million) and related interest expense ($3.2 million) attributable to prior years recorded in response to a settlement agreement (the "Settlement Agreement") between the Partnership and certain customer representatives that concluded a dispute that began in 1992 concerning the Partnership's tariff rates. See "Items 1 & 2. Business and Properties, - Tariffs, - Rate Cases." Crude oil and NGL deliveries averaged a record 1,562,000 barrels per day in 1998, up from the 1,512,000 barrels per day averaged during 1997, a 3% growth in Lakehead System deliveries. Crude oil and NGL deliveries increased 4% during 1997 when compared with 1996 results. Over the three-year period, increased deliveries resulted from greater crude oil production in western Canada, increased transportation of foreign and U.S. crude received in the Chicago area, combined with increased pipeline capacity from the Partnership's expansion programs. System utilization measured in barrel miles was relatively unchanged over the three year period due to shorter average length of haul. 14 17 Net income for 1998 was $10.2 million higher than net income in 1997 primarily due to increased operating revenue and lower interest expense partially offset by higher operating expenses and lower interest and other income. Net income in 1997 improved $26.1 million in comparison with 1996. A 1996 non-recurring charge of $20.1 million related to prior years' rate refunds required under the Settlement Agreement together with a related interest accrual of $3.2 million accounts for a majority of the increase. In addition, a combination of higher operating revenue and lower interest expense, partially offset by higher operating expenses, led to the increase in net income. Operating revenue for 1998 was $287.7 million, or $5.6 million greater than operating revenue for 1997. The increase was primarily due to increased deliveries and the full year impact of a July 1, 1997, tariff increase of 1.6%, partially offset by a 0.6% tariff decrease on July 1, 1998, as required under the FERC's indexing methodology and an increase in the proportion of heavy crude oil deliveries (up 9% to 625,000 barrels per day). The Partnership's current tariff rate for medium and heavy crude oil deliveries to the Chicago area is approximately 7% and 20% higher, respectively, than that for lighter crude oils. The positive impact of increased deliveries and heavier crude oil mix were somewhat offset by a decreased average length of haul (686 miles in 1998 versus 704 miles in 1997). Average length of haul decreased due to increased receipt of crude oil in the Chicago area from U.S. and foreign sources for delivery to markets east of Chicago including eastern Canada. Operating revenue for 1997 was $282.1 million, or $7.6 million greater than 1996 primarily due to increased deliveries and the transportation of a greater proportion of heavy crude oil (up 22% to 573,000 barrels per day). Operating revenue was also favorably impacted by the full year impact of a July 1996 tariff rate increase of 0.9%, and an additional 1.6% on July 1, 1997. Operating revenue for 1996 reflects tariff rates implied in the Settlement Agreement. Total operating expenses of $182.3 million in 1998 were $8.3 million greater than 1997 primarily due to higher power costs associated with increased deliveries, and a heavier crude oil mix. Operating and administrative costs increased $3.9 million primarily due to increased rents for rights-of-way as a result of the renewal of certain lease agreements that expired during the year, and higher maintenance costs associated with an increased level of internal pipeline inspection. Depreciation expense increased due to the growth in property, plant and equipment. Total 1997 operating expenses were $13.1 million less than 1996 primarily due to the absence of a $20.1 million provision for prior years' rate refunds recorded in 1996. The decrease in total operating expenses was somewhat offset by higher power costs associated with a heavier crude oil mix and increased deliveries. Operating and administrative expenses increased largely due to higher property taxes. Depreciation expense for 1997 increased due to growth in property, plant and equipment, somewhat offset by the impact of revised depreciation rates that became effective on July 1, 1996. The depreciation rates were revised to better represent the expected service life of the pipeline system. Interest expense of $21.9 million in 1998 decreased $16.7 million from 1997 largely due to the capitalization of interest costs associated with SEP II and Terrace as part of the costs of constructing the assets. Capitalized interest reflects the Partnership's average cost of debt, of approximately 7.8%, and the average level of funds invested in construction. Capitalized interest increased due to the significant construction projects ongoing during 1998. Interest expense is further decreased due to the utilization of the Partnership's cash balances to finance a portion of the capital expenditures rather than issuing additional debt or equity. Interest capitalization generally ceases once a capital project is complete and ready for service. Interest paid increased to $44.4 million in 1998 from $39.9 million paid in 1997 primarily due to greater borrowing on the Partnership's revolving credit facility. Interest expense for 1997 decreased $5.3 million from 1996 due to lower balances and interest rates with respect to rate refunds payable, and increased capitalized interest attributable to greater construction 15 18 work in process during 1997. These changes were partially offset by additional interest on greater average borrowings in 1997 under the Partnership's credit facility. LIQUIDITY AND CAPITAL RESOURCES At December 31, 1998, cash, cash equivalents and short-term investments totaled $47.0 million, down $125.5 million since December 31, 1997. In keeping with the Partnership's financing plans for SEP II and Terrace, existing cash balances were used to partially finance the expansion programs. Of this $47.0 million, $24.7 million was set aside for the cash distribution paid on February 12, 1999, with the remaining $22.3 million available for capital expenditures and other business needs. Cash generated from operating activities in 1998 decreased marginally by $3.0 million from 1997 to $103.6 million, as the impact of higher net income was offset by changes in working capital requirements. Cash generated from operating activities in 1997 increased $12.7 million from 1996 to $106.6 million primarily due to higher net income, partially offset by the reduction in liability for accrued rate refunds. In response to the October 1996 Settlement Agreement, the Partnership made rate refunds of $28.5 million in 1998 and $27.7 million in 1997 with the remaining balance continuing to be repaid through a 10% reduction of tariff rates. This reduction will continue until all refunds have been made. Based on the $28.7 million remaining balance at December 31, 1998, and projected pipeline system deliveries, the 10% reduction is expected to remain effective until sometime late in the second half of 1999. In 1998, the Partnership made capital expenditures of $487.3 million, of which $358.0 million were for SEP II, $112.7 million were for Terrace, and $16.6 million were for other projects. With $450.0 million of capital expenditures having been incurred or committed on SEP II through December 31, 1998, the project is largely complete except for minor restoration and clean-up work and the finalization of rights-of-way costs in 1999. In 1997, the Partnership made capital expenditures of $126.9 million, including $84.9 million for SEP II and $42.0 million for other projects. The first phase of the Terrace expansion is largely complete and capital expenditures are anticipated to total approximately $138.0 million. In addition to Terrace, the Partnership anticipates spending approximately $8.2 million for pipeline system enhancements and $13.5 million for core maintenance activities in 1999. See "- Future Prospects, - Lakehead System Expansion Projects." Excluding future phases of Terrace, ongoing capital expenditures are expected to average $10 to $20 million on an annual basis (approximately 50% for enhancement and 50% for core maintenance of the pipeline system). Core maintenance activities, such as the replacement of equipment and preventive maintenance programs, are expected to be undertaken to enable the Partnership's pipeline system to continue to operate at its maximum operating capacity. Enhancements to the pipeline system, such as renewal and replacement of pipe, are expected to extend the life of the Lakehead System and permit the Partnership to respond to developing industry and government standards and the changing service expectations of its customers. On an annual basis the Partnership makes expenditures of a capital and operating nature related to maintaining compliance of the Lakehead System with applicable environmental and safety regulations. Capital expenditures for safety and environmental purposes comprise a portion of the routine core maintenance and enhancement capital expenditures annually incurred by the Partnership. Amounts are not readily segregated since individual projects may be undertaken for a variety of reasons in addition to environment and safety considerations. Future environment and safety expenditures are not anticipated to be material in relation to the Partnership's results of operations. At December 31, 1998, the Partnership had $310.0 million aggregate principal amount of First Mortgage Notes outstanding that bear interest at the rate of 9.15% per annum, payable semi-annually. The notes are due and payable in ten equal annual installments beginning in the year 2002. During 1998, the Partnership increased the size of its $205.0 million Revolving Credit Facility to $350 million. Total 16 19 borrowings under the facility of $305.0 million were outstanding at December 31, 1998. Interest rates on this facility are variable and currently approximate 6%. During the third quarter of 1998, the Board of Directors of the General Partner approved a $200 million uncommitted lending facility from the General Partner to the Partnership. This uncommitted facility provided an alternative source of funds at market interest rates in the event that a disruption in the capital markets delayed anticipated debt and partner contributions. In late September 1998, the Partnership borrowed, and subsequently repaid in early October, $37.0 million under this arrangement. In October 1998, pursuant to a $400 million shelf registration statement filed with the Securities and Exchange Commission ("SEC"), $200 million face amount of senior unsecured notes were issued to retire borrowings under the Revolving Credit Facility and to repay the loan of $37 million issued by the General Partner. The Partnership issued the senior unsecured notes in two tranches of $100 million, each, with maturities of 2018 (with an interest rate of 7%) and 2028 (with an interest rate of 7.125%), respectively. For additional details relating to the Partnership's debt, see Note 6 to the Partnership's Financial Statements. In October 1997, the Partnership received net partner contributions of $100.2 million. These proceeds were used to finance a portion of SEP II. Distributions paid to partners during 1998 increased $20.1 million to $96.2 million. Distributions paid to partners for 1997 increased $11.5 million to $76.1 million compared to 1996. The Partnership distributes quarterly all of its Available Cash, which is generally defined to mean, with respect to any calendar quarter, the sum of all of the cash receipts of the Partnership plus net reductions to reserves less all of its cash disbursements and net additions to reserves. These reserves are retained to provide for the proper conduct of the Partnership's business, to stabilize partner distributions and as necessary to comply with the terms of any agreement or obligation of the Partnership. On February 12, 1999, the Partnership distributed $24.7 million related to the fourth quarter of 1998. The Partnership anticipates that it will continue to have adequate liquidity to fund future recurring operating, investing and financing activities. The Partnership intends to fund Terrace, remaining SEP II expenditures, and ongoing capital expenditures with the proceeds from future debt offerings and partner contributions, other borrowings, cash generated from operating activities, and existing cash, cash equivalents and short-term investments. Cash distributions are expected to be funded with internally generated cash. The Partnership's ability to make future debt offerings and receive future partner contributions will depend on prevailing market conditions and interest rates and the then-existing financial condition of the Partnership. FUTURE PROSPECTS Income and cash flows of the Partnership are sensitive to oil industry supply and demand in Canada and the United States, and the regulatory environment. As the Partnership's pipeline system is operationally integrated with the Enbridge Pipelines System in western Canada, the Partnership's revenues are dependent upon the utilization of the Enbridge Pipelines System by producers of western Canadian crude oil. The Partnership believes long-term demand for its pipeline system will continue in light of industry's increasing production forecasts for western Canadian crude oil and anticipated increased demand for crude oil in the Midwest U.S. See "Items 1 & 2. Business and Properties, - Supply and Demand for Western Canadian Crude Oil." In late 1998, representatives of the Canadian Association of Petroleum Producers ("CAPP") and the Partnership concluded informal discussions concerning the projected supply of western Canadian crude oil and NGL available for delivery during 1999. Based on these discussions, and as a result of the general decline in crude oil prices, it is anticipated that deliveries on the Partnership's pipeline system could be approximately 50,000 to 75,000 barrels per day (on average) less than 1998 delivery levels of 1,562,000 barrels per day. At this potential level of utilization, the Partnership will earn a 7.5% nominal rate of 17 20 return on its SEP II equity investment during 1999, the minimum prescribed in tariff agreements reached with a majority of the Partnership's customers. See "Items 1 & 2. Business and Properties, - Regulation, - Tariffs." The collective impact of reduced deliveries and a 7.5% rate of return on SEP II equity is anticipated to result in net income for 1999 of approximately $80 to $90 million. Based on current projections, the Partnership anticipates generating sufficient cash from operating activities to continue its current level of cash distribution through 1999. Despite the recent weakness in crude oil prices, the Partnership's outlook regarding future growth prospects remains positive. While the availability of western Canadian crude oil is sensitive to the long-term outlook for crude oil prices, the Partnership believes that recent announcements by major Canadian oil producers affirming oil sands development and other long-term expansion projects is encouraging and illustrative of long-term supply growth from the western Canadian sedimentary basin. The Lakehead and Enbridge Pipelines Systems (the "System") serve as a strategic link between the western Canadian oil fields and the markets of the Midwest U.S. and eastern Canada and have for the last several years operated at or near capacity. In response to a long-term trend of increasing supply of crude oil from western Canada and the growth of demand in the markets of the Midwest U.S., the Partnership plans not only to maintain the service capability of the existing Lakehead System but also to expand its capacity where appropriate. This is consistent with the Partnership's principal business objective to increase cash generated from its operations to enhance cash distributions. This strategy has enabled the Partnership to periodically increase quarterly cash distributions to its partners since 1992. Lakehead System Expansion Projects Key current and future expansion projects of the Partnership are summarized below: - - SEP II-- This expansion was largely completed in early 1999. SEP II involved the construction of a new pipeline from the Partnership's pipeline terminal at Superior, Wisconsin, to its Chicago, Illinois, market area. The pipeline is expected to provide an additional 170,000 barrels per day of delivery capacity on the Lakehead System. Under a tariff agreement with its customers ("Tariff Agreement"), a tariff surcharge has been implemented that recovers the costs of, and return on, the SEP II facilities. The Tariff Agreement allows the Partnership to earn a return on its SEP II equity investment based on the benchmark National Energy Board of Canada ("NEB") multi-pipeline rate of return. Under the Tariff Agreement, return on SEP II equity can range from a minimum equivalent to the NEB multi-pipeline rate of return less 3% (subject to a 7.5% floor) to a maximum of the multi-pipeline rate of return plus 3% (subject to a 15% ceiling). Rate of return on equity within the range is determined by measuring SEP II capacity utilization on the Enbridge Pipelines System in Canada. See "Items 1 & 2. Business and Properties, - Regulation, - Tariffs." - - Terrace Expansion Program-- This expansion program, which is being undertaken by the Partnership in conjunction with Enbridge Pipelines, is a phased expansion that is expected to ultimately provide an additional 520,000 barrels per day of heavy crude oil capacity for western Canadian producers seeking greater access to Midwest U.S. markets. Subject to continued industry support, customer requirements and receipt of regulatory approvals, the General Partner and Enbridge Pipelines anticipate that this expansion program will be completed in stages beginning in 1999. Phase I of Terrace includes construction of new 36-inch diameter pipeline facilities from Kerrobert, Saskatchewan, to Clearbrook, Minnesota. The new pipeline will join existing 48-inch diameter pipeline loops between Kerrobert and Clearbrook, creating another separate pipeline joining those locations. Phase I is expected to provide an initial 95,000 barrels per day increase in capacity in the first half of 1999, rising to 170,000 barrels per day by September 1999. Phase I construction is expected to cost the Partnership approximately $138 million for construction of facilities in the U.S., and Enbridge Pipelines Cdn. $610 million for construction of facilities in Canada. Subsequent phases of Terrace are dependent upon customer requirements and, if completed, are expected to provide up to 350,000 barrels per day of added heavy crude oil capacity in addition to the 170,000 barrels per 18 21 day to be provided by Phase I. Subject to completion of all phases, and after allowing for anticipated declines in light crude oil production, total System delivery capability is expected to increase by 350,000 barrels per day. A tariff surcharge for Terrace of approximately $0.013 per barrel (for light crude oil to Chicago) is anticipated to be filed in the first half of 1999. This tariff surcharge is premised on the completion of Phase 2 and Phase 3 of Terrace. Should these later phases not proceed, the Partnership will be allowed to increase its tariff surcharge on a cost of service basis to allow recovery of, and return on, its Phase I Terrace investment including any revenue variances between the application of the toll increment and annual Terrace cost of service. See "Items 1 & 2. Business and Properties, - Regulation, - Tariffs." The Partnership is subject to a rate regulatory methodology that prescribes rate ceilings that are adjusted each July 1. The rate ceilings are adjusted by reference to annual changes in the Producer Price Index for Finished Goods minus one percent ("PPIFG-1"). The General Partner expects the PPIFG-1 to decrease approximately 1.9% for 1998. This decrease in the PPIFG-1 should not have a material effect on 1999 operating revenue since the decrease does not apply to SEP II or Terrace tariff surcharges and will be effective mid-year 1999. To date, the Partnership has been able to manage its pipeline system to ensure inflationary cost pressures in excess of the PPIFG-1 have not materially impacted net income. The FERC is scheduled to review the appropriateness of the indexing methodology, and specifically the PPIFG-1 index, in year 2000. The indexed rate environment, the Settlement Agreement, and other negotiated settlements with customers for SEP II and Terrace are benefiting the Partnership and its customers by restoring stability and providing predictable tariff rates. Customer representatives who are a party to the various agreements have agreed not to challenge any rates within the indexed ceiling until October 2001. In addition, to the extent allowed under FERC orders or by agreement with customers, the Partnership has filed, and will continue to file, for additional tariff increases from time to time to reflect ongoing expansion programs. Enbridge Inc. Projects Enbridge Inc. ("Enbridge" formerly IPL Energy Inc.), the ultimate parent of the General Partner, is also engaged in North American crude oil pipeline projects which are related to the Enbridge Pipelines and Lakehead Systems. The General Partner believes that certain of these projects are complementary to ongoing and future expansion projects even though they are not owned by the Partnership, since the projects may result in increased deliveries on the Lakehead System. Such projects are summarized below: - - Mustang -- In 1996, a U.S. subsidiary of Enbridge entered into a partnership ("Mustang Pipe Line Partners") with Mobil Illinois Pipe Line Company, a subsidiary of Mobil Oil Corporation, to own and operate a crude oil pipeline that connects the Lakehead System to the Patoka/Wood River refinery area and pipeline hub south of Chicago. The Partnership has entered into a joint tariff agreement with Mustang Pipe Line Partners that became effective January 1, 1999. The agreement covers shipments of western Canadian crude oil over the Lakehead System and the Mustang pipeline. The joint tariff agreement provides lower transportation costs to shippers desiring access to the Patoka/Wood River market area. Prior to the joint tariff agreement, this market area was not competitively accessible to Partnership customers. The joint tariff agreement results in a reduction in the Partnership's light crude oil rate for deliveries destined for the Patoka/Wood River market area. The Mustang system has a capacity of approximately 100,000 barrels per day. - - Enbridge Toledo -- Enbridge has completed construction of a new pipeline, which connects the Partnership's facilities at Stockbridge, Michigan, to two refineries in the Toledo, Ohio, area. This pipeline is anticipated to have an approximate capacity in excess of 80,000 barrels per day in heavy crude oil service and became available for service in early February 1999. - - Enbridge Athabasca (formerly Wild Rose) -- Enbridge is scheduled to complete construction of a new 30-inch diameter pipeline for the delivery of heavy crude oil from the Athabasca oil sands region 19 22 near Fort McMurray, Alberta, to Hardisty, Alberta, by March 31, 1999. At Hardisty, the Athabasca pipeline would access other pipeline systems including the Enbridge Pipelines System in western Canada. This project would provide new pipeline capacity to accommodate anticipated growth in production in the Athabasca oil sands region. When fully powered, the Athabasca pipeline is anticipated to have an ultimate capacity of 570,000 barrels per day. Enbridge has entered into a 30-year transportation arrangement with Suncor Energy Inc., the initial shipper on the pipeline. Montreal Extension Reversal The Enbridge Pipelines System includes a section which extends from Sarnia, Ontario, to Montreal, Quebec (the "Montreal Extension" or "Line 9"). The portion of the Montreal Extension from Sarnia to North Westover, Ontario, is currently in west-to-east service and the portion of the Montreal Extension from North Westover to Montreal has been purged with nitrogen and remains available for service. Enbridge Pipelines and a group of refiners have developed the Line 9 reversal project to enable crude oil imported into eastern Canada through facilities of Portland Pipe Line Corporation and Montreal Pipe Line Limited to be transported on Line 9 in an east-to-west direction from Montreal to the major refining centers in Ontario. The reversal of the Montreal Extension will result in Enbridge Pipelines becoming a competitor of the Lakehead System for supplying crude oil to the Ontario market. This reversal is expressly permitted by the agreements entered into at the time of formation of the Partnership. The NEB approved construction of facilities as well as the tolling methodology for the Line 9 project on December 18, 1997. Enbridge received notice in July 1998 from the group of sponsoring refiners to proceed with construction of facilities necessary for reversal. Construction to allow for full reversal is expected to be completed late in the third quarter or early in the fourth quarter of 1999 at which time the reversed Line 9 is anticipated to have a capacity of approximately 240,000 barrels per day from Montreal to Sarnia. Due to upstream capacity constraints, the Montreal extension is anticipated to be reversed in two stages, with the first stage entering service in May 1999 with a capacity of 120,000 barrels per day from Montreal to North Westover. The Partnership anticipates that the reversal of Line 9 will result in a decline in deliveries over the Lakehead System to eastern Canada. Displaced volumes originating in western Canada are anticipated to be diverted to other markets in the Midwest U.S. U.S. domestic and foreign crude oil volumes that enter the Lakehead System in Chicago are also anticipated to decline from recent historical levels due to the reversal of Line 9. The level of decline in deliveries over the Lakehead System to eastern Canada will be dependent upon the global crude oil market dynamics and the level of utilization of Line 9. YEAR 2000 ISSUE The Partnership's pipeline system is operationally dependent on the ability of Enbridge Pipelines to transport crude oil and other liquid hydrocarbons from western Canada to reach markets in the United States and eastern Canada. Due to the integrated nature of these two pipeline systems, the Partnership's Year 2000 Readiness Program is being conducted in conjunction with Enbridge Pipelines. The Partnership's Year 2000 Readiness Program continues on schedule, with several milestone points being reached by December 31, 1998. The Year 2000 Project Teams of Enbridge Pipelines and the Partnership have compiled a comprehensive list of all computer hardware and software, embedded chip technologies and business processes including those having significant third party interdependencies. A risk assessment and business impact analysis of each item has also been completed and the Partnership is prioritizing its efforts and resources to ensure that all critical processes and assets are made to be compliant on a timely basis. Some critical systems, such as certain accounting systems which have been replaced under a business system upgrade project, are already known to be Year 2000 compliant, thereby reducing the risk of failure. The most critical systems are those that operate and control crude oil and NGL pipelines, as they are essential to Partnership operations. These systems are used to control the entire liquid pipeline system, including related tank farms and pumping stations. Instrumentation along the pipelines measure and 20 23 control temperatures, pressures, volume flow, pump operation, valve operation control equipment and alarm states. This information is also passed to various control systems to help monitor and track flowing crude oil and NGL in the pipeline system. The control systems are expected to be compliant by mid 1999. In addition, the Year 2000 Project Teams have identified third parties whose non compliance may have a significant effect on the ability of the Partnership to continue to conduct its business without disruption. Dialogue has been established with these entities in order to ascertain whether they will be Year 2000 compliant in advance of January 1, 2000. The most significant third party interdependencies are reliance on electrical and telecommunication suppliers as they are essential to the ability to transport crude oil and NGL through the System. Also of significance are feeder pipeline systems that deliver much of the crude oil and NGL entering the System, as are the receiving connecting pipelines and refineries. While the Partnership is unable to provide a current assessment of these critical suppliers' Year 2000 compliance progress, communication with these entities and monitoring of their Year 2000 readiness status will continue. In the case of critical suppliers and feeder pipelines, joint testing initiatives may also be implemented. Where timely assurance is not received, restrictions on use or replacement of vendors will be considered. In the review of the systems potentially impacted by the Year 2000 problem, Enbridge Pipelines and the Partnership are giving consideration to the repair, replacement, workaround, outsourcing and other methods of eliminating deficiencies. Enbridge Pipelines and the Partnership are currently involved in various stages of implementing their Year 2000 compliance initiatives and expect to have all critical processes and assets compliant by mid 1999, at which point lower risk systems will be remediated. In order to address unforeseen Year 2000 problems that could arise and in an attempt to minimize business disruptions, Enbridge Pipelines and the Partnership are developing business continuity plans for all critical processes, systems, technologies and external relationships. These plans are also expected to be completed before the end of the year. Preliminary cost estimates for achieving Year 2000 compliance of the Partnership are approximately $6 million, including $1 million in capital costs and $5 million of operating expense, with approximately $1 million of expense having been incurred to date. A majority of the remaining costs are anticipated to be incurred in 1999. No material resource constraints have been encountered to date. Although management believes this estimate to be reasonable, due to the complexities outlined above, there can be no assurance that the actual costs of the project will not differ materially from the estimated amounts. Despite the Partnership's best efforts, there can be no guarantees that all systems and applications will continue without interruption through January 1, 2000 and beyond. Limited testing ability on commercial software packages and the complexity of identifying all embedded microprocessors that may be used in a great variety of hardware used for process or flow control, environmental, transportation, security, communication and other systems may result in non compliant systems. Additionally, despite ongoing dialogue with interdependent third parties there can be no assurance that their systems will be fully compliant. In the event of critical system or supplier failure, crude oil and NGL deliveries could be temporarily delayed until corrective action is taken or continuity plans are implemented. Failures that result in substantial disruptions of business activities could be material to the Partnership. ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK The Partnership's market risk is primarily impacted by changes in interest rates. The Partnership has minimal foreign exchange risk and its cash flows are not significantly impacted by changes in commodity prices as the Partnership does not own the crude oil and NGL it transports. However, commodity prices have a significant impact on the underlying supply and demand for crude oil and NGL that the 21 24 Partnership transports. The Partnership does not currently hold or issue derivative instruments for trading or any other purposes. The Partnership's market risk with respect to interest rate exposure is managed through its long-term debt ratio target, and its allocation of fixed and floating rate debt. The table below provides information about the Partnership's financial instruments that are sensitive to changes in interest rates. For debt obligations the table presents principal cash flows and related weighted average interest rates by expected maturity date.
- --------------------------------------------------------------------------------------------------------------------- EXPECTED MATURITY DATE OF DEBT INSTRUMENTS ------------------------------------------------------ THERE- FAIR DECEMBER 31, 1998 1999 - 2001 2002 2003 AFTER TOTAL VALUE - --------------------------------------------------------------------------------------------------------------------- ($U.S. in Millions) Fixed Rate: First Mortgage Notes $0 $31.0 $31.0 $248.0 $310.0 $369.0 Interest Rate - 9.15% 9.15% 9.15% Senior Unsecured Notes $0 $0 $0 $200.0 $200.0 $209.0 Interest Rate - - - 7.06% Variable Rate: Revolving Credit Facility $0 $0 $305.0 $0 $305.0 $305.0 Interest Rate - - 5.8% - - ---------------------------------------------------------------------------------------------------------------------
The average interest rate of debt outstanding on the Partnership's Revolving Credit facility was 5.8% during 1998. For additional information concerning the Partnership's debt obligations, please see Note 6 to the Partnership's Consolidated Financial Statements. ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA The consolidated financial statements of the Partnership together with the notes thereto and the independent accountants' reports thereon, appear on pages F-2 through F-12 of this Report, and are incorporated by reference. Reference should be made to the Index to Financial Statements, Supplementary Information and Financial Statement Schedules on page F-1 of this Report. ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE None. 22 25 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 - ---- --- ----------------------------- E. C. Hambrook................ 61 Chairman and Director P. D. Daniel.................. 52 Director S. J. Wuori................... 41 President and Director R. C. Sandahl................. 48 Vice President and Director F. W. Fitzpatrick............. 66 Director C. A. Russell................. 65 Director D. P. Truswell................ 55 Director S. R. Wilson.................. 41 Vice President (since January 14, 1999) and Treasurer M. A. Maki.................... 34 Chief Accountant S. D. Lenczewski.............. 38 Secretary
Mr. Hambrook was elected a Director of the General Partner in January 1992 and has served as Chairman of the General Partner since July 1996. He also serves on the Audit Committee. Mr. Hambrook is the President of Hambrook Resources Inc. Mr. Daniel was elected a Director of the General Partner in July 1996 and served as its President from July 1996 through October, 1997. Since June 1998, Mr. Daniel has also served as President and Chief Operating Officer Energy Delivery of Enbridge. Prior thereto, Mr. Daniel served as Executive Vice President and Chief Operating Officer--Energy Transportation Services of Enbridge from September 1997 through June 1998, as Senior Vice President of Enbridge from May 1994 to August 1997, as President and Chief Executive Officer of Enbridge Pipelines from August 1996 to August 1997, and as President and Chief Operating Officer of Enbridge Pipelines from May 1994 to August 1996. Prior to May 1994, he served as Vice President, Planning of Enbridge. Mr. Wuori was appointed President and elected a Director of the General Partner as of November 1, 1997. He has served as President of Enbridge Pipelines since September 1997. Prior thereto, he served as Vice President, Operations of Enbridge Pipelines from May 1994 to August 1997, and, prior thereto, as District Manager of the General Partner. Mr. Sandahl was elected a Director and appointed Vice President of the General Partner in July 1996. He served as Vice President, Operations of the General Partner from May 1994 to August 1996. Prior thereto, he was employed by Enbridge Pipelines for six years where he served in various capacities, most recently as Director of Engineering Services from June 1990 to May 1994. Mr. Fitzpatrick was elected a Director of the General Partner in April 1993 and serves on the Audit Committee. He is also a Director of Enbridge and serves as Chairman of the Audit, Finance and Risk Committee of the Board of Enbridge. 23 26 Mr. Russell was elected a Director of the General Partner in October 1985 and serves as the Chairman of the Audit Committee. Mr. Russell served as Chairman and Chief Executive Officer of Norwest Bank Minnesota North, N.A. from January through December 1995. Prior to January 1995, he served as President of Norwest Bank Minnesota North, N.A. He also served as a Director of Minnesota Power and Light Co. until May 1996. Mr. Truswell was elected a Director of the General Partner in May 1991 and served as a Vice President of the General Partner from October 1991 to May 1994. Mr. Truswell has served as Senior Vice President and Chief Financial Officer of Enbridge since May 1994 and prior thereto, as Vice President, Finance of Enbridge from 1992 to May 1994. He also served in various senior executive capacities with Enbridge Pipelines, including as Vice President, Finance from May 1991 to May 1994. Mr. Wilson was appointed Treasurer of the General Partner as of November 1, 1997. He has served as Treasurer of Enbridge since September 1997 and, prior thereto, as its Assistant Treasurer from September 1995 to August 1997. Mr. Wilson has served as Treasurer of The Consumers' Gas Company Ltd., a subsidiary of Enbridge since April 1991. Mr. Maki has served as Chief Accountant of the General Partner since June 1997. Prior thereto, he served in various supervisory and professional positions with the General Partner or Enbridge affiliates in the areas of Internal Audit, Rate Regulation and Accounting. Ms. Lenczewski has served as Secretary of the General Partner since June 1998. Prior thereto, she served as Assistant Secretary of the General Partner, from July 1996 to June 1998. 24 27 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.) Inc., ("Enbridge U.S.") and other affiliates to provide the services required by the Partnership. ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT 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 services agreement with Enbridge U.S. whereby the General Partner will utilize the resources of Enbridge U.S. to operate the Partnership. Under this agreement, Enbridge U.S. will be reimbursed for all direct and indirect expenses it incurs or payments it makes on behalf of the Partnership. The General Partner also receives certain administrative, engineering, treasury and computer services from Enbridge and Enbridge Pipelines for the benefit of the Partnership. The Partnership reimburses the General Partner for the cost of these services. For information about reimbursements to the General Partner, see Note 7 to the Partnership's Consolidated Financial Statements. The Partnership has entered into an easement acquisition agreement with Enbridge Holdings (Mustang) Inc. ("Enbridge Mustang" formerly IPL Patoka Pipeline Holdings (U.S.A.) Inc.), a subsidiary of Enbridge U.S. For the benefit of the Partnership, Enbridge Mustang has acquired certain real property for purposes of granting a pipeline easement to the Partnership. Enbridge Mustang is reimbursed for all net costs associated with this process at cost by the Partnership and will be indemnified by the Partnership from and against all liabilities that may arise in connection with this process. This agreement was entered into to facilitate easement acquisitions for SEP II. Enbridge Mustang will begin to dispose of real property acquired in 1997 and 1998 and repay advances from the Partnership as properties are sold beginning in 1999. The Partnership has implemented an agreement with Mustang Pipe Line Partners to provide for a joint tariff covering shipments of western Canadian crude oil to the Patoka/Wood River market area south of Chicago. These shipments travel on the Lakehead System to Chicago and on the Patoka/Wood River market area through the Mustang pipeline system. The joint tariff agreement provides for lower transportation costs to shippers desiring access to the Patoka/Wood River market area, an incentive which the Partnership believes complements its expansion programs. Mustang Pipe Line Partners is a Delaware general partnership owned by Mobil Illinois Pipe Line Company and a wholly owned subsidiary of Enbridge U.S. Under the terms of the Revolving Credit Facility Agreement, the Partnership, Lakehead Services, Limited Partnership ("Services Partnership") and the General Partner may draw down funds up to a combined maximum of $350.0 million. The Partnership has a 1% general partner interest in the Services 25 28 Partnership, with the General Partner having a 99% limited partner interest. For additional details, see Note 6 to the Partnership's Consolidated Financial Statements. The Partnership has entered into a $200 million uncommitted lending facility with the General Partner. This uncommitted facility provided an alternative source of funds at market interest rates in the event that a disruption in the capital markets delayed access to debt and equity markets. In late September 1998, the Partnership borrowed, and subsequently repaid in early October, $37.0 million under this arrangement. For discussion of distribution restrictions and incentive distributions payable to the General Partner, see Note 3 to the Partnership's Consolidated Financial Statements. 26 29 PART IV ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K (a) As to financial statements, supplementary information and financial statement schedules, reference is made to "Index to Financial Statements, Supplementary Information and Financial Statement Schedules" on page F-1 of this Report. (b) The Registrant filed the following reports on Form 8-K during the fourth quarter of 1998: A report on Form 8-K was filed on December 28, 1998, submitting a press release of the Registrant dated December 21, 1998, announcing a tariff filing and net income expectations for 1999. A report on Form 8-K was filed on October 20, 1998, submitting an Underwriting Agreement, dated September 28, 1998, an indenture relating to senior debt securities dated September 15, 1998, an Indenture dated September 15, 1998 relating to subordinated debt securities, a First Supplemental Indenture, dated September 15, 1998 and a Second Supplemental Indenture dated September 15, 1998. (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 Lakehead Pipe Line Partners, L.P. (Lakehead Pipe Line Partners, L.P. Registration Statement No. 33-43425 - Exhibit 3.1) 4.1 Form of Certificate representing Class A Common Units. (Lakehead Pipe Line Partners, L.P. Form 8-A/A, dated May 2, 1997) 4.2 Amended and Restated Agreement of Limited Partnership of the Partnership, dated April 15, 1997. (Lakehead Pipe Line Partners, L.P. Form 8-A/A, dated May 2, 1997) 10.1 Note Agreement and Mortgage, dated December 12, 1991. (Lakehead Pipe Line Partners, L.P. 1991 Form 10-K - Exhibit 10.1) 10.2 [Intentionally Omitted]. 10.3 Distribution Support Agreement, dated December 27, 1991, among the Lakehead Pipe Line Partners, L.P., Lakehead Pipe Line Company, Inc. and Interprovincial Pipe Line Inc. (Lakehead Pipe Line Partners, L.P. 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. (Lakehead Pipe Line Partners, L.P. 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. (Lakehead Pipe Line Partners, L.P. 1991 Form 10-K - Exhibit 10.4) 27 30 10.6 Amended Services Agreement, dated January 1, 1992, between Interprovincial Pipe Line Inc. and Lakehead Pipe Line Company, Inc. (Lakehead Pipe Line Partners, L.P. 1992 Form 10-K - Exhibit 10.6) 10.7 Certificate of Limited Partnership of Lakehead Pipe Line Company, Limited Partnership. (Lakehead Pipe Line Partners, L.P. Registration Statement No. 33-43425 - Exhibit 10.1) 10.8 Amended and Restated Agreement of Limited Partnership of Lakehead Pipe Line Company, Limited Partnership, dated December 27, 1991. (Lakehead Pipe Line Partners, L.P. 1991 Form 10-K - Exhibit 10.6) 10.9 Certificate of Limited Partnership of Lakehead Services, Limited Partnership. (Lakehead Pipe Line Partners, L.P. Registration Statement No. 33-43425 - Exhibit 10.4) 10.10 Amendment No. 1 to the Certificate of Limited Partnership of Lakehead Services, Limited Partnership. (Lakehead Pipe Line Partners, L.P. 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. (Lakehead Pipe Line Partners, L.P. 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. (Lakehead Pipe Line Partners, L.P. 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. (Lakehead Pipe Line Partners, L.P. 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. (Lakehead Pipe Line Partners, L.P. 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. (Lakehead Pipe Line Partners, L.P. 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. (Lakehead Pipe Line Partners, L.P. 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. (Lakehead Pipe Line Partners, L.P. Form 10-Q/A, filed September 14, 1998 - Exhibit 10.1) 28 31 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. (Lakehead Pipe Line Partners, L.P. 1996 Form 10-K - Exhibit 10.17) 10.19 Promissory Note, dated as of September 30, 1998, among Lakehead Pipe Line Company, Inc. as lender and Lakehead Pipe Line Company, Limited Partnership as borrower. (Lakehead Pipe Line Partners, L.P. 1998 Form 10-K - Exhibit 10.19) 10.20 Treasury Services Agreement, dated January 1, 1996, between IPL Energy Inc. and Lakehead Pipe Line Company, Inc. (Lakehead Pipe Line Partners, L.P. 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. (Lakehead Pipe Line Partners, L.P. 1998 Form 10-K - Exhibit 10.19) 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) 27 Financial Data Schedule as of and for the year ended December 31, 1998. All Exhibits listed above, with the exception of Exhibit 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. 29 32 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 9, 1999 By: /s/ S.J. Wuori ------------------------------------- S.J. Wuori (President) PURSUANT TO THE REQUIREMENTS OF THE SECURITIES EXCHANGE ACT OF 1934, THIS REPORT HAS BEEN SIGNED BELOW ON MARCH 9, 1999 BY THE FOLLOWING PERSONS ON BEHALF OF THE REGISTRANT AND IN THE CAPACITIES INDICATED WITH LAKEHEAD PIPE LINE COMPANY, INC., GENERAL PARTNER. /s/ S.J. Wuori /s/ E.C. Hambrook - ------------------------------------ ---------------------------------- S.J. Wuori E.C. Hambrook President and Director Chairman and Director (Principal Executive Officer) /s/ R.C. Sandahl /s/ M.A. Maki - ------------------------------------ ---------------------------------- R.C. Sandahl M.A. Maki Vice President and Director Chief Accountant (Principal Financial and Accounting Officer) /s/ F.W. Fitzpatrick /s/ P.D. Daniel - ------------------------------------ ---------------------------------- F.W. Fitzpatrick Director P.D. Daniel Director /s/ C.A. Russell /s/ D.P. Truswell - ------------------------------------ ---------------------------------- C.A. Russell Director D.P. Truswell Director 30 33 INDEX TO FINANCIAL STATEMENTS, SUPPLEMENTARY INFORMATION AND FINANCIAL STATEMENT SCHEDULES LAKEHEAD PIPE LINE COMPANY, LIMITED PARTNERSHIP
PAGE ---- Financial Statements Report of Independent Accountants..................................................................... F-2 Statement of Income for the Years Ended December 31, 1998, 1997, 1996................................. F-3 Statement of Cash Flows for the Years Ended December 31, 1998, 1997, 1996............................. F-4 Statement of Financial Position as at December 31, 1998 and 1997...................................... F-5 Statement of Partners' Capital for the Years Ended December 31, 1998, 1997, 1996...................... F-6 Notes to the 1998 Financial Statements................................................................ F-7 Supplementary Information (Unaudited) Selected Quarterly Financial Data..................................................................... F-13
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 34 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, of partners' capital and of cash flows present fairly, in all material respects, the financial position of Lakehead Pipe Line Company, Limited Partnership (the "Partnership") at December 31, 1998 and 1997, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1998 in conformity with generally accepted accounting principles. These financial statements are the responsibility of the Partnership's management; our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with generally accepted auditing standards which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for the opinion expressed above. PRICEWATERHOUSECOOPERS LLP Minneapolis, Minnesota January 8, 1999 F-2 35
- -------------------------------------------------------------------------------------------------------------------- LAKEHEAD PIPE LINE COMPANY, LIMITED PARTNERSHIP STATEMENT OF INCOME - -------------------------------------------------------------------------------------------------------------------- (DOLLARS IN MILLIONS) - -------------------------------------------------------------------------------------------------------------------- Year Ended December 31, 1998 1997 1996 - -------------------------------------------------------------------------------------------------------------------- OPERATING REVENUE (NOTE 8) $ 287.7 $ 282.1 $ 274.5 - -------------------------------------------------------------------------------------------------------------------- Expenses Power $ 69.0 65.9 62.0 Operating and administrative 71.9 68.0 66.7 Depreciation 41.4 40.1 38.3 Provision for prior years' rate refunds (Note 8) - - 20.1 - -------------------------------------------------------------------------------------------------------------------- 182.3 174.0 187.1 - -------------------------------------------------------------------------------------------------------------------- Operating Income 105.4 108.1 87.4 Interest and Other Income 5.9 9.7 9.6 Interest Expense (Note 5) (21.9) (38.6) (43.9) - -------------------------------------------------------------------------------------------------------------------- Net Income $ 89.4 $ 79.2 $ 53.1 ====================================================================================================================
The accompanying notes to the financial statements are an integral part of these statements. F-3 36
- -------------------------------------------------------------------------------------------------------------------- LAKEHEAD PIPE LINE COMPANY, LIMITED PARTNERSHIP STATEMENT OF CASH FLOWS - -------------------------------------------------------------------------------------------------------------------- (DOLLARS IN MILLIONS) - -------------------------------------------------------------------------------------------------------------------- Year ended December 31, 1998 1997 1996 Cash Provided from Operating Activities Net income $ 89.4 $ 79.2 $ 53.1 Adjustments to reconcile net income to cash provided from operating activities: Depreciation 41.4 40.1 38.3 Accrued rate refunds and related interest (Note 8) 2.1 3.5 42.6 Other 0.2 0.5 0.6 Changes in operating assets and liabilities: Accounts receivable and other (2.8) 4.8 (0.7) Materials and supplies - (0.1) (1.6) General Partner and affiliates (1.0) 2.4 0.2 Accounts payable and other 2.1 1.5 3.6 Interest payable 0.2 2.1 0.7 Property and other taxes 0.5 0.3 (1.1) Payment of rate refunds and related interest (Note 8) (28.5) (27.7) (41.8) - -------------------------------------------------------------------------------------------------------------------- 103.6 106.6 93.9 - -------------------------------------------------------------------------------------------------------------------- Investing Activities Short-term investments, net 53.9 29.8 (8.0) Advances to affiliate (Note 6) (25.5) (6.5) - Additions to property, plant and equipment (487.3) (126.9) (76.7) Changes in construction payables 31.0 1.9 - (427.9) (101.7) (84.7) - -------------------------------------------------------------------------------------------------------------------- Financing Activities Variable rate financing, net (Note 5) 152.0 - 68.0 Fixed rate financing, net (Note 5) 196.9 - - Partners' contributions, net - 100.2 - Distributions to partners (Note 3) (96.2) (76.1) (64.6) - -------------------------------------------------------------------------------------------------------------------- 252.7 24.1 3.4 - -------------------------------------------------------------------------------------------------------------------- Increase (Decrease) in Cash and Cash Equivalents (71.6) 29.0 12.6 Cash and Cash Equivalents at Beginning of Year 118.6 89.6 77.0 - -------------------------------------------------------------------------------------------------------------------- Cash and Cash Equivalents at End of Year $ 47.0 $ 118.6 $ 89.6 ====================================================================================================================
The accompanying notes to the financial statements are an integral part of these statements. F-4 37
- -------------------------------------------------------------------------------------------------------------------- LAKEHEAD PIPE LINE COMPANY, LIMITED PARTNERSHIP STATEMENT OF FINANCIAL POSITION - -------------------------------------------------------------------------------------------------------------------- (DOLLARS IN MILLIONS) - -------------------------------------------------------------------------------------------------------------------- December 31, 1998 1997 - -------------------------------------------------------------------------------------------------------------------- ASSETS Current Assets Cash and cash equivalents $ 47.0 $ 118.6 Short-term investments - 53.9 Advances to affiliate (Note 6) 32.0 6.5 Accounts receivable and other 25.2 22.4 Materials and supplies 7.1 7.1 - -------------------------------------------------------------------------------------------------------------------- 111.3 208.5 Deferred Charges and Other 6.7 4.3 Property, Plant and Equipment, Net (Note 4) 1,296.2 850.3 - -------------------------------------------------------------------------------------------------------------------- $ 1,414.2 $ 1,063.1 ==================================================================================================================== LIABILITIES AND PARTNERS' CAPITAL Current Liabilities Due to General Partner and affiliates $ 2.9 $ 3.9 Accounts payable and other 53.3 20.2 Interest payable 5.5 5.3 Property and other taxes 11.9 11.4 Current portion of accrued rate refunds and related interest (Note 8) 28.7 29.0 - -------------------------------------------------------------------------------------------------------------------- 102.3 69.8 Long-Term Debt (Note 5) 814.5 463.0 Accrued Rate Refunds and Related Interest (Note 8) - 26.1 Contingencies (Note 9) - -------------------------------------------------------------------------------------------------------------------- 916.8 558.9 - -------------------------------------------------------------------------------------------------------------------- Partners' Capital Limited Partner 494.8 501.7 General Partner 2.6 2.5 - -------------------------------------------------------------------------------------------------------------------- 497.4 504.2 - -------------------------------------------------------------------------------------------------------------------- $ 1,414.2 $ 1,063.1 ====================================================================================================================
The accompanying notes to the financial statements are an integral part of these statements. F-5 38
- -------------------------------------------------------------------------------------------------------------------- LAKEHEAD PIPE LINE COMPANY, LIMITED PARTNERSHIP STATEMENT OF PARTNERS' CAPITAL - -------------------------------------------------------------------------------------------------------------------- Limited General (DOLLARS IN MILLIONS) Partner Partner Total - -------------------------------------------------------------------------------------------------------------------- Partner's capital at December 31, 1995 $ 411.0 $ 1.4 $ 412.4 Net income allocation 52.4 0.7 53.1 Distributions to partners (63.9) (0.7) (64.6) - -------------------------------------------------------------------------------------------------------------------- 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 ====================================================================================================================
The accompanying notes to the financial statements are an integral part of these statements. F-6 39 - -------------------------------------------------------------------------------- LAKEHEAD PIPE LINE COMPANY, LIMITED PARTNERSHIP NOTES TO THE 1998 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") (formerly Interprovincial Pipe Line Inc.), a Canadian company owned by Enbridge Inc. (formerly IPL Energy 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 in the United States and conform in all material respects with the historical cost accounting standards of the International Accounting Standards Committee. The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses and related disclosures. 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. Amounts provided for accrued rate refunds are recognized as a direct reduction from revenues except for amounts related to prior years (Note 8), which are separately stated as a provision for prior years' rate refunds. CASH EQUIVALENTS AND SHORT-TERM INVESTMENTS Cash equivalents are defined as all highly marketable securities with a maturity of three months or less when purchased. Short-term investments are marketable securities with a maturity of more than three months when purchased. Both are accounted for as held-to-maturity securities and valued at amortized cost. MATERIALS AND SUPPLIES Materials and supplies are stated at the lower of cost or market value. DEFERRED FINANCING CHARGES Deferred financing charges are amortized on the straight line basis over the life of the related debt, which is comparable to results using the effective interest method. F-7 40 2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED) 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. Such taxable income reportable to the partners may vary substantially from financial income as a result of differences between the tax basis and financial reporting basis of assets and liabilities and the taxable income allocation requirements under the Operating 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. COMPARATIVE AMOUNTS Certain comparative amounts are reclassified to conform with the current year's financial statement presentation. 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 1998, 1997 and 1996, the Operating Partnership paid cash distributions of $96.2 million, $76.1 million and $64.6 million, respectively. On January 14, 1999, the Operating Partnership expects to declare a cash distribution relating to the fourth quarter of 1998 of $24.8 million. This anticipated distribution would be payable on February 12, 1999 to the partners in accordance with their respective percentage interest of record on January 29, 1999. F-8 41 4. PROPERTY, PLANT AND EQUIPMENT, NET
- -------------------------------------------------------------------------------------------------------------------- Average Depreciation December 31, Rates 1998 1997 - -------------------------------------------------------------------------------------------------------------------- Land - $ 6.2 $ 6.1 Rights-of-way 3.6% 126.4 12.6 Pipeline 4.1% 783.0 519.6 Pumping equipment, buildings and tanks 4.6% 427.1 355.4 Vehicles, office and communications equipment 13.9% 28.8 27.4 Construction in progress - 115.8 87.4 - -------------------------------------------------------------------------------------------------------------------- 1,487.3 1,008.5 Accumulated depreciation (191.1) (158.2) - -------------------------------------------------------------------------------------------------------------------- $ 1,296.2 $ 850.3 ====================================================================================================================
5. DEBT
December 31, 1998 1997 First Mortgage Notes $ 310.0 $ 310.0 Revolving Credit Facility Agreement 305.0 153.0 Senior Unsecured Notes, Net 199.5 - - -------------------------------------------------------------------------------------------------------------------- $ 814.5 $ 463.0 ===================================================================================================================
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 current 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 2003, but is subject to extension. Each year, on the anniversary date of the facility, the current maturity date may be extended by one year subject to the approval of the lending banks. Upon drawdown, the loans are secured by a first lien on the mortgaged property that ranks equally with the Notes or may be fully collateralized with U.S. or Canadian government securities. The facility contains restrictive covenants substantially identical to those in the Note Agreements, provides for borrowing at variable interest rates and currently attracts a facility fee of 0.075% (1997 - 0.075%; 1996 - 0.085%) per annum on the entire $350.0 million ($205.0 million prior to June 18, 1998). At December 31, 1998, $305.0 million of the facility was utilized and is classified as long-term debt (1997 - $153.0 million). The interest rate on loans averaged 5.8% (1997 - 6.2%; 1996 - 6.8%) and was 5.5% at the end of 1998 (1997 - 6.2%). F-9 42 5. DEBT (CONTINUED) SENIOR UNSECURED NOTES On October 1, 1998, the Operating Partnership issued a total of $200.0 million Senior Unsecured Notes in two tranches of $100.0 million. The first tranche of $100 million carries an interest rate of 7.00% and matures in 2018. The second tranche carries an interest rate of 7.125% and matures in 2028. Interest on both tranches is payable semi-annually. The Senior Unsecured Notes do not contain any financial tests restricting the issuance of additional indebtedness. INTEREST Interest expense includes $2.1 million related to accrued rate refunds (1997 - $3.5 million; 1996 - $9.7 million) and is net of amounts capitalized of $25.5 million (1997 - $3.3 million; 1996 - $2.4 million). Interest paid amounted to $44.4 million (1997 - $39.9 million; 1996 - $44.8 million). 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 $34.9 million (1997 - $33.2 million; 1996 - $33.9 million) and are included in operating and administrative expenses. At December 31, 1998, the Operating Partnership has accounts payable to the General Partner and affiliates of $2.9 million (1997 - $3.9 million). Under the terms of the Revolving Credit Facility Agreement, Lakehead Services, Limited Partnership ("Services Partnership") and the Operating Partnership may draw down funds up to a combined maximum of $350.0 million ($205.0 million prior to June 18, 1998). The Operating Partnership is entitled to require the Services Partnership to repay any amounts owed by the Services Partnership in order to allow the Operating Partnership to borrow thereunder. At December 31, 1998, the Services Partnership had no borrowings under the facility. The Services Partnership is a Delaware limited partnership in which the General Partner holds a 99% limited partner interest and the Lakehead Partnership holds a 1% general partner interest. The Operating Partnership has entered into an easement acquisition agreement with Enbridge Holdings (Mustang) Inc. ("Enbridge Mustang") (formerly IPL Patoka Pipeline Holdings (U.S.A.) Inc.), an affiliate of the General Partner. Enbridge Mustang has acquired certain real property for the purpose of granting pipeline easements to the Operating Partnership for a new pipeline constructed by the Operating Partnership from Superior, Wisconsin to Chicago, Illinois. The Operating Partnership has made non-interest bearing cash advances to Enbridge Mustang in order to provide for these real property acquisitions by Enbridge Mustang. These advances amounted to $32.0 million at December 31, 1998 (1997 - $6.5 million). During the third quarter of 1998, the Board of Directors of the General Partner approved a $200.0 million lending facility from the General Partner to the Operating Partnership to provide an alternative backup source of funds in the event that a temporary disruption in the capital markets delays anticipated debt and equity issuances. Under this facility, in late September 1998, the Operating Partnership borrowed $37.0 million from the General Partner at an interest rate of 8.75%. This loan was repaid in early October upon completion of the Operating Partnership's Senior Unsecured Note offering. No amounts were outstanding at December 31, 1998. F-10 43 7. MAJOR CUSTOMERS Operating revenue received from major customers was as follows:
- -------------------------------------------------------------------------------------- Year ended December 31, 1998 1997 1996 - -------------------------------------------------------------------------------------- Amoco Oil Company $ 57.9 $ 60.7 $ 63.2 Mobil Oil Company of Canada Ltd. $ 40.0 $ 42.5 $ 37.2 Imperial Oil Limited $ 33.6 $ 33.2 $ 35.4 ======================================================================================
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, the FERC approved a July 1996 agreement ("Settlement Agreement") between the Operating Partnership and customer representatives on all outstanding contested tariff rates. The Settlement Agreement resulted in an approximate tariff rate reduction of 6% and total rate refunds and related interest of $120.0 million through the effective date of October 1, 1996. The Operating Partnership provided for $42.6 million of rate refunds and related interest in 1996 to reflect the Settlement Agreement. Of the amount provided, rate refunds related to 1996 of $12.8 million have reduced operating revenue, with prior years' portion, $20.1 million, separately stated as a provision for prior years' rate refunds. Rate refund interest expense for 1996 and prior year amounts totaling $9.7 million were recorded in interest expense. The balance of the $120.0 million of accrued rate refunds and related interest required under the Settlement Agreement was provided for prior to 1996. Refunds required under the Settlement Agreement began in 1996 with $41.8 million repaid during the fourth quarter of 1996, with the remaining balance being repaid through a 10% reduction on future rates. This reduction will continue until all refunds have been made, which is expected to remain effective until sometime during the second half of 1999. During 1998, refunds of $28.5 million (1997 - $27.7 million) were made to customers and interest expense of $2.1 million (1997 - $3.5 million) was recorded by the Operating Partnership. Interest will continue to accrue on the unpaid balance based on the 90-day Treasury bill rate. 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 covered 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. F-11 44 9. CONTINGENCIES (CONTINUED) OIL IN CUSTODY The Operating Partnership transports crude oil and natural gas liquids ("NGLs") owned by its customers for a fee. The volume of liquid hydrocarbons in the Operating Partnership's pipeline system at any one time approximates 12 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 NGLs in the Operating Partnership's custody. 10. FAIR VALUE OF FINANCIAL INSTRUMENTS The carrying amounts of cash equivalents and short-term investments approximate fair value. The short-term investments consist of high quality commercial paper. Based on the borrowing rates currently available for instruments with similar terms and remaining maturities, the carrying value of borrowings under the Revolving Credit Facility approximate fair value, the fair value of the First Mortgage Notes approximates $369 million (1997 - $363 million) and the fair value of the Senior Unsecured Notes approximates $209 million. Due to defined contractual arrangements, refinancing of the First Mortgage Notes and Senior Unsecured Notes would not result in any financial benefit to the Operating Partnership. F-12 45 LAKEHEAD PIPE LINE COMPANY, LIMITED PARTNERSHIP SUPPLEMENTARY INFORMATION (UNAUDITED) SELECTED QUARTERLY FINANCIAL DATA (dollars in millions)
- ---------------------------------------------------------------------------------------------------------------------- 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 $ 23.1 $ 24.5 $ 22.8 $ 19.0 $ 89.4 - ---------------------------------------------------------------------------------------------------------------------- 1997 QUARTERS First Second Third Fourth Total - ---------------------------------------------------------------------------------------------------------------------- Operating revenue $ 68.7 $ 66.9 $ 72.3 $ 74.2 $ 282.1 Operating income $ 25.7 $ 26.9 $ 27.1 $ 28.4 $ 108.1 Net income $ 17.9 $ 19.4 $ 19.6 $ 22.3 $ 79.2 - ----------------------------------------------------------------------------------------------------------------------
F-13 EX-27.1 2 FINANCIAL DATA SCHEDULE
5 1,000 U.S. DOLLARS YEAR DEC-31-1998 JAN-01-1998 DEC-31-1998 1 47,000 0 25,200 0 0 111,300 1,487,300 191,100 1,414,200 102,300 814,500 0 0 0 497,400 1,414,200 0 287,700 0 182,300 0 0 21,900 89,400 0 89,400 0 0 0 89,400 0 0
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