Back to GetFilings.com
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 [FEE REQUIRED]
For the fiscal year ended DECEMBER 31, 1996
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE
SECURITIES EXCHANGE ACT OF 1934 [NO FEE REQUIRED]
For the transition period from ___________ to ___________
Commission File Number: 1-10934
LAKEHEAD PIPE LINE PARTNERS, L.P.
(Exact name of Registrant as specified in its charter)
DELAWARE
(State or other jurisdiction of
incorporation or organization)
39-1715850
(I.R.S. Employer
Identification No.)
LAKE SUPERIOR PLACE
21 WEST SUPERIOR STREET
DULUTH, MINNESOTA 55802-2067
(Address of principal executive offices and zip code)
(218) 725-0100
(Registrant's telephone number, including area code)
-------------------------
Securities registered pursuant to Section 12(b) of the Act:
TITLE OF EACH CLASS NAME OF EACH EXCHANGE ON WHICH REGISTERED
------------------- -----------------------------------------
Preference Units New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act: NONE
-------------------------
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. [ ]
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 __
As of February 3, 1997, the aggregate market value of the Registrant's
Preference units held by non affiliates of the Registrant was $763,420,000 based
on the reported closing sale price of such units on the New York Stock Exchange
on that date.
As of February 3, 1997, there were 20,090,000 of the Registrant's
Preference units outstanding.
-------------------------
DOCUMENTS INCORPORATED BY REFERENCE: NONE
================================================================================
2
TABLE OF CONTENTS
PAGE
----
PART I
ITEMS 1 & 2. Business and Properties..................................... 1
ITEM 3. Legal Proceedings........................................... 14
ITEM 4. Submission of Matters to a Vote of Security Holders......... 15
PART II
ITEM 5. Market for Registrant's Common Equity and Related
Stockholder Matters......................................... 15
ITEM 6. Selected Financial Data..................................... 16
ITEM 7. Management's Discussion and Analysis of Financial Condition
and Results of Operations................................... 17
ITEM 8. Financial Statements and Supplementary Data................. 20
ITEM 9. Changes in and Disagreements with Accountants on Accounting
and Financial Disclosure.................................... 20
PART III
ITEM 10. Directors and Executive Officers of the Registrant.......... 21
ITEM 11. Executive Compensation...................................... 22
ITEM 12. Security Ownership of Certain Beneficial Owners and
Management.................................................. 22
ITEM 13. Certain Relationships and Related Transactions.............. 23
PART IV
ITEM 14. Exhibits, Financial Statement Schedules and Reports on Form
8-K......................................................... 24
SIGNATURES................................................................ 26
INDEX TO FINANCIAL STATEMENTS, SUPPLEMENTARY INFORMATION AND FINANCIAL
STATEMENT SCHEDULES..................................................... F-1
When used in this document, the words "anticipate," "believe," "expect,"
"estimate," and similar expressions are intended to identify forward-looking
statements. Such statements are subject to certain risks, uncertainties and
assumptions. Should one or more of these risks or uncertainties materialize, or
should underlying assumptions prove incorrect, actual results may vary
materially from those anticipated, believed, expected or estimated. For
additional discussion of such risks, uncertainties and assumptions, see "Items 1
& 2, Business and Properties -- Business Risks" included elsewhere in this
report.
3
PART I
ITEMS 1 & 2. BUSINESS AND PROPERTIES
GENERAL
Lakehead Pipe Line Partners, L.P. is a publicly traded Delaware limited
partnership ("Registrant" or "Partnership"), which owns a 99% limited partner
interest in Lakehead Pipe Line Company, Limited Partnership ("Operating
Partnership"), also a Delaware limited partnership. Unless the context otherwise
requires, references herein to the Partnership include the Registrant and the
Operating Partnership.
The Partnership was formed in 1991 to acquire, own and operate the crude
oil and natural gas liquids pipeline business of Lakehead Pipe Line Company,
Inc. (the "General Partner"), a wholly-owned subsidiary of Interprovincial Pipe
Line Inc. ("Interprovincial"). Interprovincial is a Canadian company owned by
IPL Energy Inc. ("IPL Energy") of Calgary, Alberta, Canada. The General Partner
has a 16% limited partner (in the form of 3,912,750 Common units) and 1% general
partner interest in the Registrant, as well as a 1% general partner interest in
the Operating Partnership (an effective 18% combined interest in the
Partnership). The remaining 82% limited partner interest in the Partnership is
represented by 20,090,000 publicly traded Preference units.
Interprovincial and the Partnership are engaged in the transportation of
crude oil and other liquid hydrocarbons through a common carrier pipeline system
("System"). The System, which is the primary transporter of crude oil from
Canada to the United States and is the only pipeline that transports crude oil
from western Canada to eastern Canada, serves all the major refining centers in
the Great Lakes region of the United States, as well as the province of Ontario,
Canada. The System consists of the IPL and IPL(NW) Systems in Canada and the
Lakehead System, which is owned by the Partnership, in the United States.
The Lakehead System traverses approximately 1,750 miles from the Canadian
border near Neche, North Dakota, to the Canadian border near Marysville,
Michigan. The Lakehead System consists of three separate lines extending from
the Canadian border near Neche to Superior, Wisconsin, and a line from the
Canadian border near Neche to Clearbrook, Minnesota. At Superior, the pipeline
continues as two separate lines, one traversing through the upper Great Lakes
region and the other through the lower Great Lakes region of the United States,
with both lines re-entering Canada at a point near Marysville. The Lakehead
System also includes a lateral line from the Canadian border near Niagara Falls,
Ontario to the Buffalo, New York area.
The IPL System, which is owned and operated by Interprovincial, extends
approximately 1,200 miles from Edmonton, Alberta, across the Canadian Prairies
to the U.S. border near Neche, and continues from the U.S. border near
Marysville, to Toronto, Ontario, and Montreal, Quebec, with lateral lines to
Nanticoke, Ontario, and Niagara Falls.
The IPL(NW) System, which is owned and operated by Interprovincial Pipe
Line (NW) Ltd., a wholly owned subsidiary of IPL Energy, extends approximately
540 miles between Norman Wells, Northwest Territories and Zama, Alberta.
PROPERTIES
The Lakehead System consists of approximately 2,600 miles of pipe with
diameters ranging from 12 inches to 48 inches, 57 main line pump station
locations with a total of approximately 551,000 installed horsepower and 45
tanks with an aggregate capacity of approximately 9 million barrels. The volume
of liquid hydrocarbons in the Lakehead System that is required at all times for
operation amounts to approximately 12 million barrels, all of which is owned by
the shippers on the Lakehead System.
The Lakehead System is comprised of a number of separate segments as
follows:
(i) (a) the portion of Line 13 that extends from the Canadian border
near Neche to Clearbrook consisting of 18 inch pipe;
1
4
(b) the portions of Lines 1, 2, and 3 that extend from the Canadian
border near Neche to Superior consisting of 20 (18 inch from Clearbrook
to Superior), 26 and 34 inch pipe, respectively; Line 3 is looped with
approximately 120 miles of 48 inch pipe;
(ii) Line 5, a 30 inch line from Superior through the upper Great
Lakes region via the upper peninsula of Michigan and across the Straits of
Mackinac to the Canadian border near Marysville;
(iii) the portion of Line 6 that is a 34 inch line from Superior to
the Chicago area;
(iv) the portion of Line 6 that is a 30 inch line extending from the
Chicago area to the Canadian border near Marysville; and
(v) the portion of Line 10 that is a lateral line from the Canadian
border near Niagara Falls to the Buffalo area consisting of 12 inch pipe,
which is looped with a 4 mile section of 20 inch pipe.
The Lakehead System regularly transports up to 35 different types of liquid
hydrocarbons including light, medium and heavy crude oil (including bitumen),
condensate, synthetic crudes and natural gas liquids ("NGL").
Estimated capacities of the various segments of the Lakehead System for
1997 are as follows:
DESIGN ANNUAL
LINE SEGMENT CAPACITY CAPACITY
------------ -------- --------
(THOUSANDS OF
BARRELS PER DAY)
Canadian border to Clearbrook............................... 1,729 1,452
Clearbrook to Superior...................................... 1,512 1,218
Superior to Canadian border near Marysville (through the
upper Great Lakes region)................................. 566 509
Superior to Chicago area.................................... 782 704
Chicago area to Canadian border near Marysville............. 409 368
Canadian border near Niagara Falls to the Buffalo area...... 66 59
Design capacity is the absolute theoretical system capacity and assumes
that all required horsepower is fully operational at all times. Annual capacity,
which takes into account receipt and delivery patterns and ongoing pipeline
maintenance, reflects achievable rates over long periods of time.
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.
To prolong the useful life of the Lakehead System, pipeline crews perform
scheduled maintenance and make repairs when necessary. The Partnership attempts
to control corrosion of the pipeline through use of pipe coatings and cathodic
protection systems. These preventive measures are supported by internal
inspections using electronic instruments. On a bi-weekly basis, the entire right
of way is inspected from the air. 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.
The Partnership continued its integrity program of periodic internal
inspections of the Lakehead System during 1996 as inspections were conducted on
selected sections of Line 3 and all of Line 5. Additional internal inspections
will continue in 1997.
TITLE TO PROPERTIES
The Partnership conducts business and owns properties located in seven
states. The Lakehead System is, in general, located on land owned by others and
is operated under perpetual easements or rights of way granted by land owners,
public authorities, railways or public utilities. In certain of the states
through which the pipeline passes, the Partnership has rights of condemnation.
These rights have been exercised from time to time.
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
2
5
others and operated under easements or permits. 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. For a discussion of the most
recent report by the National Energy Board of Canada ("NEB") relating to
long-term trends in the supply of crude oil produced in western Canada, see "--
Supply and Demand Projections for Western Canadian Crude Oil". If a decline in
western Canadian crude oil does occur, the Partnership expects that throughput
on the Lakehead System will also decline.
The Partnership's business depends in part on the level of demand for crude
oil and natural gas liquids in the geographic areas in which deliveries are made
by the Lakehead System and the ability and willingness of shippers having access
to the Lakehead System to supply such demand by deliveries through the Lakehead
System. 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.
For a discussion of the most recent report by the NEB relating to long-term
trends in the demand for crude oil produced in western Canada, see "-- Supply
and Demand Projections for Western Canadian Crude Oil".
The Lakehead System is dependent upon the utilization of the IPL System by
producers of western Canadian crude oil to reach markets in the United States
and eastern Canada. The diversion of western Canadian crude oil away from the
IPL System, whether by virtue of increased demand by western Canadian refiners
or the shipment of crude oil by other pipelines, would be likely to have a
direct impact on the volumes transported by the Lakehead System. The Lakehead
System encounters competition in serving shippers to the extent that shippers
have alternative opportunities for transporting liquid hydrocarbons from their
sources to customers. In addition, the Lakehead System is affected by the
conditions in the markets for liquid hydrocarbons in the areas to which the
Lakehead System makes deliveries. For a discussion of competition, see "--
Competition". In addition, reduced throughput on the IPL System as a result of
testing, line repair, reduced operating pressures or other causes could result
in reduced throughput on the Lakehead System.
The operations of the Partnership are subject to federal and state laws and
regulations relating to environmental protection and federal and state laws and
regulations relating to operational safety. Although the General Partner
believes that the operations of the Lakehead System are in general 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. Moreover, it is
possible that other developments, such as increasingly strict environmental and
safety laws, regulations and enforcement policies thereunder, and claims for
damages to property or persons resulting from the Partnership's operations,
could result in substantial costs and liabilities to the Partnership. For a
discussion on environmental and safety regulation, see "-- Environmental and
Safety Regulation".
The interstate common carrier pipeline operations of the Partnership are
subject to rate regulation by the Federal Energy Regulatory Commission ("FERC").
For a discussion of FERC regulation and Partnership tariff rates, see "--
Regulation" and "-- Tariffs".
REGULATION
FERC Regulation
The interstate common carrier pipeline operations of the Partnership are
subject to rate regulation by the FERC under the Interstate Commerce Act. The
Interstate Commerce Act requires, among other things, that petroleum products
and crude oil pipeline rates be just, reasonable and nondiscriminatory, and
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 commission
chooses to suspend the
3
6
proposed change. A complaint, by comparison, can apply either to an existing
rate or practice or a proposed change and subjects the pipeline, in certain
circumstances, to possible retroactive liability for past rates or practices
found to be unlawful.
The Energy Policy Act of 1992 required the FERC to issue rules establishing
a simplified and generally applicable ratemaking methodology for oil pipelines
and to streamline procedures in oil pipeline proceedings. In response, the FERC
issued Orders No. 561 and No. 561-A which prescribe an indexing methodology for
setting rate ceilings beginning in 1995. Rates in effect at December 31, 1994,
if not subject to protest or complaint, became the base rates for application of
the indexing mechanism. The index selected for use is the Producer Price Index
for Finished Goods minus 1% ("PPIFG-1"). On an ongoing basis, rate ceiling
levels are adjusted each July 1, and the PPIFG-1 for use on July 1, 1996 was
approximately 0.9%. 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 that the rate is unjust and
unreasonable).
Prior to the indexing methodology, and since 1985, the propriety of crude
oil pipeline rates was generally assessed on the basis of a trended original
cost methodology (FERC Opinion No. 154-B/C). In general, under this cost-based
methodology, crude oil pipeline rates were permitted to generate operating
revenues, based on projected volumes, not greater than the total of the
following components: (i) operating expenses, (ii) depreciation and
amortization, (iii) federal and state income taxes and (iv) an overall allowed
rate of return on the pipeline's rate base.
In Orders No. 561 and No. 561-A, the FERC stated that, as a general rule,
pipelines must utilize the indexing methodology to change rates. The FERC
indicated, however, that it was retaining 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 such that rates at the ceiling level
would preclude the carrier from being able to charge a just and reasonable rate.
In addition, a pipeline can seek to charge market-based rates if it can
establish that it lacks significant market power, 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
agreement between the pipeline and at least one shipper not affiliated with the
pipeline.
In May 1996, the United States Court of Appeals for the District of
Columbia Circuit denied the petitions for review of FERC Orders No. 561 and No.
561-A filed by the Association of Oil Pipe Lines, the Canadian Association of
Petroleum Producers and others. No further legal review of these Orders is
pending.
Other Regulation
The Operating Partnership and the portion of the Lakehead System in
Michigan is, or may be, subject to the jurisdiction of the Michigan Public
Service Commission with respect to the construction and operation of the
pipeline and the issuance of the Partnership's securities in that state. The
Michigan Public Service Commission does not regulate the tariffs charged for
transportation on the Lakehead System.
International border crossing permits received from the U.S. Government
authorize the Partnership to make and maintain its pipeline crossings of the
international boundary between the United States and Canada. These permits
provide that they may be terminated or amended at the will of the U.S.
Government and that the pipelines they govern may be inspected by or subject to
orders issued by federal or state government agencies.
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.
4
7
TARIFFS
Rate Cases
In October 1996, the FERC approved an agreement (the "Settlement
Agreement") between the Partnership and customer representatives on all
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. Refunds of $41.8
million were made in the fourth quarter of 1996, with the remaining balance
($79.3 million at December 31, 1996) to be paid through a 10% reduction on
future rates. This reduction will continue until all refunds have been made,
which is expected to take approximately three years. Interest will continue to
accrue on the unpaid balance. The Settlement Agreement also provides that the
agreed tariff rates will be subject to indexing as prescribed by FERC regulation
and that the Partnership's customer representatives will not challenge any rates
within the indexed ceiling for a period of five years. Furthermore, the
Settlement Agreement provides for the terms of an incremental tariff rate
surcharge to recover the cost of, and allow a rate of return on, the
Partnership's future new line from Superior to Chicago (for additional details
about this new line, please read the information under the caption "Capital
Expenditures"). The rate of return on this new line will be based on the
utilization level of the additional capacity constructed. As per 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%, respectively.
Subsequent to the Settlement Agreement, both the Partnership and customer
representatives withdrew appeals filed with the U.S. Court of Appeals for the
District of Columbia Circuit in response to the June 1995 FERC decision (Opinion
No. 397) on the Partnership's tariff rates as well as the related May 1996 FERC
Opinion No. 397-A. In Opinion No. 397 the FERC decided: (1) as provided in FERC
Opinion No. 154-B, the Partnership's use of the trended original cost
methodology is appropriate, and the Partnership is entitled to a starting, or
transition, rate base; (2) the Partnership is not entitled to recover in cost of
service a tax allowance with respect to income attributable to individual
limited partners; and (3) the Partnership's rates in effect on October 24, 1991
were deemed by the FERC to have been subject to a complaint and are therefore
not deemed "just and reasonable" by the Energy Policy Act. However, for the
purposes of making refunds under Opinion No. 397, the Partnership is obligated
to do so only down to the level of its rates in effect immediately preceding a
May 1992 increase. In Opinion No. 397-A, which denied rehearing and clarified
Opinion No. 397, the FERC further limited the income tax allowance by denying
entitlement to any income tax allowance in connection with "curative
allocations" which cause the General Partner's proportion of taxable income to
be greater than its proportion of ownership in the Partnership.
Current Tariffs
Under published tariffs, the rates for transportation through the Lakehead
System of light crude oil from the Canadian border near Neche to principal
delivery points at December 31, 1996, were as follows:
RATE
PER BARREL
----------
Clearbrook, Minnesota....................................... $0.144
Superior, Wisconsin......................................... $0.271
Chicago, Illinois area...................................... $0.532
Canadian border near Marysville, Michigan................... $0.607
Buffalo, New York area...................................... $0.648
The rates at December 31, 1996 for medium and heavy crude oils were higher,
while those for NGL's were lower, than the rates set forth in the above table to
compensate for differences in costs for shipping different grades of liquid
hydrocarbons. In addition, effective November 1, 1996, the Partnership's
published rates are subject to a 10% reduction, which will continue until all
rate refunds and interest resulting from the Settlement Agreement have been
paid.
The Partnership finalized an agreement with Mustang Pipe Line Partners in
October 1996 to provide for a future joint tariff covering shipments of western
Canadian crude oil to the Patoka, Illinois market area south
5
8
of Chicago. The shipments will travel on the Lakehead System to Chicago, and on
to Patoka through the Mustang pipeline system. The joint tariff agreement will
provide for lower transportation costs to shippers desiring access to the Patoka
market, an incentive which the General Partner believes complements the
Partnership's future new line from Superior to Chicago. For additional details
about this new line, please read the information under the caption "-- Capital
Expenditures". Mustang Pipe Line Partners is a Delaware general partnership
owned by Mobil Illinois Pipe Line Company and a wholly-owned subsidiary of IPL
Energy (U.S.A.) Inc. ("IPL Energy USA"), an affiliated Delaware corporation
owned by IPL Energy.
DELIVERIES FROM THE LAKEHEAD SYSTEM
Deliveries from the Lakehead System are made in the Great Lakes region of
the United States and to the province of Ontario, principally to refineries,
either directly or through connecting pipelines of other companies. Major
refining centers within these regions are located near Sarnia, Nanticoke and
Toronto, Ontario; the Minneapolis-St. Paul area of Minnesota; Superior,
Wisconsin; the Chicago area of Illinois and Indiana; the pipeline hub at Patoka,
Illinois; and the Detroit, Michigan; Toledo, Ohio; and Buffalo, New York areas.
Crude oils and NGLs transported by the Lakehead System are feedstock for
refineries and petrochemical plants.
The U.S. Government segregates the United States into five districts,
Petroleum Administration for Defense Districts ("PADD"), for purposes of its
strategic planning to ensure crude oil supply to key refining areas in the event
of a national emergency. The oil industry utilizes these districts in reporting
statistics regarding oil supply and demand. The Lakehead System services the
northern tier of PADD 2, and governmental publications project that crude oil
demand in this area will remain relatively constant. In addition, such
publications project the supply of crude oil from producing areas in the U.S.
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 General Partner believes that the Lakehead System will be
able to maintain its current level of deliveries into PADD 2. Express Pipeline
Ltd. ("Express Pipeline"), a joint venture between Alberta Energy Company, Ltd.
and TransCanada PipeLines Limited, has constructed a 170,000 barrel per day
pipeline which will compete for this market. For additional details on Express
Pipeline, see "-- Competition".
The following table sets forth Lakehead System deliveries and barrel miles
for each of the years in the five-year period ended December 31, 1996.
DELIVERIES
-------------------------------------
1996 1995 1994 1993 1992
---- ---- ---- ---- ----
(THOUSANDS OF BARRELS PER DAY)
UNITED STATES
Light crude oil.......................... 309 345 335 332 333
Medium and heavy crude oil............... 569 513 452 421 401
NGL...................................... 23 18 8 4 3
----- ----- ----- ----- -----
901 876 795 757 737
----- ----- ----- ----- -----
EASTERN CANADA
Light crude oil.......................... 348 332 321 333 335
Medium and heavy crude oil............... 102 96 108 97 83
NGL...................................... 100 105 102 101 96
----- ----- ----- ----- -----
550 533 531 531 514
----- ----- ----- ----- -----
1,451 1,409 1,326 1,288 1,251
===== ===== ===== ===== =====
BARREL MILES (billions).................... 384 385 366 358 353
===== ===== ===== ===== =====
Deliveries on the Lakehead System in 1996 averaged approximately 1,451,000
barrels per day, a slight increase over 1995. Deliveries to U.S. destinations
have increased over the past five years and made up 62% of
6
9
the total volumes shipped on the Lakehead System in 1996. Deliveries to eastern
Canada have remained relatively stable since 1992.
SOURCES OF SHIPMENTS
Substantially all of the shipments delivered through the Lakehead System
originate in oil fields in the Canadian provinces of Alberta, Saskatchewan,
Manitoba and British Columbia and in the Northwest Territories of Canada. The
shipments reach the Lakehead System from the portion of the System located in
western Canada, which receives its shipments primarily through pipelines owned
and operated by others. The Lakehead System also receives U.S. and Canadian
production at Clearbrook (through a connection with Portal Pipe Line Company, an
affiliate of the General Partner), U.S. production at Stockbridge and Lewiston,
Michigan, and both U.S. and offshore production in the Chicago area.
SUPPLY AND DEMAND PROJECTIONS FOR WESTERN CANADIAN CRUDE OIL
By virtue of the integrated nature of the System, the following discussion
provides an assessment of the total supply and demand for western Canadian crude
oil. The forecast supply and demand information is based on the analysis
provided in the NEB's report "Canadian Energy Supply and Demand 1993 - 2010,
Trends and Issues" ("NEB Report"), published in December 1994. The NEB Report
focuses on broad prospective energy market developments under different
scenarios but does not set forth detailed descriptions of the analytical methods
used or the quantitative results supporting the scenarios.
Supply
The NEB Report assesses the prospects for Canadian crude oil supply under
two different assumptions about the progress of production and development
technology. The "Current Tech Case" assumes crude oil supply costs associated
with technologies that are currently in use or that have already been
extensively tested and are close to becoming commercially viable. The "High Tech
Case" assumes supply cost estimates associated with technologies that are in the
early stages of research. These estimates were based on consultation with
industry participants, the NEB's own assessment of historical trends and the
NEB's own judgement. In both the Current Tech Case and the High Tech Case, the
NEB assumed crude oil prices that rose from the 1993 average of $19 per barrel
to $23 per barrel in 2010 (in 1993 constant dollars).
The NEB also examined the impact that price sensitivity would have on crude
oil supply. They developed two scenarios that assume technologies consistent
with the Current Tech Case, but estimated supply at crude oil prices of $30 per
barrel, the "High Price Case" and supply at crude oil prices of $15 per barrel,
the "Low Price Case". The $15 to $30 window, in the NEB's view, represents a
sustainable range of crude oil prices.
The tables below set forth the NEB's projections of western Canadian
productive capacity of crude oil and equivalent under each of their four
scenarios:
PRODUCTIVE CAPACITY OF WESTERN CANADIAN CRUDE OIL AND EQUIVALENT
CURRENT TECH CASE
1995 2000 2005 2010
---- ---- ---- ----
(THOUSANDS OF BARRELS PER DAY)
Light crude oil................................... 1,290 1,140 1,020 850
Heavy crude oil................................... 810 940 780 700
----- ----- ----- -----
2,100 2,080 1,800 1,550
===== ===== ===== =====
7
10
PRODUCTIVE CAPACITY OF WESTERN CANADIAN CRUDE OIL AND EQUIVALENT
HIGH TECH CASE
1995 2000 2005 2010
---- ---- ---- ----
(THOUSANDS OF BARRELS PER DAY)
Light crude oil................................... 1,300 1,140 1,030 920
Heavy crude oil................................... 820 1,090 1,080 1,090
----- ----- ----- -----
2,120 2,230 2,110 2,010
===== ===== ===== =====
PRODUCTIVE CAPACITY OF WESTERN CANADIAN CRUDE OIL AND EQUIVALENT
CURRENT TECH AND LOW PRICE CASE
1995 2000 2005 2010
---- ---- ---- ----
(THOUSANDS OF BARRELS PER DAY)
Light crude oil................................... 1,270 1,100 870 690
Heavy crude oil................................... 720 590 320 170
----- ----- ----- -----
1,990 1,690 1,190 860
===== ===== ===== =====
PRODUCTIVE CAPACITY OF WESTERN CANADIAN CRUDE OIL AND EQUIVALENT
CURRENT TECH AND HIGH PRICE CASE
1995 2000 2005 2010
---- ---- ---- ----
(THOUSANDS OF BARRELS PER DAY)
Light crude oil................................... 1,320 1,230 1,050 1,090
Heavy crude oil................................... 840 1,150 1,250 1,340
----- ----- ----- -----
2,160 2,380 2,300 2,430
===== ===== ===== =====
The NEB states in their summary and conclusions that total Canadian crude
oil production could increase over the study period so long as world oil prices
are consistently above the mid-point of their sustainable range and/or
technological progress further reduces supply costs. Any expansion in oil supply
is likely to feature increases in heavy oil production, in bitumen production
from the oil sands and light oil production from the frontiers. Light oil
production from western Canada is expected to gradually decline over the study
period. The state of resource depletion in western Canada suggests that supply
of western Canadian conventional crude oil, particularly light crude oil, is
unlikely to be sustained in the long run even under conditions of rapid
technological progress. However, horizontal drilling and other new technologies
may lead to a continued gradual increase in production in the near term and
could delay the decline by several years.
The NEB further summarizes their analysis by stating that the size and
composition of Canadian crude oil supply is very sensitive to oil prices between
$15 and $26. In a world in which oil prices track at the bottom of the
sustainable range, total Canadian crude oil supply declines quite rapidly as no
new supply sources are economically viable. In contrast, all sources are viable
above $26. Canada should remain a net exporter of crude oil when oil prices are
sustained at or above the mid-range level. At lower prices Canadian production
declines sufficiently rapidly that Canada becomes a net importer toward the end
of their forecast term.
Demand
Refineries in Canada generally use light crude oil to manufacture petroleum
products, while the bulk of western Canadian heavy crude oil production is
exported. Because of this, the NEB separately determined supply and demand
balances for light and heavy crude oil. The NEB Report only developed demand
scenarios
8
11
for western Canadian crude oil for the Current Tech Case and the High Tech Case,
which are summarized in the following tables:
DISPOSITION OF WESTERN CANADIAN CRUDE OIL AND EQUIVALENT
CURRENT TECH CASE
1995 2000 2005 2010
---- ---- ---- ----
(THOUSANDS OF BARRELS PER DAY)
LIGHT CRUDE OIL
Western Canada.................................. 430 430 430 430
Eastern Canada.................................. 390 470 470 330
United States................................... 560 330 210 190
----- ----- ----- -----
1,380 1,230 1,110 950
----- ----- ----- -----
HEAVY CRUDE OIL
Western Canada.................................. 40 50 50 50
Eastern Canada.................................. 90 90 100 100
United States................................... 590 710 540 450
----- ----- ----- -----
720 850 690 600
----- ----- ----- -----
2,100 2,080 1,800 1,550
===== ===== ===== =====
DISPOSITION OF WESTERN CANADIAN CRUDE OIL AND EQUIVALENT
HIGH TECH CASE
1995 2000 2005 2010
---- ---- ---- ----
(THOUSANDS OF BARRELS PER DAY)
LIGHT CRUDE OIL
Western Canada.................................. 430 430 430 430
Eastern Canada.................................. 380 430 470 470
United States................................... 590 370 270 190
----- ----- ----- -----
1,400 1,230 1,170 1,090
----- ----- ----- -----
HEAVY CRUDE OIL
Western Canada.................................. 40 50 50 50
Eastern Canada.................................. 80 90 100 100
United States................................... 600 860 790 770
----- ----- ----- -----
720 1,000 940 920
----- ----- ----- -----
2,120 2,230 2,110 2,010
===== ===== ===== =====
The NEB assumed that western Canadian crude oil will be used first to
satisfy refinery demand in western Canada and then to maintain a minimum level
of exports to U.S. markets. The NEB assumed that market forces will result in a
sustained level of light crude oil deliveries to U.S. markets of approximately
190,000 barrels per day. Their assumption reflects the expectation that crude
oil currently moving to the U.S. on the Rangeland and Milk River pipeline
systems will likely continue, and other U.S. refiners that are partially
dependent on Canadian supply will continue to purchase western Canadian crude
oil. Remaining volumes of western Canadian light crude oil would then be
available to satisfy the needs of Quebec and Ontario.
As has been the case for many years, the available supply of western
Canadian heavy crude oil will continue to exceed Canadian requirements. This
trend is expected to continue until the end of the NEB's plan period. The NEB
assumed it very unlikely that Canadian refineries will significantly increase
their use of heavy crude oil, unless the light/heavy crude oil price
differentials widen sufficiently to justify large capital expenditures
associated with the construction of the necessary processing facilities.
9
12
Current Tech Case light/heavy price differentials are expected to increase
only marginally through the forecast period. At these differentials, U.S.
refiners can expand existing heavy crude oil upgrading facilities at a marginal
cost below that which would be required by Canadian refiners. In the High Tech
Case, differentials are projected to widen substantially, providing additional
incentive for U.S. refiners to expand conversion facilities. The High Tech Case
accounts for some upgrading in Alberta later in the plan period, when price
differentials between light and heavy crude oil are assumed to widen
significantly as a consequence of the growing production of bitumen. Investments
in such upgrading projects remain highly speculative, and may result in
alternate markets being required to absorb the incremental supply.
The NEB based their projection of the U.S. market for Canadian heavy crude
oil on a number of considerations. No major changes in U.S. product demand are
expected in the northern tier area of PADD 2 served by Canadian heavy crude oil.
U.S. domestic production currently supplying refineries in this area is
declining, providing an opportunity for Canadian heavy crude oil to capture
additional market share. U.S. refiners in this area began an upgrading program
some years ago, and therefore, incremental refinery conversion capacity is much
less costly than in Canada.
The NEB concludes that Canadian heavy crude oil could well play an
increasing role in meeting the U.S. demand for feedstocks over the projection
period. Additionally, to the extent that upgrading projects in western Canada do
not materialize in the post-2000 period, there will be greater reliance on this
market to accommodate the growth in western Canadian crude oil production.
Assuming no installation of conversion capacity in eastern Canadian refineries,
the likely alternative market outlet would be the Wood River/Patoka, Illinois
hub area near St. Louis, Missouri. The NEB's High Tech Case assumes that western
Canadian heavy crude oil penetrates this area, although it is recognized that
this is a highly competitive market, and subject to pressures from offshore
imports.
The NEB Report indicates that the NEB's analysis is not intended to provide
a forecast but rather to give a broad assessment of the implications of possible
variations in key underlying variables, such as world oil prices, for long-term
trends in Canadian oil production. The NEB Report specifically disclaims any
attempt to assess year-to-year fluctuations in the demand for and supply of
energy or in energy prices. The NEB Report does not speculate on the future
course of government policies, including energy and environmental policies, but
rather analyzes plausible trends in energy market variables within the currently
existing policy framework.
Eastern Canadian demand for western Canadian crude oil could be impacted by
the reversal of a portion of the IPL System located in Ontario and Quebec. For
additional details on this reversal, see "-- Competition".
CUSTOMERS
The Lakehead System conducts operations without the benefit of exclusive
franchises from government entities or long-term contractual arrangements with
shippers. During 1996, 44 shippers tendered crude oil and other liquid
hydrocarbons 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 1996 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 22%, 13% and 12%, respectively, of total operating revenue
generated by the Lakehead System during 1996. The remaining shippers each
accounted for less than 10% of such revenue.
CAPITAL EXPENDITURES
In 1996, the Partnership made capital expenditures of $76.7 million, of
which $59.0 million was for the 1996 expansion program which consisted primarily
of several new pump stations on Line 6 from Superior to Chicago and a new tank
at Clearbrook. The 1996 expansion has increased delivery capacity into Chicago
area markets by up to 120,000 barrels per day. Approximately 40,000 barrels per
day of this added capacity will be required to offset the effects of moving
increased volumes of heavy crude oil, which can lower system delivery
capability. Of the remaining capital expenditures, $5.9 million was spent for
core maintenance capital
10
13
expenditures and $11.8 million for other enhancements to the Lakehead System,
which includes $7.1 million for an additional expansion in response to the
increased Midwest U.S. demand for cost effective and timely access to western
Canadian production. The Partnership and Interprovincial have begun working on
this additional expansion, which is expected to increase delivery capacity to
this important market by approximately 170,000 barrels per day. On the Lakehead
System, this expansion will consist primarily of a new 450-mile 24 inch pipeline
from Superior to Chicago at an approximate cost of $300 million. Right-of-way
and environmental permitting work began in 1996 and will continue in 1997. The
General Partner believes that the majority of the expenditures for pipeline
construction will be incurred in 1998, with completion planned for the second
half of that same year.
The Partnership's recurring capital program to maintain and enhance the
service capability of the Lakehead System, excluding the new pipeline from
Superior to Chicago, will require future expenditures which are estimated to be
up to approximately $30 million annually. Excluding the new pipeline, capital
expenditures in 1997 are expected to total approximately $40 million.
TAXATION
For federal and state income tax purposes, the Partnership and Operating
Partnership are not taxable entities. Federal and state income taxes on
Partnership taxable income are borne by the individual partners through the
allocation of Partnership taxable income. Such taxable income may vary
substantially from net income reported in the statement of income.
COMPETITION
Because pipelines are generally the lowest cost method for intermediate and
long haul overland movement of crude oil, the System's most significant existing
competitors (other than indigenous consumption in western Canada) are other
pipelines. Of the pipelines transporting western Canadian crude oil out of
Canada (including Express Pipeline discussed below), the System provides
approximately 75% of the total pipeline design capacity. Competition among
common carrier pipelines is based primarily on transportation charges, access to
producing areas and proximity to end users. Interprovincial and the General
Partner believe that high capital requirements, environmental considerations and
problems in acquiring rights of way and related permits make it unlikely that a
competing pipeline system comparable in size and scope to the System will be
built in the foreseeable future. However, the System is experiencing a
competitive challenge for crude oil deliveries to the U.S. Midwest market by
Express Pipeline. Express Pipeline has constructed a 170,000 barrel per day
pipeline to carry western Canadian crude oil to the Wood River, Illinois market
as well as the U.S. Rocky Mountain region. This pipeline is expected to be in
service in 1997. Interprovincial and the General Partner believe, however, that
the IPL/Lakehead System (including the future new line from Superior to Chicago)
will be more attractive to western Canadian producers shipping to the Chicago or
Patoka/Wood River based markets as it offers lower tolls, shorter transit times
and no shipper volume commitments.
The System encounters competition in serving shippers to the extent that
shippers have alternate opportunities for transporting liquid hydrocarbons from
their sources to customers. As U.S. domestic production declines in markets
which are currently served by other pipelines from the western Canadian supply
basin, Canadian crude oil may be drawn to those markets to meet shortfalls.
Generally, it is expected that producers will receive the highest netback price
from markets served by the System, but alternate markets may for periods of time
offer equal or better returns for the producer. These could potentially be the
U.S. Rocky Mountain region for sweet crude oil and the Washington state market
for light sour crude oil.
The General Partner estimates that the System transported approximately 70%
of total western Canadian crude oil production to markets in the United States
and eastern Canada in 1996, of which approximately 90% was transported by the
Lakehead System. The remainder was refined in Alberta or transported through
other pipelines to British Columbia and the states of Washington and Montana.
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
11
14
centers of Minneapolis-St. Paul, Chicago, Detroit and Toledo. The Lakehead
System transports approximately 45% of all crude oil deliveries into the Chicago
area, 75% of all crude oil deliveries into the Minneapolis-St. Paul area, and
virtually all deliveries of crude oil to Ontario, Canada. The Minneapolis-St.
Paul refineries are serviced by three crude oil pipelines which compete with the
Lakehead System. The Wood River Pipeline delivers imported and domestic crude
oil from the south. The Minnesota Pipeline, in addition to moving Canadian crude
oil, delivers North Dakota production received from the Portal Pipeline (an
affiliate of the General Partner). The Williams Pipeline delivers crude oil and
refined products from the Midcontinent. The Chicago area is served by both
common carrier and proprietary pipelines. The Chicap/Capline system and the Arco
/Seaway Pipeline are both common carriers which deliver domestic and imported
crude oil to the Chicago market. Chicago is also served by proprietary pipelines
operated by affiliates of Amoco. The Detroit and Toledo markets are serviced by
the Mid-Valley Pipeline and other pipelines which connect to the Capline system.
The Patoka/Wood River market area receives crude oil flows originating from the
U.S. Gulf Coast from the Capline and Seaway pipelines. At Cushing, Oklahoma, the
Seaway pipeline can feed into the Ozark pipeline for delivery to the Patoka/Wood
River area. Domestic U.S. supplies can reach the Patoka/Wood River area by these
lines as well. As previously stated, it is expected that the Express Pipeline
will begin deliveries of western Canadian crude to this area in 1997. The
Lakehead System also competes with the Cochin Pipeline for the transportation of
natural gas liquids produced in western Canada.
The IPL System includes a section which extends from Sarnia, Ontario to
Montreal, Quebec (the "Montreal Extension"). The portion of the Montreal
Extension from Sarnia to North Westover, Ontario is currently in west to east
service. The section from North Westover to Montreal has been purged with
nitrogen and remains available for service. Interprovincial is investigating
economic alternatives for the Montreal Extension. A detailed evaluation has
shown the most efficient use to be reversal of the direction of flow over the
entire length of the Montreal Extension to bring offshore oil to Ontario
refineries. While a reversal of the Montreal Extension could result in
Interprovincial or a subsidiary of Interprovincial becoming a competitor for
supplying crude oil to the Ontario market, such a reversal is expressly
permitted by the agreements entered into at the time of formation of the
Partnership. A reversal of the Montreal Extension is not anticipated to have a
material adverse impact on the Partnership, as displaced volumes are expected to
be redirected to existing U.S. markets served by the Partnership.
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 General Partner believes that the operations of the Lakehead System
are in general 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 such liabilities will not be
incurred. To the extent that the Partnership is unable to recover environmental
costs in its rates or through insurance, the General Partner has agreed to
indemnify the Partnership from and against any costs relating to environmental
liabilities associated with the Lakehead System prior to its transfer to the
Partnership in 1991. This excludes any liabilities resulting from a change in
laws after such transfer. If the Partnership is held to be responsible for
liabilities not covered by the General Partner's indemnification obligation,
such liabilities could have an adverse impact on the financial condition of the
Partnership and the Partnership's ability to make distributions.
Air
The operations of the Partnership are subject to the federal Clean Air Act
and comparable state statutes. The General Partner believes that the operations
of the Lakehead System are in substantial compliance with such statutes in all
states in which it operates.
12
15
Water
The federal Water Pollution Control Act, as amended by the Oil Pollution
Act of 1990 ("WPCA"), imposes strict controls against 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.
The operations of the Partnership are subject to state and federal
regulations concerning the discharge of water associated with pipeline system
operations or testing, or of stormwater run-off from facilities. The General
Partner believes that the operations of the Lakehead System are in substantial
compliance with such regulations in all states in which it operates.
Remediation Matters
Contamination resulting from spills of crude oil and petroleum products is
not unusual within the petroleum pipeline industry. The Lakehead System has, in
the past, experienced such spills. Historic spills along the Lakehead System as
a result of past operations may have resulted in soil or groundwater
contamination for which further remediation may be required. The General Partner
does not expect that any cleanup liabilities not covered by the General
Partner's indemnification obligation will have a material adverse effect on the
financial condition of the Partnership.
Superfund
The Comprehensive Environmental Response, Compensation and Liability Act of
1989, as amended ("CERCLA"), 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. These persons include the owner or
operator of a site and companies that disposed, or arranged for the disposal of,
the hazardous substances found at a site. Such statutes also authorize
government environmental authorities such as the Environmental Protection Agency
("EPA") and, in some instances, third parties to take actions in response to
threats to the public health or the environment and to seek to recover from the
responsible classes of persons the costs incurred. 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 disposed of at sites that may require cleanup under Superfund and
related state statutes.
Uncertainty remains under current law as to whether certain petroleum
contaminated wastes constitute hazardous substances for the purposes of CERCLA
and comparable state laws. This uncertainty may, in the future, be resolved by a
conclusive judicial or administrative determination that such wastes are
considered hazardous substances. To the extent that such resolution would be
considered to constitute a change in the law, the General Partner's
indemnification obligations to the Partnership would not cover remedial
liability that may, in the future, be asserted relating to the historical
disposal of such waste generated by operation of the Lakehead System. The
remedial liability associated with such waste may be material, although the
General Partner believes that the Partnership would not be adversely impacted to
a greater extent than its competitors.
13
16
Waste
The Partnership generates hazardous and nonhazardous solid wastes that are
subject to requirements of the federal Resource Conservation and Recovery Act
("RCRA") and comparable state statutes. The Partnership reports, as required, to
environmental regulatory agencies regarding the disposal of such wastes. The EPA
is currently in the process of developing stricter disposal standards for
nonhazardous waste. Further, it is possible that some wastes that are currently
classified as nonhazardous, possibly including wastes generated during pipeline
operations, may, in the future, be designated as "hazardous waste", which is
subject to more costly disposal requirements.
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.
This legislation 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. Recent regulations have also been
issued requiring pipeline operators to implement alcohol testing programs, to
supplement already established drug testing programs previously required by
regulation, for employees and contractors that are engaged in safety-sensitive
activities. Additional legislation or regulations have been proposed requiring
remotely controlled shutoff valves in populated or environmentally sensitive
areas, increased public education of pipeline safety and accident prevention and
periodic integrity testing of pipelines by internal inspection or hydrostatic
testing. The Partnership currently has an integrity testing program utilizing
internal inspection devices and has conducted additional hydrostatic testing for
selected segments of the Lakehead System. Facilities have been constructed and
permits obtained to treat and dispose of hydrostatic test water generated.
The Partnership is also subject to the requirements of federal and state
Occupational Safety and Health Acts ("OSHA"). The General Partner believes that
the operations of the Lakehead System are in substantial compliance with such
statutes in all states in which it operates.
In general, the General Partner expects to incur future ongoing
expenditures to comply with industry and regulatory safety standards. Such
expenditures cannot be accurately estimated at this time, although the General
Partner does not expect that they will have a material adverse effect on the
Partnership.
EMPLOYEES
Neither the General Partner nor the Partnership has any employees. On
January 1, 1996, the General Partner transferred its employees to IPL Energy
USA. As the General Partner is responsible for management and operation of the
Partnership, it has entered into a services agreement with IPL Energy USA to
provide the required services. The General Partner also receives, for the
benefit of the Partnership, certain administrative, engineering, treasury and
computer services from Interprovincial and IPL Energy. The Partnership
reimburses the General Partner or its affiliates for expenses incurred in
performing these services.
ITEM 3. LEGAL PROCEEDINGS
In response to the Settlement Agreement, both the Partnership and customer
representatives withdrew appeals filed with the U.S. Court of Appeals for the
District of Columbia Circuit in response to the June 1995 FERC decision (Opinion
No. 397) on the Partnership's tariff rates as well as the related May 1996 FERC
Opinion No. 397-A.
The Partnership is, and the General Partner prior to the formation of the
Partnership has been, in the ordinary course of business, a defendant in various
lawsuits and a party to various legal proceedings, some of which are covered, in
whole or in part, by insurance. Certain of these claims were assumed by the
Partnership in connection with the Partnership's formation. The Partnership
believes that the outcome of all such lawsuits
14
17
and other 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 or to any liabilities relating to a change in laws after December 27,
1991.
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 1996.
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
The Preference units of the Registrant are listed and traded on the New
York Stock Exchange, the principal market for the Partnership's Preference
units, under the symbol LHP. The quarterly price range per Preference unit and
cash distributions paid per unit for 1996 and 1995 are summarized below:
FIRST SECOND THIRD FOURTH
1996 QUARTERS ----- ------ ----- ------
High........................................................ $ 29 $ 28 1/8 $ 31 1/8 $ 34 7/8
Low......................................................... $ 25 1/2 $ 21 5/8 $ 25 1/4 $ 30 3/8
Cash distributions paid..................................... $0.64 $0.64 $0.64 $0.68
1995 QUARTERS
High........................................................ $ 29 1/4 $ 30 5/8 $ 27 1/4 $ 27 1/2
Low......................................................... $ 26 3/8 $ 22 $ 25 $ 24
Cash distributions paid..................................... $0.64 $0.64 $0.64 $0.64
At February 3, 1997, there were approximately 35,000 Preference Unitholders
of which there were 3,610 registered Preference Unitholders of record. There is
no established public trading market for the Registrant's Common units, all of
which are held by the General Partner.
15
18
ITEM 6. SELECTED FINANCIAL DATA
The following table sets forth, for the periods and at the dates indicated,
summary historical financial and operating data for the Partnership. The table
is derived from the consolidated financial statements of the Partnership and
notes thereto, and should be read in conjunction with those audited financial
statements.
YEAR ENDED DECEMBER 31,
-------------------------------------------------
1996(1) 1995(1) 1994 1993 1992
------- ------- ---- ---- ----
(DOLLARS IN MILLIONS, EXCEPT PER UNIT AMOUNTS)
INCOME STATEMENT DATA:
Operating revenue.............................. $274.5 $268.5 $246.0 $240.1 $222.2
Operating expenses(2).......................... 187.1 195.2 159.7 159.6 148.7
------ ------ ------ ------ ------
Operating income............................... 87.4 73.3 86.3 80.5 73.5
Other income................................... 9.6 7.1 4.1 3.1 3.5
Interest expense............................... (43.9) (40.3) (29.8) (30.9) (29.4)
Minority interest.............................. (0.7) (0.5) (0.7) (0.7) (0.6)
------ ------ ------ ------ ------
Net income..................................... $ 52.4 $ 39.6 $ 59.9 $ 52.0 $ 47.0
====== ====== ====== ====== ======
Net income per unit(3)......................... $ 2.11 $ 1.60 $ 2.61 $ 2.36 $ 2.13
====== ====== ====== ====== ======
Cash distributions paid per unit............... $ 2.60 $ 2.56 $ 2.51 $ 2.36 $ 1.80(4)
====== ====== ====== ====== ======
FINANCIAL POSITION DATA
(AT YEAR END):
Property, plant and equipment, net............. $763.5 $725.1 $727.6 $622.1 $615.7
Total assets................................... $975.9 $915.2 $868.6 $758.8 $722.3
Long-term debt................................. $463.0 $395.0 $364.0 $344.0 $320.0
Partners' capital
General Partner............................. $ 1.6 $ 1.5 $ 1.6 $ 0.7 $ 0.5
Common Unitholder........................... 21.7 21.7 23.5 11.8 9.7
Preference Unitholders...................... 376.3 387.9 409.3 354.4 356.7
------ ------ ------ ------ ------
$399.6 $411.1 $434.4 $366.9 $366.9
====== ====== ====== ====== ======
CASH FLOW DATA:
Cash provided from operating activities........ $ 93.9 $121.5 $108.1 $ 92.5 $ 68.5
Capital expenditures........................... $ 76.7 $ 35.5 $136.9 $ 35.6 $ 32.6
OPERATING DATA:
Barrel miles (billions)........................ 384 385 366 358 353
Deliveries
(thousands of barrels per day)
United States............................... 901 876 795 757 737
Eastern Canada.............................. 550 533 531 531 514
------ ------ ------ ------ ------
1,451 1,409 1,326 1,288 1,251
====== ====== ====== ====== ======
- -------------------------
(1) 1996 results reflect the impact of the 1996 agreement between the
Partnership and customer representatives on all outstanding contested tariff
rates. 1995 results reflect the impact of the June 1995 FERC decision.
(2) Operating expenses include provisions for prior years' rate refunds of $20.1
million and $22.9 million in 1996 and 1995, respectively.
(3) The General Partner's allocation of net income has been deducted before
calculating net income per unit.
(4) Distributions paid in 1992 consist of $0.03 per unit with respect to the
period from December 27, 1991 (the Partnership's inception) through December
31, 1991 and $0.59 per unit with respect to each of the first three quarters
of 1992.
16
19
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
In October 1996, the FERC approved the Settlement Agreement between the
Partnership and customer representatives on all outstanding contested tariff
rates. The 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. Refunds of $41.8 million were made in the fourth quarter of
1996, with the remaining balance ($79.3 million at December 31, 1996) to be paid
through a 10% reduction on future rates. This reduction will continue until all
refunds have been made, which is expected to take approximately three years.
Interest will continue to accrue on the unpaid balance. The Settlement Agreement
also provides that the agreed tariff rates will be subject to indexing as
prescribed by FERC regulations and that the Partnership's customer
representatives will not challenge any rates within the indexed ceiling for a
period of five years.
On October 16, 1996, the Board of Directors of the General Partner
increased the quarterly cash distribution to $0.68 per unit ($2.72 per unit on
an annualized basis) from $0.64 per unit. This increase, the second since the
Partnership's inception, is the result of continued earnings growth and the
removal of the uncertainty relating to the Partnership's tariff rates.
RESULTS OF OPERATIONS
The Partnership continued its strong operational performance in 1996 as
deliveries averaged a record 1,451,000 barrels per day, up 3% from the 1,409,000
barrels averaged in 1995. System utilization, measured in barrel miles, remained
relatively unchanged from last year, reflecting a higher proportion of shorter
haul deliveries to the significant Midwest markets served by the Partnership.
Deliveries and barrel miles during 1995 were up 6% and 5%, respectively, over
1994 as a result of the Partnership's 1994 expansion.
Net income for 1996 was $52.4 million ($2.11 per unit) compared with $39.6
million ($1.60 per unit) in 1995 and $59.9 million ($2.61 per unit) in 1994. Net
income is impacted in all years by the rate refunds and related interest
recorded in response to various tariff rate regulatory developments. In order to
eliminate the retroactive aspects of these developments and to facilitate
comparison, operating results have been recalculated as shown below. This
information includes the impact of the Settlement Agreement on the years
presented and excludes any amounts related to prior years.
Recalculated Operating Results
1996 1995 1994
---- ---- ----
(DOLLARS IN MILLIONS, EXCEPT PER UNIT
AMOUNTS)
Operating Revenue................................ $ 274.5 $ 268.5 $ 237.0
Operating Expenses............................... (167.0) (172.3) (159.7)
Interest Income.................................. 9.6 7.1 4.1
Interest Expense................................. (40.7) (38.8) (30.9)
Minority Interest................................ (0.9) (0.7) (0.6)
------- ------- -------
Net Income....................................... $ 75.5 $ 63.8 $ 49.9
======= ======= =======
Net Income Per Unit.............................. $ 3.06 $ 2.60 $ 2.17
======= ======= =======
Recalculated net income for 1996 was $11.7 million, or $0.46 per unit,
higher than in 1995. A combination of higher operating revenue, lower total
operating expenses and greater interest income, partially offset by higher
interest expense, led to the increase. Recalculated net income for 1995 reflects
the positive impact of the Partnership's 1994 expansion program and was $13.9
million, or $0.43 per unit, greater than 1994. This expansion resulted in higher
1995 operating revenue which was partially offset by increased operating and
interest expense.
Recalculated operating revenue is computed at the tariff rates implied in
the Settlement Agreement. These implied rates include an approximate 5% increase
on November 30, 1994, allowed to reflect the additional costs associated with
the 1994 expansion, and an approximate 0.9% increase on July 1, 1996 allowed
17
20
under the FERC's indexing methodology. Operating revenue for 1996 was $6.0
million higher than 1995 primarily due to a greater proportion of heavy crude
oil deliveries (up 29% to 471,000 barrels per day) and the 1996 tariff rate
increase. The tariff rate for heavier crude oil is greater than that for lighter
crude oils primarily due to its higher viscosity which requires more power to
pump. The Partnership's current tariff rate for heavy crude oil deliveries to
the Chicago area is approximately 10% to 18% higher than that for lighter crude
oils. Operating revenue for 1995 was 13% above the previous year's recalculated
amount of $237.0 million. This increase was due to both the transportation of
greater volumes and the November 1994 tariff rate increase.
Total 1996 recalculated operating expenses were $5.3 million less than in
1995 primarily due to lower power costs ($2.2 million) and oil losses ($2.8
million). Efficiencies gained from the Partnership's ongoing power cost
management initiative, partially offset by the transportation of greater amounts
of heavy crude oil, led to the decrease in power costs. Oil losses are impacted
by operational considerations, including changing customer delivery
requirements, and the volatility of crude oil prices, resulting in variances in
the level of oil losses from year to year. Despite growth in property, plant and
equipment, 1996 depreciation expense increased only slightly over 1995 due to
the impact of new depreciation rates, effective July 1, 1996, which better
represent the service life of the pipeline system. This change in depreciation
rates, approved by the FERC, resulted in 1996 depreciation expense being
approximately $1.8 million lower than it would have been utilizing the prior
rates. Total 1995 recalculated operating expenses were $12.6 million greater
than in 1994 primarily due to a combination of additional ongoing costs
resulting from the 1994 expansion program (depreciation and property taxes --
$9.6 million) and lower overhead costs capitalized ($5.6 million), partially
offset by lower oil losses ($2.4 million) and maintenance costs ($2.3 million).
Overhead costs capitalized were more in 1994 as a higher proportion of employee
time was spent on capital projects (as opposed to maintenance and repair
projects) due to the 1994 capacity expansion. Efficiencies implemented with the
1994 expansion, as well as management initiatives, contributed to oil losses
being less than in 1994. A reduction in periodic pipeline inspection costs led
to lower maintenance costs in 1995.
Interest income in 1996 increased over 1995 due to higher average
investment balances. Interest income in 1995 was greater than in 1994 due to
both higher average interest rates and investment balances.
Recalculated interest expense for 1996 was $1.9 million greater than in
1995 primarily due to the impact of additional borrowings under the
Partnership's credit facility to finance enhancement capital expenditures. 1995
recalculated interest expense increased $7.9 million over the previous year
primarily due to the impact of higher average balances and interest rates with
respect to accrued rate refunds ($2.8 million) and borrowings under the credit
facility ($2.3 million). In addition, interest capitalized in 1995 was $2.8
million lower than in 1994. Larger capital projects, primarily the 1994
expansion program, allowed more interest to be capitalized in 1994.
LIQUIDITY AND CAPITAL RESOURCES
At December 31, 1996, cash, cash equivalents and short-term investments
totaled $173.3 million, up $20.6 million since December 31, 1995, as cash
generated from operating activities and borrowings exceeded cash required for
distributions, capital expenditures and rate refunds. Of this $173.3 million,
$17.0 million ($0.68 per unit) was set aside for the cash distribution paid on
February 14, 1997, with the remaining $156.3 million available for capital
expenditures, distributions or other business needs.
Cash generated from operating activities in 1996 decreased $27.6 million
from 1995 primarily due to the repayment of rate refunds and related interest,
partially offset by higher net income. Cash generated from operating activities
in 1995 was $13.4 million over 1994 as higher cash flow from income before
non-cash deductions for depreciation and accrued rate refunds was partially
offset by greater working capital requirements. Timing differences in the
collection of accounts receivable and payment of accrued obligations led to the
year-to-year changes in working capital requirements.
In 1996, the Partnership made capital expenditures of $76.7 million, of
which $59.0 million was for the 1996 expansion program. The 1996 expansion
consisted primarily of several new pump stations on Line 6 from Superior to
Chicago and a new tank at Clearbrook, and increased delivery capacity into
Chicago area markets by up to 120,000 barrels per day. Approximately 40,000
barrels per day of this added capacity will be required
18
21
to offset the effects of moving increased volumes of heavy crude oil, which can
lower system delivery capability. Of the remaining capital expenditures, $5.9
million (1995 -- $7.6 million; 1994 -- $14.5 million) was spent for core
maintenance capital expenditures and $11.8 million (1995 -- $27.9 million; 1994
- --$122.4 million) for other enhancements.
Distributions paid to partners increased $1.0 million to $63.9 million
($2.60 per unit) in 1996. The $0.04 per unit quarterly distribution increase
first paid in November 1996 accounted for the increase. 1995 distributions
increased $5.7 million over 1994 to $62.9 million ($2.56 per unit). The full
year effect of distributions paid on the additional 2.2 million Preference units
issued in September 1994 primarily accounted for this increase. In February
1997, the Partnership paid a $0.68 per unit distribution related to the fourth
quarter of 1996. This was the last distribution subject to certain preferential
rights of the Preference Unitholders and certain support obligations of the
General Partner. With respect to subsequent cash distributions, the Preference
and Common units will be treated as one class of units. For additional details,
please read Note 3 to the Partnership's Consolidated Financial Statements.
The Partnership borrowed $68.0 million under its $205.0 million revolving
credit facility in 1996, primarily to finance the 1996 expansion in accordance
with an appropriate regulatory capital structure. This brings total borrowings
under the facility to $153.0 million at December 31, 1996. For additional
details relating to the revolving credit facility, please read Note 5 to the
Partnership's Consolidated Financial Statements.
The General Partner believes that the Partnership will continue to have
adequate liquidity to fund future recurring operating, investing and financing
activities. Cash distributions and certain recurring capital expenditure
programs are expected to be funded with internally-generated cash. Significant
enhancement capital expenditures are expected to be funded with
internally-generated cash, borrowings or the proceeds from additional equity
offerings.
FUTURE PROSPECTS
Income and cash flows are sensitive to oil industry supply and demand in
both Canada and the United States, as well as the regulatory environment. As the
Lakehead System is operationally integrated with the IPL System, the
Partnership's revenues are dependent upon the utilization of the IPL System by
producers of western Canadian crude oil. Interprovincial and the General Partner
believe demand for the System will continue in light of industry's increasing
production forecasts for western Canadian crude oil.
The Partnership intends to maintain and enhance the service capability of
the Lakehead System. This will require future capital expenditures which are
estimated to be up to $30 million on a recurring annual basis. In addition, in
response to the increased Midwest U.S. demand for cost effective and timely
access to western Canadian production, the Partnership and Interprovincial have
begun working on an additional expansion which is expected to increase delivery
capacity to this important market by approximately 170,000 barrels per day. On
the Lakehead System, this expansion will consist primarily of a new 450-mile 24
inch pipeline from Superior to Chicago at an approximate cost of $300 million.
Right-of-way and environmental permitting work began in 1996 and will continue
in 1997. The General Partner believes that the majority of the expenditures for
pipeline construction will be incurred in 1998, with completion planned for the
second half of that same year. The Partnership plans on financing this expansion
with existing cash balances, borrowings and proceeds from the issuance of
additional Partnership units.
The Partnership's 1996 expansion is not expected to significantly impact
net income at this time. However, the General Partner believes that it adds the
long-term flexibility necessary to meet emerging supply and transportation
trends in North America and complements the Partnership's future new pipeline
from Superior to Chicago. The General Partner believes that these combined
expansions will position the Partnership to realize increased cash flows which
will enhance the Partnership's future distribution capability.
The Partnership finalized an agreement with Mustang Pipe Line Partners in
October 1996 to provide for a future joint tariff covering shipments of western
Canadian crude oil to the Patoka, Illinois market area south of Chicago. These
shipments will travel on the Partnership's system to Chicago, and on to Patoka
through the
19
22
Mustang pipeline system. The joint tariff agreement will provide for lower
transportation costs to shippers desiring access to the Patoka market, an
incentive which the General Partner believes complements the Partnership's
future new pipeline from Superior to Chicago. Mustang Pipe Line Partners is a
Delaware general partnership owned by Mobil Illinois Pipe Line Company and a
wholly-owned subsidiary of IPL Energy USA.
BP Exploration & Oil Inc. has announced a proposal to convert 110,000
barrels per day of light crude oil processing capacity to medium/heavy crude oil
capacity at its Toledo, Ohio refinery. In conjunction with this, IPL Energy has
proposed construction of a 75-mile 16 inch pipeline which would connect the
Partnership's system near Stockbridge, Michigan to BP's Toledo refinery. The
General Partner believes these proposals also complement the future line from
Superior to Chicago as they offer another market for western Canadian producers
of medium and heavy crude oil. Various approvals and agreements are required
before these proposals can proceed.
The Partnership and Interprovincial are committed to remaining the primary
transporter of western Canadian crude oil to the U.S. Midwest and eastern
Canada. As such, and in light of potential further demand for capacity, the
Partnership and Interprovincial have entered into preliminary discussions with
shippers to provide for additional expansions beyond the new pipeline from
Superior to Chicago.
The Partnership is subject to a rate regulatory methodology which
prescribes rate ceilings adjusted every 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 does not anticipate that
PPIFG-1 will change significantly enough (July 1, 1996 = 0.9%) to have a
material effect on 1997 operating revenue. The General Partner also believes
that the 1997 impact of inflation on the Partnership's overall operating
expenses will be mitigated by ongoing cost-control initiatives.
The Settlement Agreement will benefit the Partnership by restoring
stability and providing predictable tariff rates as customer representatives
have agreed not to challenge any rates within the indexed ceiling for a period
of five years. In addition, the Partnership and customer representatives agreed
to the terms of an incremental tariff rate surcharge to recover the cost of, and
allow a rate of return on, the new line from Superior to Chicago. The rate of
return on this new line will be based on the utilization level of the additional
capacity constructed.
The Partnership is also subject to the risks of environmental costs and
liabilities inherent in pipeline operations. To the extent that the Partnership
is unable to recover environmental costs in its rates or through insurance, the
General Partner has agreed to indemnify the Partnership from and against any
costs relating to environmental liabilities associated with the Lakehead System
prior to its transfer to the Partnership in 1991. This indemnity excludes any
liabilities resulting from a change in laws after such transfer.
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-11 of this Report. Reference should be made to the Index to
Financial Statements, Supplementary Information and Financial Statement
Schedules on page F-1 of this Report.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
None.
20
23
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
(a) Directors and Executive Officers
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. As the sole stockholder of the
General Partner, Interprovincial 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..................... 59 Chairman and Director
P. D. Daniel....................... 50 President and Director
R. C. Sandahl...................... 46 Vice President and Director
F. W. Fitzpatrick.................. 64 Director
B. F. MacNeill..................... 57 Director
C. A. Russell...................... 63 Director
D. P. Truswell..................... 53 Director
J. R. Bird......................... 47 Treasurer
S. Q. DeVinck...................... 37 Chief Accountant
P. W. Norgren...................... 43 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 has served as President and a Director of the General Partner
since July 1996. Mr. Daniel has served as President and Chief Executive Officer
of Interprovincial since August 1996 and President and Chief Operating Officer
of Interprovincial from May 1994 to August 1996. He has also served as Senior
Vice President of IPL Energy since May 1994. Prior thereto, he served as Vice
President, Planning of IPL Energy. Mr. Daniel has served as President and
Chairman of IPL Energy USA since August 1996.
Mr. Sandahl has served as Vice President and a Director of the General
Partner since July 1996. Mr. Sandahl was Vice President, Operations of the
General Partner from May 1994 to August 1996. Prior thereto, he was employed by
Interprovincial for six years where he served in various capacities, most
recently as Director of Engineering Services from June 1990 to May 1994. On
January 1, 1996, Mr. Sandahl was transferred from employment with the General
Partner to employment with IPL Energy USA. He has served as Vice President of
IPL Energy USA since August 1996.
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 IPL Energy.
Mr. MacNeill has served as a Director of the General Partner since May 1990
and previously served as Chairman and Chief Executive Officer of the General
Partner from May 1994 to July 1996. From May 1991 to May 1994, he served as
President and Chief Executive Officer of the General Partner. Mr. MacNeill has
served as Chief Executive Officer, President and a Director of IPL Energy since
December 1992 and Chairman of Interprovincial since August 1996. He was Chairman
and Chief Executive Officer of Interprovincial from May 1994 to August 1996.
Prior thereto, he served as President and Chief Executive Officer of
Interprovincial from May 1991 to May 1994.
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 1, 1995 to December 31, 1995. Prior thereto, 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.
21
24
Mr. Truswell was elected a Director of the General Partner in May 1991 and
previously 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 IPL Energy since May 1994 and prior thereto, as Vice
President, Finance since 1992. Prior thereto, he served in various senior
executive capacities with Interprovincial, including as Vice President, Finance
from May 1991 to May 1994.
Mr. Bird has served as Treasurer of the General Partner since October 1996.
He has served as Vice President and Treasurer of IPL Energy since February 1995.
Prior thereto, Mr. Bird was employed by Gulf Canada Resources Ltd. as Vice
President, Treasury and Corporate Development from April 1993 to January 1995.
Prior thereto, he was employed by GW Utilities Ltd. as Vice President and
Controller.
Mr. DeVinck has served as Chief Accountant of the General Partner since
July 1996. Prior thereto, he held management and supervisory positions with the
General Partner in the areas of tax and accounting. On January 1, 1996, Mr.
DeVinck was transferred from employment with the General Partner to employment
with IPL Energy USA. He has served as Chief Accountant of IPL Energy USA since
August 1996.
Mr. Norgren has served as Secretary of the General Partner since July 1996.
Prior thereto, he served as Assistant Secretary and in professional and
management positions within the Law department of the General Partner. On
January 1, 1996, Mr. Norgren, General Counsel, was transferred from employment
with the General Partner to employment with IPL Energy USA. He has served as
Secretary of IPL Energy USA since August 1996, and prior thereto as Assistant
Secretary from November 1995 to August 1996.
(b) Section 16(a) Beneficial Ownership Reporting Compliance
Section 16(a) of the Securities Exchange Act of 1934 requires the General
Partner's directors and officers, and persons who own more than ten percent of a
registered class of the Partnership's equity securities, to file reports of
ownership and changes in ownership (Forms 3, 4 and 5) of such securities with
the Securities and Exchange Commission and the New York Stock Exchange. Mr. J.R.
Bird, Treasurer of the General Partner, Mr. P.D. Daniel, President and a
director of the General Partner, Mr. S.Q. DeVinck, Chief Accountant of the
General Partner and Mr. P.W. Norgren, Secretary of the General Partner, were
each late in filing an initial report on Form 3.
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. As the General Partner has no employees, it has entered into a services
agreement with IPL Energy USA to provide the services required by the
Partnership.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
(a) Security Ownership of Certain Beneficial Owners
TITLE OF CLASS NAME AND ADDRESS AMOUNT PERCENT OF CLASS
-------------- ---------------- ------ ----------------
Preference units No person or group is known to be the
beneficial owner of more than 5% of the
Preference Units as at February 1, 1997
Common units Lakehead Pipe Line Company, Inc. 3,912,750 100
Lake Superior Place
21 West Superior Street
Duluth, Minnesota 55802-2067
22
25
(b) Security Ownership of Management
As of February 3, 1997, S.Q. DeVinck beneficially owned 400 Preference
units. Preference units beneficially held by all directors and officers as a
group represented less than 1% of the Partnership's outstanding Preference
units.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
The Partnership is managed by the General Partner pursuant to the Amended
and Restated Agreements of Limited Partnership of the Partnership and the
Operating Partnership, dated December 27, 1991 ("Partnership Agreements"). The
General Partner has entered into a services agreement with IPL Energy USA
whereby the General Partner will utilize the resources of IPL Energy USA to
operate the Partnership. Under this agreement, IPL Energy USA 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 Interprovincial and IPL Energy
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, please read Note 6 to the Partnership's Consolidated
Financial Statements.
Under the terms of the Revolving Credit Facility Agreement, Lakehead
Services, Limited Partnership ("Services Partnership") and the Partnership may
draw down funds up to a combined maximum of $205.0 million. The Partnership has
a 1% general partner interest in the Services Partnership, with the General
Partner having a 99% limited partner interest. For additional details, please
read Note 6 to the Partnership's Consolidated Financial Statements.
For discussion of distribution restrictions and incentive distributions
payable to the General Partner, please read Note 3 to the Partnership's
Consolidated Financial Statements.
23
26
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 did not file any reports on Form 8-K during the fourth
quarter of 1996.
(c) The following Exhibits (numbered in accordance with Item 601 of
Regulation S-K) are filed or incorporated herein by reference as part of this
Report.
EXHIBIT
NUMBER DESCRIPTION
- ------- -----------
3.1 Certificate of Limited Partnership of the Partnership.
(Partnership's Registration Statement No. 33-43425 --
Exhibit 3.1)
4.1 Form of Certificate representing Preference Units. (1991
Form 10-K -- Exhibit 4.1)
4.2 Amended and Restated Agreement of Limited Partnership of the
Partnership, dated December 27, 1991. (1991 Form 10-K --
Exhibit 4.2)
10.1 Note Agreement and Mortgage, dated December 12, 1991. (1991
Form 10-K -- Exhibit 10.1)
10.2 Revolving Credit and Term Loan Facility Agreement, dated
December 12, 1991, 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. (1991 Form 10-K -- Exhibit 10.2)
10.3 Distribution Support Agreement, dated December 27, 1991,
among the Partnership, Lakehead Pipe Line Company, Inc. and
Interprovincial Pipe Line Inc. (1991 Form 10-K -- Exhibit
10.3)
10.4 Assumption and Indemnity Agreement, dated December 18, 1992,
between Interprovincial Pipe Line Inc. and Interprovincial
Pipe Line System Inc. (1992 Form 10-K -- Exhibit 10.4)
10.5 Amended Services Agreement, dated February 29, 1988, between
Interprovincial Pipe Line Inc. and Lakehead Pipe Line
Company, Inc. (1991 Form 10-K -- Exhibit 10.4)
10.6 Amended Services Agreement, dated January 1, 1992, between
Interprovincial Pipe Line Inc. and Lakehead Pipe Line
Company, Inc. (1992 Form 10-K -- Exhibit 10.6)
10.7 Certificate of Limited Partnership of the Operating
Partnership. (Partnership's Registration Statement No.
33-43425 -- Exhibit 10.1)
10.8 Amended and Restated Agreement of Limited Partnership of the
Operating Partnership, dated December 27, 1991. (1991 Form
10-K -- Exhibit 10.6)
10.9 Certificate of Limited Partnership of Lakehead Services,
Limited Partnership. (Partnership's Registration Statement
No. 33-43425 -- Exhibit 10.4)
10.10 Amendment No. 1 to the Certificate of Limited Partnership of
Lakehead Services, Limited Partnership. (Partnership's
Registration Statement No. 33-43425 -- Exhibit 10.16)
10.11 Amended and Restated Agreement of Limited Partnership of
Lakehead Services, Limited Partnership, dated December 27,
1991. (1991 Form 10-K -- Exhibit 10.9)
10.12 Contribution, Conveyance and Assumption Agreement, dated
December 27, 1991, among Lakehead Pipe Line Company, Inc.,
Lakehead Pipe Line Partners, L.P. and Lakehead Pipe Line
Company, Limited Partnership. (1991 Form 10-K -- Exhibit
10.10)
10.13 LPL Contribution and Assumption Agreement, dated December
27, 1991, among Lakehead Pipe Line Company, Inc., Lakehead
Pipe Line Partners, L.P. and Lakehead Pipe Line Company,
Limited Partnership and Lakehead Services, Limited
Partnership. (1991 Form 10-K -- Exhibit 10.11)
24
27
EXHIBIT
NUMBER DESCRIPTION
- ------- -----------
10.14 Services Agreement, dated January 1, 1996, between IPL
Energy (U.S.A.) Inc. and Lakehead Pipe Line Company, Inc.
(1995 Form 10-K -- Exhibit 10.14)
10.15 Amended and Restated Revolving Credit Agreement, dated
September 6, 1996, among Lakehead Pipe Line Company, Inc.,
Lakehead Pipe Line Partners, L.P., Lakehead Services,
Limited Partnership, Lakehead Pipe Line Company, Limited
Partnership and the Bank of Montreal and Harris Trust and
Savings Bank.
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.
10.17 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.
10.18 Treasury Services Agreement, dated January 1, 1996, between
IPL Energy Inc. and Lakehead Pipe Line Company, Inc.
21 Subsidiaries of the Registrant.
27 Financial Data Schedule as of and for the year ended
December 31, 1996.
All Exhibits listed above, with the exception of Exhibits 10.15, 10.16,
10.17, 10.18, 21 and 27 are incorporated herein by reference to the
documents identified in parentheses.
Copies of Exhibits may be obtained upon written request of any Unitholder
to Investor Relations, Lakehead Pipe Line Company, Inc., Lake Superior Place, 21
West Superior Street, Duluth, Minnesota 55802-2067.
(d) As to financial statement schedules, reference is made to "Financial
Statement Schedules" on page F-1 of this report.
25
28
SIGNATURES
PURSUANT TO THE REQUIREMENTS OF SECTION 13 OR 15(d)OF THE SECURITIES
EXCHANGE ACT OF 1934, THE REGISTRANT HAS DULY CAUSED THIS REPORT TO BE SIGNED ON
ITS BEHALF BY THE UNDERSIGNED, THEREUNTO DULY AUTHORIZED.
Lakehead Pipe Line Partners, L.P.
(Registrant)
By: Lakehead Pipe Line Company, Inc.,
as General Partner
Date: February 17, 1997 By: /s/ P. D. DANIEL
------------------------------------
P.D. Daniel
(President)
PURSUANT TO THE REQUIREMENTS OF THE SECURITIES EXCHANGE ACT OF 1934, THIS
REPORT HAS BEEN SIGNED BELOW ON FEBRUARY 17, 1997 BY THE FOLLOWING PERSONS ON
BEHALF OF THE REGISTRANT AND IN THE CAPACITIES INDICATED WITH LAKEHEAD PIPE LINE
COMPANY, INC., GENERAL PARTNER.
/s/ P.D. DANIEL /s/ E.C. HAMBROOK
- ------------------------------------------ ------------------------------------------
P.D. Daniel E.C. Hambrook
President and Director Chairman and Director
(Principal Executive Officer)
/s/ R.C. SANDAHL /s/ S.Q. DEVINCK
- ------------------------------------------ ------------------------------------------
R.C. Sandahl S.Q. DeVinck
Vice President and Director Chief Accountant
(Principal Financial and Accounting
Officer)
/s/ F.W. FITZPATRICK /s/ B.F. MACNEILL
- ------------------------------------------ ------------------------------------------
F.W. Fitzpatrick B.F. MacNeill
Director Director
/s/ C.A. RUSSELL /s/ D.P. TRUSWELL
- ------------------------------------------ ------------------------------------------
C.A. Russell D.P. Truswell
Director Director
26
29
INDEX TO FINANCIAL STATEMENTS, SUPPLEMENTARY INFORMATION
AND FINANCIAL STATEMENT SCHEDULES
LAKEHEAD PIPE LINE PARTNERS, L.P.
PAGE
----
Financial Statements
Report of Independent Accountants......................... F-2
Consolidated Statement of Income for the Years Ended
December 31, 1996, 1995, 1994.......................... F-3
Consolidated Statement of Cash Flows for the Years Ended
December 31, 1996, 1995, 1994.......................... F-4
Consolidated Statement of Financial Position as at
December 31, 1996 and 1995............................. F-5
Consolidated Statement of Partners' Capital for the Years
Ended December 31, 1996,
1995, 1994............................................. F-6
Notes to the 1996 Consolidated 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
30
REPORT OF INDEPENDENT ACCOUNTANTS
To the Partners of
Lakehead Pipe Line Partners, L.P.
In our opinion, the accompanying consolidated balance sheets and the
related consolidated statements of income, of partners' capital and of cash
flows present fairly, in all material respects, the financial position of
Lakehead Pipe Line Partners, L.P. and its investment in Lakehead Pipe Line
Company, Limited Partnership at December 31, 1996 and 1995, and the results of
their operations and their cash flows for each of the three years in the period
ended December 31, 1996 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.
PRICE WATERHOUSE LLP
Minneapolis, Minnesota
January 13, 1997
F-2
31
LAKEHEAD PIPE LINE PARTNERS, L.P.
CONSOLIDATED STATEMENT OF INCOME
YEAR ENDED DECEMBER 31,
--------------------------
1996 1995 1994
---- ---- ----
(DOLLARS IN MILLIONS,
EXCEPT PER UNIT AMOUNTS)
Operating Revenue (Note 8).................................. $274.5 $268.5 $246.0
------ ------ ------
Expenses
Power..................................................... 62.0 64.2 62.6
Operating and administrative.............................. 66.7 70.1 65.7
Depreciation.............................................. 38.3 38.0 31.4
Provision for prior years' rate refunds (Note 8).......... 20.1 22.9 --
------ ------ ------
187.1 195.2 159.7
------ ------ ------
Operating Income............................................ 87.4 73.3 86.3
Interest Income............................................. 9.6 7.1 4.1
Interest Expense (Note 5)................................... (43.9) (40.3) (29.8)
Minority Interest........................................... (0.7) (0.5) (0.7)
------ ------ ------
Net Income.................................................. $ 52.4 $ 39.6 $ 59.9
====== ====== ======
Net Income Per Unit (Note 2)................................ $ 2.11 $ 1.60 $ 2.61
====== ====== ======
Weighted Average Units Outstanding (millions)............... 24.0 24.0 22.4
====== ====== ======
The accompanying notes to the consolidated financial statements are an integral
part of these statements.
F-3
32
LAKEHEAD PIPE LINE PARTNERS, L.P.
CONSOLIDATED STATEMENT OF CASH FLOWS
YEAR ENDED DECEMBER 31,
-------------------------
1996 1995 1994
---- ---- ----
(DOLLARS IN MILLIONS)
Operating Activities
Net income................................................ $ 52.4 $ 39.6 $ 59.9
Adjustments to reconcile net income to cash provided from
operating activities:
Depreciation........................................... 38.3 38.0 31.4
Accrued rate refunds and related interest (Note 8)..... 42.6 46.4 9.7
Minority interest...................................... 0.7 0.5 0.7
Other.................................................. 0.6 0.8 0.2
Changes in operating assets and liabilities:
Accounts receivable and other........................ (0.7) 4.3 (5.6)
Materials and supplies............................... (1.6) (0.7) --
Due to General Partner and affiliates................ 0.2 0.2 (0.8)
Accounts payable and other........................... 3.6 (12.1) 12.9
Interest payable..................................... 0.7 1.1 (0.4)
Property and other taxes............................. (1.1) 3.4 0.1
Payment of rate refunds and related interest (Note
8).................................................. (41.8) -- --
------ ------ -------
93.9 121.5 108.1
------ ------ -------
Investing Activities
Short-term investments, net............................... (8.0) (18.5) 34.2
Additions to property, plant and equipment................ (76.7) (35.5) (136.9)
------ ------ -------
(84.7) (54.0) (102.7)
------ ------ -------
Financing Activities
Issuance of variable rate financing....................... 68.0 31.0 20.0
Proceeds from unit issuance (Note 1)...................... -- -- 64.8
Distributions to partners (Note 3)........................ (63.9) (62.9) (57.2)
Minority interest......................................... (0.7) (0.6) 0.1
------ ------ -------
3.4 (32.5) 27.7
------ ------ -------
Increase in Cash and Cash Equivalents....................... 12.6 35.0 33.1
Cash and Cash Equivalents at Beginning of Year.............. 77.0 42.0 8.9
------ ------ -------
Cash and Cash Equivalents at End of Year.................... $ 89.6 $ 77.0 $ 42.0
====== ====== =======
The accompanying notes to the consolidated financial statements are an integral
part of these statements.
F-4
33
LAKEHEAD PIPE LINE PARTNERS, L.P.
CONSOLIDATED STATEMENT OF FINANCIAL POSITION
DECEMBER 31,
---------------------
1996 1995
---- ----
(DOLLARS IN MILLIONS)
ASSETS
Current Assets
Cash and cash equivalents................................. $ 89.6 $ 77.0
Short-term investments.................................... 83.7 75.7
Accounts receivable and other............................. 27.2 26.5
Materials and supplies.................................... 7.0 5.4
------ ------
207.5 184.6
Deferred Charges and Other.................................. 4.9 5.5
Property, Plant and Equipment, Net (Note 4)................. 763.5 725.1
------ ------
$975.9 $915.2
====== ======
LIABILITIES AND PARTNERS' CAPITAL
Current Liabilities
Due to General Partner and affiliates..................... $ 1.5 $ 1.3
Accounts payable and other................................ 16.8 13.2
Interest payable.......................................... 3.2 2.5
Property and other taxes.................................. 11.1 12.2
Current portion of accrued rate refunds and related
interest (Note 8)...................................... 29.0 78.5
------ ------
61.6 107.7
Long-Term Debt (Note 5)..................................... 463.0 395.0
Accrued Rate Refunds and Related Interest (Note 8).......... 50.3 --
Minority Interest........................................... 1.4 1.4
Contingencies (Note 9)......................................
------ ------
576.3 504.1
Partners' Capital
General Partner........................................... 1.6 1.5
Common Unitholder (Units issued -- 3,912,750)............. 21.7 21.7
Preference Unitholders (Units issued -- 20,090,000)....... 376.3 387.9
------ ------
399.6 411.1
------ ------
$975.9 $915.2
====== ======
The accompanying notes to the consolidated financial statements are an integral
part of these statements.
F-5
34
LAKEHEAD PIPE LINE PARTNERS, L.P.
CONSOLIDATED STATEMENT OF PARTNERS' CAPITAL
GENERAL COMMON PREFERENCE
PARTNER UNITHOLDER UNITHOLDERS TOTAL
------- ---------- ----------- -----
(DOLLARS IN MILLIONS)
Partners' capital at December 31, 1993.................. $ 0.7 $ 11.8 $354.4 $366.9
Allocation of proceeds from unit issuance (Note 1)...... 0.6 9.1 55.1 64.8
Net income allocation................................... 1.4 12.4 46.1 59.9
Distributions to partners............................... (1.1) (9.8) (46.3) (57.2)
----- ------ ------ ------
Partners' capital at December 31, 1994.................. 1.6 23.5 409.3 434.4
Net income allocation................................... 1.2 8.2 30.2 39.6
Distributions to partners............................... (1.3) (10.0) (51.6) (62.9)
----- ------ ------ ------
Partners' capital at December 31, 1995.................. 1.5 21.7 387.9 411.1
Net income allocation................................... 1.6 10.2 40.6 52.4
Distributions to partners............................... (1.5) (10.2) (52.2) (63.9)
----- ------ ------ ------
Partners' capital at December 31, 1996.................. $ 1.6 $ 21.7 $376.3 $399.6
===== ====== ====== ======
The accompanying notes to the consolidated financial statements are an integral
part of these statements.
F-6
35
LAKEHEAD PIPE LINE PARTNERS, L.P.
NOTES TO THE 1996 CONSOLIDATED FINANCIAL STATEMENTS
(dollars in millions)
1. PARTNERSHIP ORGANIZATION AND NATURE OF OPERATIONS
Lakehead Pipe Line Partners, L.P. ("Lakehead Partnership") is a publicly
traded limited partnership that owns a 99% limited partner interest in Lakehead
Pipe Line Company, Limited Partnership ("Operating Partnership"), both Delaware
limited partnerships, and collectively known as the "Partnership". The
Partnership was formed in 1991 to acquire, own and operate the crude oil and
natural gas liquids pipeline business of Lakehead Pipe Line Company, Inc. (the
sole "General Partner"). The General Partner is a wholly-owned subsidiary of
Interprovincial Pipe Line Inc. ("Interprovincial"), a Canadian company owned by
IPL Energy Inc. of Calgary, Alberta, Canada.
In September 1994, the Lakehead Partnership issued an additional 2,200,000
Preference units (total proceeds, including the General Partner's contribution,
were $64.8 million), bringing the total number of Preference units issued to
20,090,000. Preference units are publicly traded and represent an 82.0% limited
partner interest in the Partnership. The General Partner has a 16.1% limited
partner (in the form of 3,912,750 Common units) and 1.0% general partner
interest in the Lakehead Partnership, as well as a 1.0% general partner interest
in the Operating Partnership (an effective 18.0% combined interest in the
Partnership).
The Partnership holds a 1% general partner interest in Lakehead Services,
Limited Partnership ("Services Partnership"), a Delaware limited partnership,
formed to facilitate the ongoing financing of the Operating Partnership.
The Operating Partnership is engaged in the transportation of crude oil and
natural gas liquids through a common carrier pipeline system. Substantially all
of the shipments delivered originate in western Canadian oil fields. The
majority of the shipments reach the Operating Partnership at the Canada/United
States border in North Dakota, through a Canadian pipeline system owned by
Interprovincial. 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.
Approximately 60% of the Operating Partnership's deliveries were made in the
United States in each of the last three years.
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
The consolidated financial statements of the Partnership are prepared in
accordance with generally accepted accounting principles in the United States
and conform in all material respects with the historical cost accounting
standards of the International Accounting Standards Committee. The preparation
of financial statements in conformity with generally accepted accounting
principles requires management to make estimates and assumptions that affect the
reported amounts of assets, liabilities, revenues, expenses and disclosure of
contingent assets and liabilities.
PRINCIPLES OF CONSOLIDATION
The financial statements of the Partnership include the accounts of the
Lakehead Partnership and the Operating Partnership on a consolidated basis. The
equity method is used to account for the Partnership's 1% general partner
interest in the Services Partnership. The General Partner's 1% interest in the
Operating Partnership is accounted for by the Partnership as a minority
interest.
REGULATION OF PIPELINE SYSTEM
As an interstate common carrier oil pipeline, rates and accounting
practices are under the regulatory authority of the Federal Energy Regulatory
Commission ("FERC").
F-7
36
LAKEHEAD PIPE LINE PARTNERS, L.P.
NOTES TO THE 1996 CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
(dollars in millions)
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
REVENUE RECOGNITION
Substantially all pipeline system revenues are derived from transportation
of crude oil and natural gas liquids and are recognized in income upon delivery.
Amounts provided for accrued rate refunds are recognized as a direct reduction
from revenues except for amounts related to prior years (Note 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 net realizable
value.
DEFERRED FINANCING CHARGES
Deferred financing charges are amortized on the straight line basis over
the life of the related debt.
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
For federal and state income tax purposes, the Partnership is not a taxable
entity. Accordingly, no recognition has been given to income taxes for financial
reporting purposes. The tax on Partnership net income is borne by the individual
partners through the allocation of taxable income. Such taxable income may vary
substantially from net income reported in the consolidated statement of income.
NET INCOME PER UNIT
Net income per unit is computed by dividing net income, after deduction of
the General Partner's allocation, by the weighted average number of Preference
and Common units outstanding. The General Partner's allocation is equal to an
amount based upon its 1% general partner interest, adjusted to reflect an amount
equal to incentive distributions and an amount required to reflect depreciation
on the General Partner's historical cost basis for assets contributed on
formation of the Partnership. The General Partner was allocated 3.0%, 3.0% and
2.3% of net income before minority interest in 1996, 1995 and 1994,
respectively.
COMPARATIVE AMOUNTS
Certain comparative amounts are reclassified to conform with the current
year's financial statement presentation.
F-8
37
LAKEHEAD PIPE LINE PARTNERS, L.P.
NOTES TO THE 1996 CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
(dollars in millions)
3. CASH DISTRIBUTIONS
The Partnership distributes quarterly all of its "Available Cash", which is
generally defined in the Partnership Agreement as cash receipts less cash
disbursements and net additions to reserves for future requirements. These
reserves are retained to provide for the proper conduct of the Partnership
business and as necessary to comply with the terms of any agreement or
obligation of the Partnership. Distributions by the Partnership of its Available
Cash generally are made 98% to the Common and Preference Unitholders and 2% to
the General Partner, subject to the payment of incentive distributions to the
General Partner to the extent that certain target levels of cash distributions
to the Unitholders are achieved. The incremental incentive distributions payable
to the General Partner are 15%, 25% and 50% of all quarterly distributions of
Available Cash that exceed target levels of $0.59, $0.70, and $0.99 per
Preference and Common unit, respectively. Such incentive distributions totaled
$0.9 million in 1996 (1995 -- $0.7 million; 1994 -- $0.5 million).
In 1996, the Partnership paid cash distributions of $2.60 per unit
consisting of $0.64 per unit paid in February, May and August, and $0.68 per
unit paid in November. In 1995, distributions of $2.56 per unit were paid,
representing four distributions of $0.64 per unit. In 1994, distributions of
$2.51 per unit were paid, consisting of $0.59 per unit paid in February and
$0.64 per unit paid in May, August and November.
The cash distribution in respect of the fourth quarter 1996 will be the
last distribution subject to certain preferential rights of the Preference
Unitholders and certain support obligations of the General Partner. For
distributions related to quarters ending before 1997, in the event that there
was not sufficient Available Cash to pay a minimum quarterly distribution
("MQD") of $0.59 per unit to all Unitholders at the end of a quarter, Preference
Unitholders were entitled to receive the MQD, plus any arrearages, prior to any
distribution of Available Cash to the Common Unitholders. With no arrearages of
cash distributions, this preferential right will expire after the payment of the
distribution related to the fourth quarter of 1996. With respect to subsequent
cash distributions, the Preference and Common units will be treated as one class
of units. In addition, the General Partner had agreed, for quarterly
distributions prior to 1997, to support the MQD to a maximum aggregate amount of
$60.0 million. This support has not been required.
4. PROPERTY, PLANT AND EQUIPMENT, NET
AVERAGE DECEMBER 31,
DEPRECIATION -----------------
RATES 1996 1995
------------ ---- ----
Land........................................................ -- $ 5.4 $ 5.2
Rights-of-way............................................... 3.6% 12.4 12.4
Pipeline.................................................... 4.1 506.1 504.2
Pumping equipment, buildings and tanks...................... 4.6 310.8 257.7
Vehicles, office and communications equipment............... 13.6 27.1 24.6
Construction in progress.................................... -- 22.4 4.7
------- -------
884.2 808.8
Accumulated depreciation.................................... (120.7) (83.7)
------- -------
$ 763.5 $ 725.1
======= =======
Effective July 1, 1996, the Partnership revised the estimated service lives
of its property, plant and equipment to better represent the service life of its
pipeline system. Prior to this change, the average depreciation rate for
rights-of-way was 4.0%, pipeline -- 4.0%, pumping equipment, buildings and
tanks -- 6.9% and vehicles, office and communications equipment -- 6.2%. The
change in depreciation rates resulted in 1996 net income being $1.8 million, or
$0.07 per unit, higher than it would have been utilizing the prior rates.
F-9
38
LAKEHEAD PIPE LINE PARTNERS, L.P.
NOTES TO THE 1996 CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
(dollars in millions)
5. DEBT
DECEMBER 31,
----------------
1996 1995
---- ----
First Mortgage Notes........................................ $310.0 $310.0
Revolving Credit Facility Agreement......................... 153.0 85.0
------ ------
$463.0 $395.0
====== ======
FIRST MORTGAGE NOTES
The Partnership has issued, in a private placement to institutional
investors, $310.0 million aggregate principal amount of First Mortgage Notes.
The Notes are secured by a first mortgage on substantially all of the property,
plant and equipment of the Partnership and are due and payable in ten equal
annual installments beginning in the year 2002. The interest rate on the Notes
is 9.15% per annum, payable semi-annually. The Notes contain various restrictive
covenants applicable to the Partnership, and restrictions on the incurrence of
additional indebtedness, which is subject to compliance with certain issuance
tests. The General Partner believes these issuance tests will not negatively
impact the Partnership's ability to finance current expansion projects. Under
the Note Agreements, the Partnership is permitted to make cash distributions not
more frequently than quarterly in an amount not to exceed Available Cash (Note
3) for the immediately preceding calendar quarter.
REVOLVING CREDIT FACILITY AGREEMENT
The Partnership has a $205.0 million Revolving Credit Facility Agreement
which was amended in September 1996 to effectively reduce the interest rate
spread and extend the maturity date to at least September 2001. The maturity
date is subject to extension on an annual basis. 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. government securities. The
facility contains restrictive covenants substantially identical to those in the
Note Agreements, provides for variable interest rates and currently carries a
facility fee of 0.085% per annum on the entire $205.0 million. At December 31,
1996, $153.0 million of the facility was utilized and is classified as long-term
debt (1995 -- $85.0 million). The interest rate on loans averaged 6.8% (1995 --
6.9%; 1994 -- 5.1%) and was 6.0% at the end of 1996 (1995 -- 7.2%).
INTEREST
Interest expense includes $9.7 million related to accrued rate refunds
(1995 -- $7.3 million; 1994 -- $1.8 million) and is net of amounts capitalized
of $2.4 million (1995 -- $1.0 million; 1994 -- $3.8 million). Interest paid
amounted to $44.8 million (1995 -- $31.9 million; 1994 -- $31.0 million).
6. RELATED PARTY TRANSACTIONS
The Partnership, which does not have any employees, uses the services of
the General Partner and its affiliates for managing and operating its pipeline
business. These services, which are reimbursed at cost in accordance with
service agreements, amounted to $33.9 million (1995 -- $33.8 million; 1994 --
$34.0 million) and are included in operating and administrative expenses.
Under the terms of the Revolving Credit Facility Agreement, the Services
Partnership and the Partnership may draw down funds up to a combined maximum of
$205.0 million. The Partnership is entitled to require the Services Partnership
to repay any amounts owed by the Services Partnership in order to allow the
Partnership to borrow thereunder. During 1996, the Partnership paid the Services
Partnership a standby
F-10
39
LAKEHEAD PIPE LINE PARTNERS, L.P.
NOTES TO THE 1996 CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
(dollars in millions)
6. RELATED PARTY TRANSACTIONS (CONTINUED)
fee of $0.4 million (1995 -- $0.8 million; 1994 -- $1.0 million) as
consideration for the agreement by the Services Partnership that the Partnership
will have priority over the Services Partnership to borrow up to the full amount
available under the facility. Effective September 1996, the standby fee was
eliminated and replaced with a facility fee which the Partnership pays directly.
The Partnership will continue to have borrowing priority over the Services
Partnership.
7. MAJOR CUSTOMERS
Operating revenue received from major customers was as follows:
YEAR ENDED DECEMBER 31,
-----------------------
1996 1995 1994
---- ---- ----
Amoco Oil Company.................................... $63.2 $62.3 $54.6
Mobil Oil Company of Canada Ltd. .................... $37.2 $34.7 $33.9
Imperial Oil Limited................................. $35.4 $31.4 $27.3
The Partnership has a concentration of trade receivables from companies
operating in the oil and gas industry. These receivables are collateralized by
the crude oil and other products contained in the Partnership's pipeline and
storage facilities.
8. ACCRUED RATE REFUNDS AND RELATED INTEREST
In October 1996, the FERC approved a July 1996 agreement between the
Partnership and customer representatives on all outstanding contested tariff
rates. The agreement resulted in an approximate tariff rate reduction of 6% and
total rate refunds and related interest of $120.0 million through the effective
date of October 1, 1996. Refunds of $41.8 million were made during the fourth
quarter of 1996, with the remaining balance ($79.3 million at December 31, 1996)
to be repaid through a 10% reduction on future rates. This reduction will
continue until all refunds have been made, which is expected to take
approximately three years. Interest will continue to accrue on the unpaid
balance.
The Partnership provided for $42.6 million of rate refunds and related
interest in 1996 to reflect the settlement agreement. In 1995, the Partnership
provided for $46.4 million of rate refunds and related interest to reflect a
June 1995 FERC decision. In 1994, $9.7 million was provided for rate refunds and
related interest to reflect an October 1994 FERC Administrative Law Judge
initial decision. The balance of accrued rate refunds and related interest was
provided for prior to 1994. Of the amounts provided, rate refunds related to the
current year have reduced operating revenue, with the prior years' portion
separately stated as a provision for prior years' rate refunds. Interest has
been reflected in interest expense.
9. CONTINGENCIES
The Partnership is subject to federal and state laws and regulations
relating to the protection of the environment. Environmental risk is inherent to
liquid pipeline operations and the Partnership could, at times, be subject to
environmental cleanup and enforcement actions. The General Partner manages this
environmental risk through appropriate environmental policies and practices to
minimize the impact to the Partnership. To the extent that the Partnership is
unable to recover environmental costs in its rates or through insurance, the
General Partner has agreed to indemnify the Partnership from and against any
costs relating to environmental liabilities associated with the pipeline system
prior to its transfer to the Partnership in 1991. This excludes any liabilities
resulting from a change in laws after such transfer. The Partnership continues
to
F-11
40
LAKEHEAD PIPE LINE PARTNERS, L.P.
NOTES TO THE 1996 CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
(dollars in millions)
9. CONTINGENCIES (CONTINUED)
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.
10. FAIR VALUE OF FINANCIAL INSTRUMENTS
The carrying amounts of cash equivalents and short-term investments
approximate fair value because of the short maturity of these instruments. The
short-term investments consist primarily of government obligations and high
quality commercial paper.
Based on the borrowing rates currently available for instruments with
similar terms and remaining maturities, the carrying values of borrowings under
the Revolving Credit Facility approximate fair value and the fair value of the
First Mortgage Notes approximates $344 million (1995 -- $366 million). Due to
contractual arrangements defined in the Note Agreements, refinancing of the
Notes would not result in any financial benefit to the Partnership.
F-12
41
LAKEHEAD PIPE LINE PARTNERS, L.P.
SUPPLEMENTARY INFORMATION (UNAUDITED)
SELECTED QUARTERLY FINANCIAL DATA
(dollars in millions, except per unit amounts)
FIRST(2) SECOND THIRD FOURTH TOTAL
-------- ------ ----- ------ -----
1996 QUARTERS
Operating revenue...................................... $ 68.0 $65.9 $67.9 $72.7 $274.5
Operating income....................................... $ 5.2 $27.6 $25.7 $28.9 $ 87.4
Net income (loss)...................................... $ (6.3) $19.2 $17.7 $21.8 $ 52.4
Net income (loss) per unit(1).......................... $(0.27) $0.78 $0.72 $0.88 $ 2.11
1995 QUARTERS
Operating revenue...................................... $ 64.9 $68.7 $66.2 $68.7 $268.5
Operating income....................................... $ 0.2 $27.6 $22.6 $22.9 $ 73.3
Net income (loss)...................................... $ (9.3) $19.5 $14.5 $14.9 $ 39.6
Net income (loss) per unit(1).......................... $(0.39) $0.79 $0.59 $0.61 $ 1.60
- -------------------------
(1) The General Partner's allocation of net income (loss) has been deducted
before calculating net income (loss) per unit.
(2) The first quarter of 1996 was restated to reflect the 1996 agreement between
the Partnership and customer representatives on all outstanding contested
tariff rates, and the first quarter of 1995 was restated to reflect the June
1995 FERC decision.
F-13