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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended DECEMBER 31, 1998
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the transition period from ______ to ______
Commission File Number: 1-10934
LAKEHEAD PIPE LINE PARTNERS, L.P.
(Exact name of Registrant as specified in its charter)
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<S> <C>
DELAWARE 39-1715850
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
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LAKE SUPERIOR PLACE
21 WEST SUPERIOR STREET
DULUTH, MINNESOTA 55802-2067
(Address of principal executive offices and zip code)
(218) 725-0100
(Registrant's telephone number, including area code)
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Securities registered pursuant to Section 12(b) of the Act:
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Title of each class Name of each exchange on which registered
CLASS A COMMON UNITS NEW YORK STOCK EXCHANGE
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Securities registered pursuant to Section 12(g) of the Act: NONE
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Indicate by check mark whether the Registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
Registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes [X] No [ ]
Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to the
best of the Registrant's knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K. [X]
As of March 1, 1999, the aggregate market value of the Registrant's Class A
Common Units held by non affiliates of the Registrant was $965,384,000 based on
the reported closing sale price of such units on the New York Stock Exchange on
that date.
As of March 1, 1999, there were 22,290,000 of the Registrant's Class A
Common Units outstanding.
------------------------
DOCUMENTS INCORPORATED BY REFERENCE: NONE
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TABLE OF CONTENTS
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PAGE
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PART I
ITEMS 1 & 2. Business and Properties..................................... 1
ITEM 3. Legal Proceedings........................................... 11
ITEM 4. Submission of Matters to a Vote of Security Holders......... 12
PART II
ITEM 5. Market for Registrant's Common Equity and Related
Stockholder Matters......................................... 12
ITEM 6. Selected Financial Data..................................... 13
ITEM 7. Management's Discussion and Analysis of Financial Condition
and Results of Operations................................. 14
ITEM 7A. Quantitative and Qualitative Disclosures About Market
Risk........................................................ 21
ITEM 8. Financial Statements and Supplementary Data................. 22
ITEM 9. Changes in and Disagreements with Accountants on Accounting
and Financial Disclosure.................................. 22
PART III
ITEM 10. Directors and Executive Officers of the Registrant.......... 22
ITEM 11. Executive Compensation...................................... 23
ITEM 12. Security Ownership of Certain Beneficial Owners and
Management.................................................. 24
ITEM 13. Certain Relationships and Related Transactions.............. 24
PART IV
ITEM 14. Exhibits, Financial Statement Schedules and Reports on Form
8-K......................................................... 25
SIGNATURES.................................................................. 28
INDEX TO FINANCIAL STATEMENTS, SUPPLEMENTARY INFORMATION AND FINANCIAL
STATEMENT SCHEDULES....................................................... F-1
</TABLE>
This Annual Report on Form 10-K contains forward-looking statements. These
statements are based on the Partnership's beliefs as well as assumptions made by
and information currently available to the Partnership. When used in this
document, the words "anticipate," "believe," "expect," "estimate," "forecast,"
"project," and similar expressions identify forward-looking statements. These
statements reflect the Partnership's current views with respect to future events
and are subject to various risks, uncertainties and assumptions including:
- the Partnership's dependence upon adequate supplies of and demand for
western Canadian crude oil,
- the price of crude oil and the willingness of shippers to ship crude oil
when prices are low,
- regulation of the Partnership's tariffs by the Federal Energy Regulatory
Commission and the possibility of unfavorable outcomes of future tariff
proceedings,
- the Partnership's ability to complete Year 2000 readiness activities, and
- the effects of competition, in particular, by other pipeline systems.
If one or more of these risks or uncertainties materialize, or if the
underlying assumptions prove incorrect, actual results may vary materially from
those described in this Form 10-K. Except as required by applicable securities
laws, the Partnership does not intend to update these forward-looking
statements. For additional discussion of such risks, uncertainties and
assumptions, see "Items 1 & 2. Business and Properties -- Business Risks"
included elsewhere in this Form 10-K.
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PART I
ITEMS 1 & 2. BUSINESS AND PROPERTIES
OVERVIEW
Lakehead Pipe Line Partners, L.P. is a publicly traded Delaware limited
partnership ("Registrant" or "Partnership"), which owns a 99% limited partner
interest in Lakehead Pipe Line Company, Limited Partnership ("Operating
Partnership"), also a Delaware limited partnership. Unless the context otherwise
requires, references in this Form 10-K to the Partnership include the Registrant
and the Operating Partnership.
The Partnership was formed in 1991 to acquire, own and operate the
regulated crude oil and natural gas liquids pipeline business of Lakehead Pipe
Line Company, Inc. (the "General Partner"), a wholly-owned subsidiary of
Enbridge Pipelines Inc. ("Enbridge Pipelines" formerly Interprovincial Pipe Line
Inc.). Enbridge Pipelines is a Canadian company owned by Enbridge Inc.
("Enbridge" formerly IPL Energy Inc.) of Calgary, Alberta, Canada. The General
Partner owns a 14.8% limited partner interest (in the form of 3,912,750 Class B
Common Units) and a 1% general partner interest in the Registrant, as well as a
1% general partner interest in the Operating Partnership (an effective 16.6%
combined interest in the Partnership). The remaining 83.4% limited partner
interest in the Partnership is represented by 22,290,000 publicly traded Class A
Common Units.
The Partnership and Enbridge Pipelines transport crude oil and other liquid
hydrocarbons for others through the world's longest liquid petroleum pipeline
system ("System"). The System is the primary transporter of crude oil from
western Canada to the United States and is the only pipeline that transports
crude oil from western Canada to eastern Canada. The System serves all the major
refining centers in the Great Lakes region of the United States, as well as the
province of Ontario, Canada and the Patoka/Wood River refinery and pipeline hub
in southern Illinois. Various subsidiaries of Enbridge own the Canadian portion
of the System ("Enbridge Pipelines System") and the Partnership owns the U.S.
portion of the System ("Lakehead System").
The System extends from Edmonton, Alberta, across the Canadian prairies to
the U.S. border near Neche, North Dakota. From Neche the System continues on to
Superior, Wisconsin, where it splits into two branches with one branch
travelling through the upper Great Lakes region and the other through the lower
Great Lakes region of the United States. Both branches reenter Canada near
Marysville, Michigan. From Marysville the System continues on to Toronto,
Ontario and Montreal, Quebec, with lateral lines to Nanticoke, Ontario and the
Buffalo, New York area. The System is approximately 3,000 miles long, of which,
approximately 1,750 are in the United States.
Shipments tendered to the System primarily originate in oil fields in the
western Canadian provinces of Alberta, Saskatchewan, Manitoba and British
Columbia and in the Northwest Territories of Canada and reach the System through
facilities owned and operated by third parties or affiliates of Enbridge
Pipelines. Deliveries from the System are currently made in the prairie
provinces of Canada, in the Great Lakes and Midwest regions of the United States
and the province of Ontario, principally to refineries, either directly or
through connecting pipelines of other companies.
All scheduling of shipments (including routes and storage) is handled by
Enbridge Pipelines in coordination with the Partnership. The Lakehead System
includes 16 connections to pipelines and refineries at various locations in the
United States, including the refining areas in and around Chicago, Illinois,
Minneapolis-St. Paul, Minnesota, Detroit, Michigan, Toledo, Ohio, Buffalo and
Patoka/Wood River. The Lakehead System has three main terminals at Clearbrook,
Minnesota, Superior, and Griffith, Indiana. The terminals are used to gather
crude oil prior to injection into the Lakehead System and to provide tankage in
order to allow for more flexible scheduling of oil movements.
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PROPERTIES
The Lakehead System consists of approximately 3,200 miles of pipe with
diameters ranging from 12 inches to 48 inches, 60 main line pump station
locations with a total of approximately 663,000 installed horsepower and 54
crude oil storage tanks with an aggregate working capacity of approximately nine
million barrels. The volume of liquid hydrocarbons in the Lakehead System
required at all times for operation is approximately 13 million barrels, all of
which is owned by the shippers on the Lakehead System. The Lakehead System
regularly transports up to 45 different types of liquid hydrocarbons including
light, medium and heavy crude oil (including bitumen), condensate, synthetic
crudes and natural gas liquids ("NGL").
The Lakehead System is comprised of a number of separate segments as
follows:
- Canadian border to Clearbrook segment including portions of four
pipelines consisting of 18-, 20-, 26-, and 34-inch diameter pipe with a
total annual capacity of 1,571,000 barrels per day. This segment includes
approximately 40 miles of 48-inch pipeline looping that increases the
annual capacity of this segment;
- Clearbrook to Superior segment including portions of three pipelines
consisting of 18-, 26-, and 34-inch diameter pipe, respectively, with a
total annual capacity of 1,337,000 barrels per day. This segment also
includes approximately 80 miles of 48-inch pipeline looping;
- Superior to Marysville segment consisting of 30-inch diameter pipe with
an annual capacity of 509,000 barrels per day;
- Superior to Chicago area segment including two pipelines of 24- and
34-inch diameter pipe with a total annual capacity of 889,000 barrels per
day;
- Chicago area to Marysville segment that is a 30-inch diameter pipe with
an annual capacity of 333,000 barrels per day;
- Canadian border to Buffalo segment consisting of 12-inch diameter pipe
with an annual capacity of 74,000 barrels per day.
Estimated annual capacities noted above take into account receipt and
delivery patterns and ongoing pipeline maintenance, and reflect achievable
pipeline capacity over long periods of time. Lakehead System capacities set
forth above do not include the estimate of annual capacity upon completion of
Phase I of the Terrace Expansion Program ("Terrace") which is expected to be
completed in two stages during 1999. See "Item 7. Management's Discussion and
Analysis of Financial Condition and Results of Operations, -- Terrace Expansion
Program." Terrace will add an additional 170,000 barrels per day annual capacity
to the Lakehead System from the Canadian border to Superior. The properties
described above include facilities added during the System Expansion Program II
("SEP II") of the Lakehead System, consisting primarily of a new 24-inch
diameter pipeline from Superior to the Chicago area (approximately 450 miles).
This new pipeline, together with other pipeline system modifications, is
projected to provide approximately 170,000 barrels per day of additional
delivery capacity to the Midwest U.S. markets served by the Partnership. The new
pipeline has an ultimate potential capacity of 350,000 barrels per day through
the installation of additional pumping units. SEP II complements a Cdn. $160
million expansion of the Enbridge Pipelines System.
The Partnership believes that the Lakehead System has been constructed and
is maintained in accordance with applicable federal, state and local laws and
regulations, standards prescribed by the American Petroleum Institute and
accepted industry practice. The Partnership attempts to control corrosion of the
pipeline through the use of pipe coatings and cathodic protection systems and
monitors the integrity of the Lakehead System through a program of periodic
internal inspections using electronic instruments. On a bi-weekly basis, the
entire pipeline right of way is inspected from the air. In addition, trained and
skilled operators use computerized monitoring systems to identify pressure drops
that might indicate potential disruptions in flow, and operate remote controlled
valves and pumps that allow the Lakehead System to be shut down quickly if
required.
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TITLE TO PROPERTIES
The Partnership conducts business and owns properties located in seven
states. In general, the Lakehead System is located on land owned by others and
is operated under perpetual easements and rights of way, licenses or permits
that have been granted by private land owners, public authorities, railways or
public utilities.
The pumping stations, tanks, terminals and certain other facilities of the
Lakehead System are located on land that is owned by the Partnership, except for
five pumping stations that are situated on land owned by others pursuant to
easements or permits. An affiliate of the General Partner has acquired
properties for the benefit of the Partnership in connection with SEP II. See
"Item 13. Certain Relationships and Related Transactions." Substantially all of
the Lakehead System assets are subject to a first mortgage securing indebtedness
of the Operating Partnership.
BUSINESS RISKS
The Lakehead System is dependent upon the level of supply of crude oil and
other liquid hydrocarbons from western Canada. Supply, in turn, is dependent
upon a number of variables, one of which is the price of crude oil. In recent
months, the price of crude oil has reached a twenty year low, resulting in
reduced throughput on the System. For a discussion of the forecast of the future
supply of crude oil produced in western Canada, see "-- Supply and Demand for
Western Canadian Crude Oil."
Demand for western Canadian crude oil and NGL in the geographic areas
served by the Lakehead System is affected by the delivery of other crude oil and
refined products into the same areas. Existing pipeline capacity for the
delivery of crude oil to the Midwest U.S., the primary destination market served
by the Lakehead System, exceeds current refining capacity. The Partnership
believes that the System has certain advantages over other transporters of crude
oil with which it competes and the System is among the lowest cost transporters
of crude oil and NGL in North America based on costs per barrel mile
transported. See "-- Competition."
Enbridge Pipelines is in the process of modifying a pipeline segment from
Sarnia, Ontario to Montreal, involving a reversal of a line to bring crude oil
from Montreal to Sarnia ("Montreal Extension" or "Line 9"). The line reversal
will result in Enbridge Pipelines becoming a competitor of the Partnership for
supplying crude oil to the Ontario market which is anticipated to decrease the
level of deliveries into the Ontario market. See "Item 7. Management's
Discussion and Analysis of Financial Condition and Results of Operations,
- -- Montreal Extension Reversal."
The Partnership cannot predict the impact of future economic conditions,
fuel conservation measures, alternative fuel requirements, governmental
regulation or technological advances in fuel economy and energy generation
devices, all of which could reduce the demand for crude oil and other liquid
hydrocarbons in the areas in which deliveries are made by the Lakehead System.
In addition, reduced throughput on the System could result from testing, line
repair, reduced operating pressures, reduced crude oil supply or other causes.
The operations of the Partnership are subject to federal and state laws and
regulations relating to environmental protection and operational safety.
Although the Partnership believes that the operations of the Lakehead System are
in substantial compliance with applicable environmental and safety regulations,
risks of substantial costs and liabilities are inherent in pipeline operations,
and there can be no assurance that such costs and liabilities will not be
incurred, see "-- Environmental and Safety Regulation."
The Partnership filed a rate increase with the Federal Energy Regulatory
Commission ("FERC") in late 1998 to reflect the projected incremental costs and
throughput resulting from SEP II. A Tariff Agreement previously reached between
the Partnership and customer representatives sets forth parameters governing the
tariff increase associated with SEP II, Terrace, and other expansion projects,
although individual customers who are not parties to the agreement could
potentially challenge any existing or future rate filing. Any challenge, if
successful, could have a material adverse effect on the Partnership. For a
discussion of FERC regulation, Partnership tariff rates, and the Tariff
Agreement, see "-- Regulation" and "-- Tariffs."
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REGULATION
FERC Regulation
The Partnership's interstate common carrier pipeline operations are subject
to rate regulation by the FERC under the version of the Interstate Commerce Act
("ICA") applicable to oil pipelines. The ICA requires that petroleum products
and crude oil pipeline rates be just, reasonable and non-discriminatory. The ICA
permits challenges to new, changed and existing rates through either a "protest"
or "complaint." At the FERC, a protest normally applies only to a proposed
change in a pipeline's rates or practices and subjects the pipeline to a
forward-looking investigation and possible refund obligation if the FERC chooses
to suspend the proposed change as it is empowered to do for up to seven months
from the proposed date of the change. A complaint, by comparison, typically
applies to an existing rate or practice and subjects the pipeline, in certain
circumstances, to possible retroactive liability for past rates or practices
found to be unlawful.
The FERC utilizes a simplified ratemaking methodology for oil pipelines
that prescribes an indexing methodology for setting rate ceilings. As described
in FERC Orders No. 561 and No. 561-A, the index used is the Producer Price Index
for Finished Goods minus 1% ("PPIFG-1"). Rate ceiling levels are increased or
decreased each July 1. The PPIFG-1 for use on July 1, 1998, was approximately
negative 0.6%. Inflationary rate increases allowed under the FERC's indexing
methodology may be different than increases in the Partnership's costs. Indexed
rates are subject both to protests and to complaints, but in either case the
FERC's existing regulations specify that the party challenging a rate must show
reasonable grounds for asserting that the amount of any rate increase resulting
from application of the index is so substantially in excess of the pipeline's
increase in costs as to be unjust and unreasonable (or that the amount of any
rate decrease is so substantially less than the actual cost decrease incurred by
the pipeline that the rate is unjust and unreasonable).
The FERC has stated that, as a general rule, pipelines must utilize the
indexing methodology to change rates. However, the FERC has retained cost-based
ratemaking, market-based rates and settlements as alternatives to the indexing
approach. A pipeline can follow a cost-based approach when it can demonstrate
that there is a substantial divergence between the actual costs experienced by
the carrier and the rates resulting from application of the index. Under FERC's
cost-based methodology, crude oil pipeline rates are permitted to generate
operating revenues, based on projected volumes, not greater than the total of
the following components:
- operating expenses,
- depreciation and amortization,
- federal and state income taxes and
- an overall allowed rate of return on the pipeline's rate base.
During the period 1992 to 1995, the Partnership implemented several rate
filings in accordance with this methodology, see "-- Tariffs, -- Rate Cases." In
addition, a pipeline can charge market-based rates if it first establishes that
it lacks significant market power in a particular relevant market, and a
pipeline can establish rates pursuant to a settlement if agreed upon by all
current shippers. Initial rates for new services can be established through a
cost-based filing or through an uncontested agreement between the pipeline and
at least one shipper not affiliated with the pipeline.
Other Regulation
The governments of the United States and Canada have, by treaty, agreed to
ensure nondiscriminatory treatment with respect to the passage of oil and gas
through the pipelines of one country across the territory of the other.
Individual border crossing points require U.S. government permits that may be
terminated or amended at the will of the U.S. government. These permits provide
that pipelines may be inspected by or subject to orders issued by federal or
state government agencies.
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TARIFFS
Rate Cases
The Partnership had several rate cases pending before the FERC during the
period from 1992 to 1996. The primary issue included the applicability of the
FERC's Opinion 154-B/C trended original cost methodology. The FERC issued
decisions on the Partnership's 1992 tariff rate increase that determined the
Partnership was entitled to use the FERC's Opinion No. 154-B/C rate methodology,
although it was not entitled to recover in its cost of service a tax allowance
with respect to income attributable to individual limited partners.
In 1996, the FERC approved a settlement agreement ("Settlement Agreement")
between the Partnership, the Canadian Association of Petroleum Producers
("CAPP") and the Alberta Department of Energy ("ADOE") on all then-outstanding
contested tariff rates. The Settlement Agreement provided for a tariff rate
reduction of approximately 6% and total rate refunds and interest of $120.0
million through the effective date of October 1, 1996, with interest accruing
thereafter on the unpaid balance. The Partnership made rate refunds of $41.8
million in the fourth quarter of 1996, with the balance being paid through a 10%
reduction of tariff rates until all refunds have been made, which is expected to
occur sometime late in the second half of 1999. At December 31, 1998, the
remaining liability for rate refunds was $28.7 million.
The Settlement Agreement also provided for the terms of an incremental
tariff rate surcharge for a period of 15 years to recover the cost of, and allow
a rate of return on the Partnership's investment in, SEP II. The rate of return
on this investment will be based, in part, on the utilization level of the
additional capacity constructed. As specified in the Settlement Agreement,
higher utilization will result in a greater rate of return, subject to a minimum
and maximum rate of return of 7.5% and 15.0%, respectively. The tariff rate
surcharge will be recomputed on a cost of service basis and filed with FERC each
year. The Settlement Agreement provided that the agreed underlying tariff rates
will be subject to indexing as prescribed by FERC regulation and that CAPP and
ADOE will not challenge any rates within the indexed ceiling for a period of
five years, expiring October 2001.
Tariff Agreement
In 1998, the Partnership filed an offer of settlement ("Tariff Agreement")
with the FERC to facilitate the filing of tariff rate surcharges in late 1998
and early 1999. This filing consolidated the 1996 Settlement Agreement with
respect to SEP II and other significant agreements with customers concerning
Terrace and the transportation of heavy crude oil. The FERC found the Tariff
Agreement a reasonable compromise and approved it on the grounds that it is
fair, reasonable, and in the public interest.
With respect to Terrace, the Tariff Agreement included terms governing a
tariff surcharge associated with the project. A fixed toll increase of Cdn.
$0.05 per barrel for the movement of light crude oil from Edmonton to the
Chicago area will be allocated approximately Cdn. $0.02 ($0.013 U.S.) to the
Partnership and Cdn. $0.03 to Enbridge Pipelines. The toll increase is also
subject to increase or decrease based on changes in certain defined
circumstances. The portion of the agreement associated with Terrace also
establishes in-service and notice dates for future phases of the expansion
program. Should CAPP not provide notice to construct later phases of Terrace by
July 1, 2001, the toll increment will revert to a cost of service recovery,
including collection of both prospective and past variances between revenue
generated by the Cdn. $0.05 toll increment and the Terrace cost of service.
Other Pipeline Rate Cases
On January 13, 1999, the FERC issued an opinion and order in the Santa Fe
Pacific Pipeline, L.P. ("SFPP") case that addressed various issues of interest
to FERC-regulated publicly traded partnerships and other oil pipelines including
application of FERC's Opinion No. 154-B/C rate methodology and income tax
allowances for publicly traded partnerships. The SFPP opinion is anticipated to
have no impact on the Partnership's current rates due to the Tariff Agreement
with customers. If the SFPP opinion were applied to
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the Partnership in some future rate proceedings, the impact to the Partnership,
positive or negative, would be dependent upon the specific application of the
rulings in that opinion to the Partnership.
Many of the ratemaking issues contested in the Partnership's rate cases, in
particular the FERC's own oil pipeline ratemaking methodology, have not
previously been reviewed by a federal appellate court. Any decision ultimately
rendered by the FERC on any rate case involving its oil pipeline ratemaking
methodology, including the recent SFPP decision, may be subject to judicial
review. Any such judicial review could ultimately result in alternative
ratemaking methodologies that could have a material adverse effect on the
Partnership.
Tariffs
Under published tariffs for transportation by the Lakehead System, the
rates for light crude oil from the Canadian border near Neche to principal
delivery points at January 1, 1999 (including a tariff surcharge related to SEP
II) are set forth below. As previously discussed, the Partnership's published
tariffs are subject to a 10% reduction; the tariffs less this 10% reduction are
also set forth below.
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PUBLISHED PUBLISHED
TARIFF TARIFF PER BARREL
PER BARREL LESS 10% REDUCTION
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Clearbrook, Minnesota.............................. $0.165 $0.149
Superior, Wisconsin................................ $0.318 $0.286
Chicago, Illinois area............................. $0.647 $0.582
Canadian border near Marysville, Michigan.......... $0.747 $0.672
Buffalo, New York area............................. $0.792 $0.713
</TABLE>
The rates at January 1, 1999, for medium and heavy crude oils are higher,
while those for NGL are lower, than the rates set forth in the table to
compensate for differences in costs for shipping different types and grades of
liquid hydrocarbons. The Partnership periodically adjusts its tariff rates as
allowed under FERC's indexing methodology and the Tariff Agreement and will file
a tariff surcharge for Terrace during the first half of 1999 of an estimated
$0.013 per barrel for light crude oil to the Chicago market. See "-- Tariffs,
- -- Tariff Agreement."
DELIVERIES FROM THE LAKEHEAD SYSTEM
Deliveries from the Lakehead System are made in the Great Lakes and Midwest
regions of the United States and in Ontario, principally to refineries, either
directly or through connecting pipelines of other companies. Major refining
centers within these regions are located near Sarnia, Nanticoke, Toronto,
Minneapolis-St. Paul, Superior, Chicago, the Patoka/Wood River area, Detroit,
Toledo, and Buffalo areas. Crude oils and NGL transported by the Lakehead System
are feedstock for refineries and petrochemical plants.
The U.S. government segregates the United States into five districts,
Petroleum Administration for Defense Districts ("PADD"), for purposes of its
strategic planning to ensure crude oil supply to key refining areas in the event
of a national emergency. The oil industry utilizes these districts in reporting
statistics regarding oil supply and demand. The Lakehead System services the
northern tier of PADD 2. U.S. governmental publications project that crude oil
demand in this area will remain relatively constant. In addition, these
publications project the total supply of crude oil from producing areas in the
U.S. southwest, Rocky Mountains and Midwest that currently serve the entire PADD
2 market to decline in the near term as reserves are depleted, resulting in a
need for additional supplies of crude oil to replace the continuing demand. As a
result of these factors, the Partnership believes that the Lakehead System will
be able to maintain or exceed its current level of deliveries into PADD 2.
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The following table sets forth Lakehead System average deliveries per day
and barrel miles for each of the years in the five-year period ending December
31, 1998.
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DELIVERIES
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1998 1997 1996 1995 1994
---- ---- ---- ---- ----
(THOUSANDS OF BARRELS PER DAY)
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UNITED STATES
Light crude oil........................................ 338 282 309 345 335
Medium and heavy crude oil............................. 627 652 569 513 452
NGL.................................................... 27 26 23 18 8
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Total United States.................................... 992 960 901 876 795
----- ----- ----- ----- -----
EASTERN CANADA
Light crude oil........................................ 366 355 348 332 321
Medium and heavy crude oil............................. 97 98 102 96 108
NGL.................................................... 107 99 100 105 102
----- ----- ----- ----- -----
Total Eastern Canada................................... 570 552 550 533 531
----- ----- ----- ----- -----
TOTAL DELIVERIES......................................... 1,562 1,512 1,451 1,409 1,326
===== ===== ===== ===== =====
BARREL MILES (billions per year)......................... 391 389 384 385 366
===== ===== ===== ===== =====
</TABLE>
See "Item 7. Management's Discussion and Analysis of Financial Condition
and Results of Operations, -- Montreal Extension Reversal."
SUPPLY AND DEMAND FOR WESTERN CANADIAN CRUDE OIL
Supply
Substantially all of the shipments delivered through the Lakehead System
originate in oilfields in western Canada. The Lakehead System also receives U.S.
and Canadian production at Clearbrook through a connection with a pipeline owned
by a subsidiary of Enbridge, U.S. production at Stockbridge and Lewiston,
Michigan, and both U.S. and offshore production in the Chicago area. Changes in
supply from western Canada would directly affect movements through the Enbridge
Pipelines System and, therefore, the supply available for transportation through
the Lakehead System.
Enbridge Pipelines applied to the National Energy Board of Canada ("NEB")
in December 1997 to construct its Terrace Phase I facilities in Canada which
would complement the Terrace Phase I facilities to be constructed by the
Partnership in the United States. As part of that application, Enbridge
Pipelines submitted a forecast of supply of western Canadian crude oil and a
projection of the markets in which it could be reasonably expected to be
consumed. Forecasts by their nature are based upon numerous assumptions,
including estimates provided by industry, many of which are beyond the control
of Enbridge Pipelines or the Partnership. The forecast submitted to the NEB in
1997 showed the supply of western Canadian crude oil in the year 2003 at over
2,550,000 barrels per day, approximately 500,000 barrels per day above 1997
average daily production of western Canadian crude oil. The supply of western
Canadian crude oil was expected to remain at over 2,500,000 barrels per day
through 2010. While acknowledging the uncertainty associated with forecasts of
the supply of crude oil and other commodities shipped on the Enbridge Pipelines
System, the NEB accepted as reasonable the forecasts of the supply of crude oil
and other commodities submitted by Enbridge Pipelines and recommended that a
certificate for construction be issued. The forecast quantity of crude oil was
made subject to numerous uncertainties and assumptions, including a crude oil
price of $17.50 per barrel in 1998 rising to $22.25 in 2010.
At December 31, 1998, the benchmark West Texas Intermediate ("WTI") crude
oil price closed at $12.05 per barrel, up from the 1998 low of $10.73 per
barrel. This lower crude oil price, compared to that assumed in the 1997
forecast, has impacted the crude oil supply available in western Canada.
Enbridge Pipelines has recently completed its updated forecast of western
Canadian crude oil supply and markets for western Canadian crude oil. This
long-term outlook is partially based on supply projections from the oil sands
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projects currently operating, being expanded or proposed in western Canada. The
Partnership believes that production from these projects is less sensitive to
the price of crude oil due to the size and committed capital expenditures
involved. The updated forecast projects the supply of western Canadian crude oil
to be lower during the period 1999 through 2002 than the Terrace forecast by
approximately 120,000 to 190,000 barrels per day. The forecast supply of western
Canadian crude oil is projected to recover to 2,500,000 barrels per day in 2003,
rising to over 2,600,000 barrels per day from 2004 through 2010. The updated
forecast assumes a WTI crude oil price of $14.50 per barrel in 1999, $19.50 in
2003, and $23.00 in 2010.
As a result of the decline in crude oil prices, it is anticipated that 1999
deliveries on the Lakehead System could be approximately 50,000 to 75,000
barrels per day (on average) less than 1998 delivery levels of 1,562,000 barrels
per day, a trend which could continue into the year 2000.
Despite the downturn in crude oil prices and deliveries, the Partnership
believes that the outlook regarding future growth prospects continues to be
positive and that the potential for increased crude oil production in western
Canada remains substantial. The timing of growth in supply of western Canadian
crude oil, however, will be dependent upon recovery of crude oil prices.
Demand
Rising crude oil demand and declining inland U.S. domestic production are
contributing to an increasing need for importing crude oil into the PADD 2
market. The Partnership believes that PADD 2 will continue to provide an
excellent market for western Canadian shippers as returns to crude oil producers
are expected to remain attractive. Moreover, the Partnership believes that PADD
2 will remain the most attractive market for western Canadian supply since it is
currently the largest North American processor of western Canadian heavy crude
oil and has the greatest potential for converting refining capacity from light
to heavy crude.
Although western Canadian producers experience competition from Venezuelan
and Mexican heavy crude oil in PADD 2, western Canadian heavy crude oil is
expected to remain the dominant supply source for the region. Latin American
heavy crude oil will continue to provide the swing supply to the PADD 2 region.
In the short-term, Latin American deliveries to PADD 2 are expected to increase
due to reduced supply of western Canadian crude oil resulting from low crude oil
prices and producer returns. However, over the long-term, it is expected that
producers of Latin American heavy crude oil will concentrate on PADD 3 and PADD
5 markets, where they receive a higher return than compared to PADD 2.
Based on the recent forecast completed by Enbridge Pipelines, exports from
western Canada to the United States are forecast to increase to approximately
1,800,000 barrels per day in 2005 and remain at that level or above through
2010. This is approximately 700,000 barrels per day higher than 1997 exports. Of
the exports to the United States, PADD 2 would receive approximately 1,470,000
barrels per day in 2005, approximately 600,000 barrels per day higher than 1997.
Exports to PADD 2 would rise to approximately 1,540,000 barrels per day in 2007
and decline to approximately 1,430,000 barrels per day by 2010. Although in 1999
exports on the System to PADD 2 are anticipated to be marginally lower than
1998, recovery is expected in 2001 with long-term exports surpassing Terrace
forecast levels by 2005. Current low crude oil prices are expected to delay
supply and market growth for western Canadian crude oil by approximately one to
two years.
Deliveries to eastern Canada averaged approximately 570,000 barrels per day
in 1998. Demand in eastern Canada is expected to grow to approximately 640,000
barrels per day over the next several years. Partnership deliveries to eastern
Canada are, however, expected to decline due to the reversal of Enbridge's Line
9 from Montreal to Sarnia. See "Item 7. Management's Discussion and Analysis of
Financial Condition and Results of Operations, -- Montreal Extension Reversal."
Crude oil refineries in eastern Canada are generally configured to process
light sweet and light sour crude oil. While Canadian crude oil supplies have
increased over the last several years, the supply of conventional light sweet
and light sour crude oil in western Canada is expected to decline. Eastern
Canadian refiners cannot process significantly greater amounts of western
Canadian heavy crude oil without substantial reconfiguration of their
refineries. To the extent eastern Canadian refiners have found it difficult to
obtain light crude oil supply from western Canada at an economic price, refiners
have been recently accessing U.S. and imported
8
<PAGE> 11
light crude volumes through Lakehead System pipeline connections in the Chicago
area. Light crude oil movements originating in the Chicago area for delivery to
eastern Canada have increased from approximately 70,000 barrels per day in 1997
to approximately 110,000 barrels per day in 1998. These movements are expected
to decline following the reversal of the Enbridge's Line 9 in 1999.
CUSTOMERS
The Lakehead System operates under month-to-month transportation
arrangements with its shippers. During 1998, 48 shippers tendered crude oil and
NGL for delivery through the Lakehead System. These customers included
integrated oil companies with production facilities in western Canada and
refineries in eastern Canada, major oil companies, refiners and marketers.
Shipments by the top ten shippers during 1998 accounted for approximately 80% of
total revenues during that period. Revenue from Amoco (through affiliated
companies), Mobil Oil Company of Canada Ltd. and Imperial Oil Limited accounted
for approximately 20%, 14% and 12%, respectively, of total operating revenue
generated by the Lakehead System during 1998. The remaining shippers each
accounted for less than 10% of total revenues.
CAPITAL EXPENDITURES
In 1998, the Partnership made capital expenditures of $487.3 million, of
which $470.7 million was for its two expansion programs SEP II and Terrace and
$16.6 million was for other projects including core maintenance of $7.2 million.
See "Item 7. Management's Discussion and Analysis of Financial Condition and
Results of Operations, -- SEP II, -- Terrace Expansion Program."
TAXATION
For federal and state income tax purposes, the Partnership and Operating
Partnership are not taxable entities. Federal and state income taxes on
Partnership taxable income are borne by the individual partners through the
allocation of Partnership taxable income. Such taxable income may vary
substantially from net income reported in the statement of income.
COMPETITION
Because pipelines are the lowest cost method for intermediate and long haul
movement of crude oil over land, the System's most significant existing
competitors for the transportation of western Canadian crude oil are other
pipelines. In 1998 the Enbridge Pipelines System transported approximately 65%
of total western Canadian crude oil production, of which more than 90% was
transported by the Lakehead System. The remainder of 1998 western Canadian crude
oil production was refined in Alberta or Saskatchewan or transported through
other pipelines. Of the pipelines transporting western Canadian crude oil out of
Canada, the System provides approximately 70% of the total pipeline design
capacity. The remaining 30% of design capacity is shared by five other pipelines
transporting crude oil to British Columbia, Washington, Montana and other states
in the Northwest U.S.
Competition among common carrier pipelines is based primarily on
transportation charges, access to producing areas and proximity to end users.
The Partnership believes that high capital requirements, environmental
considerations and the difficulty in acquiring rights of way and related permits
make it difficult for a competing pipeline system comparable in size and scope
to the System to be built in the foreseeable future.
Express Pipeline Ltd. ("Express Pipeline"), a joint venture between Alberta
Energy Company, Ltd. and TransCanada PipeLines Limited, owns and operates a
170,000 barrel per day capacity pipeline that carries western Canadian crude oil
to the U.S. Rocky Mountain region, where it connects to a 150,000 barrels per
day capacity pipeline system. This connecting pipeline serves the Patoka/Wood
River market area. Express Pipeline began service in early 1997. The General
Partner believes, however, that the System is more attractive to western
Canadian producers shipping to the Chicago or Patoka/Wood River market area as
it offers lower tolls and shorter transit times than Express Pipeline and does
not require shipper volume commitments as currently required by Express
Pipeline.
9
<PAGE> 12
The System encounters competition in serving shippers to the extent that
shippers have alternate opportunities for transporting liquid hydrocarbons from
their sources to customers. In selecting the destination for their supplies of
crude oil, sellers generally desire to use the alternative that results in the
highest return to them. Generally, it is expected that sellers will receive the
highest return from markets served by the System, but alternate markets may, for
periods of time, offer equal or better returns for the seller. Such markets
could potentially include the U.S. Rocky Mountain region for sweet crude oil and
the Washington State market for light sour crude oil.
In the United States, the Lakehead System encounters competition from other
crude oil and refined product pipelines and other modes of transportation
delivering crude oil and refined products to the refining centers of
Minneapolis-St. Paul, Chicago, Detroit and Toledo and the refinery market and
pipeline hub located in the Patoka/Wood River area. The Lakehead System
transports approximately 45% of all crude oil deliveries into the Chicago area,
approximately 75% of all crude oil deliveries into the Minneapolis-St. Paul area
and virtually all deliveries of crude oil to Ontario.
Please refer to "Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations, -- Montreal Extension Reversal," for
discussion of a planned reversal of the Montreal Extension that will result in
Enbridge Pipelines becoming a competitor of the Lakehead System for supplying
crude oil to the Ontario market.
ENVIRONMENTAL AND SAFETY REGULATION
General
The operations of the Partnership are subject to federal, state and local
laws and regulations relating to protection of the environment and safety.
Although the Partnership believes that the operations of the Lakehead System are
in substantial compliance with applicable environmental and safety laws and
regulations, the risk of substantial liabilities are inherent in pipeline
operations, and there can be no assurance that substantial liabilities will not
be incurred. To the extent that the Partnership is unable to recover
environmental costs in its rates or through insurance, the Partnership could be
subject to material costs.
In general, the Partnership expects to incur future ongoing expenditures to
comply with industry and regulatory environment and safety standards. Such
expenditures cannot be accurately estimated at this time, although the
Partnership does not expect that they will have a material adverse effect on the
Partnership.
Air
The operations of the Partnership are subject to the federal Clean Air Act
and comparable state statutes.
Water
The federal Water Pollution Control Act, as amended by the Oil Pollution
Act of 1990 ("WPCA"), imposes strict controls on the discharge of oil into
navigable waters. The WPCA provides penalties for any discharges of petroleum
products in reportable quantities, imposes liability for clean-up costs and
natural resource damage, and allows for third party lawsuits. State laws also
provide varying civil and criminal penalties and liabilities in the case of a
release of petroleum into surface water or groundwater. Spill prevention control
and countermeasure requirements of federal laws require diking and similar
structures to help prevent contamination of navigable waters in the event of a
petroleum overflow, rupture or leak. In response to regulations mandated by the
WPCA, the Partnership has submitted to the Office of Pipeline Safety ("OPS") of
the U.S. Department of Transportation ("DOT") oil spill emergency response
plans, which have been approved, and a certification that it has the resources
to respond to a worst case spill. Expenses of routine compliance with these and
other similar regulations are not expected to have a material adverse impact on
the Partnership.
10
<PAGE> 13
Remediation Matters
Contamination resulting from spills of crude oil and petroleum products is
not unusual within the petroleum pipeline industry. Historic spills along the
Lakehead System as a result of past operations may have resulted in soil or
groundwater contamination. The Partnership is addressing known sites through
monitoring and remediation programs.
Superfund
The Comprehensive Environmental Response, Compensation and Liability Act of
1989, as amended, also known as "Superfund," and comparable state laws impose
liability, without regard to fault or the legality of the original act, on
certain classes of persons that contributed to the release of a "hazardous
substance" into the environment. In the course of its ordinary operations, the
Lakehead System generates wastes, some of which fall within the federal and
state statutory definitions of a "hazardous substance" and some of which were
historically disposed of at sites that may require cleanup under Superfund and
related state statutes.
Waste
The Partnership generates hazardous and nonhazardous solid wastes that are
subject to requirements of the federal Resource Conservation and Recovery Act
and comparable state statutes. The Partnership believes that operations of the
Lakehead System are in substantial compliance with such statutes in all states
in which it operates. The Environmental Protection Agency ("EPA") is currently
in the process of developing stricter disposal standards for nonhazardous waste.
Safety Regulation
The Partnership's operations are subject to construction, operating and
safety regulation by the DOT and various other federal, state and local
agencies. The Pipeline Safety Act of 1992, as amended by the Accountable
Pipeline Safety and Partnership Act of 1996, requires the OPS to consider
environmental impacts and do a risk assessment, as well as satisfy its
traditional public safety mandate, when developing pipeline safety regulations.
The Act also mandates the OPS to establish pipeline operator qualification
rules, requires pipeline operators to provide maps and records to the OPS, and
authorizes the OPS to require pipelines to be modified to accommodate internal
inspection devices. Regulations issued pursuant to the Act require pipeline
operators to implement drug and alcohol testing programs for employees and
contractors that are engaged in safety-sensitive activities. Additional
legislation or regulations have been proposed requiring remotely controlled
shutoff valves in populated or environmentally sensitive areas, increased public
education of pipeline safety and accident prevention and periodic integrity
testing of pipelines by internal inspection or hydrostatic testing. The
Partnership currently has an integrity testing program utilizing internal
inspection devices and has conducted additional hydrostatic testing for selected
segments of the Lakehead System. The Partnership is also subject to the
requirements of federal and state Occupational Safety and Health Acts.
EMPLOYEES
Neither the General Partner nor the Partnership has any employees. The
General Partner is responsible for the management and operation of the
Partnership and to fulfill these obligations, it has entered into agreements
with Enbridge and certain of its subsidiaries to provide the required services.
The Partnership reimburses the General Partner or its affiliates for expenses
incurred in performing these services at cost.
ITEM 3. LEGAL PROCEEDINGS
The Partnership is a defendant in various lawsuits and a party to various
legal proceedings arising in the ordinary course of business. Some of these
lawsuits and proceedings are covered, in whole or in part, by insurance. The
Partnership believes that the outcome of all these lawsuits and proceedings will
not, individually or in the aggregate, have a material adverse effect on the
financial condition of the Partnership. In connection with the transfer of its
pipeline business to the Partnership, the General Partner agreed to indemnify
the Partnership from and against substantially all liabilities, including
liabilities relating to
11
<PAGE> 14
environmental matters, arising from operations prior to the transfer. This
indemnification does not apply to amounts that the Partnership would be able to
recover in its tariffs, through insurance, or to any liabilities relating to a
change in laws after December 27, 1991.
In late July 1998, the Partnership's directional drilling operations for
SEP II construction caused a discharge of non-hazardous bentonite drilling mud
in a wetlands area. The Partnership does not believe that any penalties that
might be assessed by the EPA will have a material impact on the financial
condition of the Partnership. The State of Illinois is pursuing an action
relating to this discharge under Natural Resource Damage Assessment regulations
of the Clean Water Act to seek compensation for damage to the wetlands area. It
is expected that a settlement will be reached with the State to resolve the
matter and that it will not have a material impact on the financial condition of
the Partnership.
In a letter dated August 19, 1998, the Illinois Attorney General informed
the Partnership that it is seeking a penalty of $135,000 for a May 28, 1998,
release of crude oil caused by a third party in Orland Park, Illinois. The
Partnership and the Attorney General are in negotiations on this matter.
The Partnership received a Notice of Violation, dated October 29, 1998,
from the Wisconsin Department of Natural Resources ("Wisconsin DNR") that
alleges the Partnership failed to monitor discharges of water from SEP II
construction trenches on certain occasions and exceeded the effluent limitations
set forth in a permit The Partnership has submitted its reply to the notice and
intends to cooperate with the Wisconsin DNR in an effort to resolve the issue
and any penalties that may ensue. It is not anticipated that any penalty will
have a material impact on the financial condition of the Partnership.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
No matters were submitted to a vote of security holders during the fourth
quarter of 1998.
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
The Partnership's Class A Common Units are listed and traded on the New
York Stock Exchange, the principal market for the Class A Common Units, under
the symbol LHP. The quarterly price range per Class A Common Unit and cash
distributions paid per unit for 1998 and 1997 are summarized below:
<TABLE>
<CAPTION>
FIRST SECOND THIRD FOURTH
----- ------ ----- ------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
1998 QUARTERS
High............................................... $ 46 3/4 $ 49 15/16 $ 52 7/16 $ 54
Low................................................ $ 43 $ 44 5/16 $ 46 11/16 $ 46 3/4
Cash distributions paid............................ $0.78 $0.86 $0.86 $0.86
</TABLE>
<TABLE>
<CAPTION>
FIRST SECOND THIRD FOURTH
----- ------ ----- ------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
1997 QUARTERS
High............................................... $ 38 3/4 $ 39 $ 47 3/4 $ 47 7/8
Low................................................ $ 33 $ 33 7/8 $ 38 $ 38 3/8
Cash distributions paid............................ $0.68 $0.68 $0.78 $0.78
</TABLE>
On March 1, 1999, the last reported sales price of the Class A Common Units
on the New York Stock Exchange was $43 5/16. At March 1, 1999, there were
approximately 39,000 Class A Common Unitholders of which there were
approximately 3,600 registered Class A Common Unitholders of record. There is no
established public trading market for the Partnership's Class B Common Units,
all of which are held by the General Partner.
12
<PAGE> 15
ITEM 6. SELECTED FINANCIAL DATA
The following table sets forth, for the periods and at the dates indicated,
summary historical financial and operating data for the Partnership. The table
is derived from the consolidated financial statements of the Partnership and
notes thereto, and should be read in conjunction with those audited financial
statements.
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
--------------------------------------------------------
1998 1997 1996(1) 1995(1) 1994
---- ---- ------- ------- ----
(DOLLARS IN MILLIONS, EXCEPT PER UNIT AMOUNTS)
<S> <C> <C> <C> <C> <C>
INCOME STATEMENT DATA:
Operating revenue........................... $ 287.7 $ 282.1 $ 274.5 $ 268.5 $ 246.0
Operating expenses(2)....................... 182.3 174.0 187.1 195.2 159.7
-------- -------- -------- -------- --------
Operating income............................ 105.4 108.1 87.4 73.3 86.3
Interest and other income................... 6.0 9.7 9.6 7.1 4.1
Interest expense............................ (21.9) (38.6) (43.9) (40.3) (29.8)
Minority interest........................... (1.0) (0.9) (0.7) (0.5) (0.7)
-------- -------- -------- -------- --------
Net income.................................. $ 88.5 $ 78.3 $ 52.4 $ 39.6 $ 59.9
======== ======== ======== ======== ========
Net income per unit(3)...................... $ 3.07 $ 3.02 $ 2.11 $ 1.60 $ 2.61
======== ======== ======== ======== ========
Cash distributions paid per unit............ $ 3.36 $ 2.92 $ 2.60 $ 2.56 $ 2.51
======== ======== ======== ======== ========
FINANCIAL POSITION DATA (AT YEAR END):
Property, plant and equipment, net.......... $1,296.2 $ 850.3 $ 763.5 $ 725.1 $ 727.6
Total assets................................ $1,414.4 $1,063.2 $ 975.9 $ 915.2 $ 868.6
Long-term debt.............................. $ 814.5 $ 463.0 $ 463.0 $ 395.0 $ 364.0
Partners' capital
Class A Common Unitholder................ $ 453.4 $ 461.6 $ 376.3 $ 387.9 $ 409.3
Class B Common Unitholder................ 37.3 36.7 21.7 21.7 23.5
General Partner.......................... 4.3 3.5 1.6 1.5 1.6
-------- -------- -------- -------- --------
$ 495.0 $ 501.8 $ 399.6 $ 411.1 $ 434.4
======== ======== ======== ======== ========
CASH FLOW DATA:
Cash provided from operating activities..... $ 103.6 $ 106.6 $ 93.9 $ 121.5 $ 108.1
Cash used in investing activities........... $ (427.9) $ (101.7) $ (84.7) $ (54.0) $ (102.7)
Cash provided from (used in) financing
activities............................... $ 252.7 $ 24.1 $ 3.4 $ (32.5) $ 27.7
Capital expenditures included in investing
activities............................... $ (487.3) $ (126.9) $ (76.7) $ (35.5) $ (136.9)
OPERATING DATA:
Barrel miles (billions)..................... 391 389 384 385 366
Deliveries
(thousands of barrels per day)
United States............................ 992 960 901 876 795
Eastern Canada........................... 570 552 550 533 531
-------- -------- -------- -------- --------
1,562 1,512 1,451 1,409 1,326
======== ======== ======== ======== ========
</TABLE>
- ---------------
(1) 1996 results reflect the impact of the Settlement Agreement between the
Partnership and customer representatives on all outstanding contested tariff
rates. 1995 results reflect the impact of a June 1995 FERC decision.
(2) Operating expenses include provisions for prior years' rate refunds of $20.1
million and $22.9 million in 1996 and 1995, respectively.
(3) The General Partner's allocation of net income has been deducted before
calculating net income per unit as follows: 1998, $8.0 million; 1997, $4.4
million; 1996, $1.6 million; 1995, $1.2 million; and 1994, $1.4 million.
13
<PAGE> 16
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
1998 was a successful year for the Partnership as record net income and
crude oil deliveries were achieved despite a decline in world crude oil prices.
The strong performance of the Partnership during 1998, coupled with expectations
for strong long-term performance, influenced the Board of Directors of the
General Partner to increase the quarterly cash distribution on April 16, 1998 to
$0.86 per unit ($3.44 on an annualized basis) from $0.78 per unit. This most
recent increase in the distribution is primarily the result of earnings growth
from capacity expansions.
Challenges encountered by the Partnership during construction of the $450
million System Expansion Program II ("SEP II") were overcome and the targeted
completion date of first quarter 1999 was met. During December 1998, the process
of filling the new pipeline with crude oil was begun and deliveries from the new
line will commence in March 1999. A tariff increase associated with the new line
was filed with the Federal Energy Regulatory Commission ("FERC") in late
December and became effective on January 1, 1999. See "-- SEP II".
The Partnership, together with Enbridge Pipelines Inc., of Edmonton,
Alberta, ("Enbridge Pipelines" formerly Interprovincial Pipe Line Inc.), began
construction of the first phase of the Terrace Expansion Program ("Terrace") in
1998. Terrace is a multi-phase program that will eventually add approximately
350,000 barrels per day of pipeline system delivery capability with the first
phase of 170,000 barrels per day expected to be operational by September 1999.
The remaining capacity may be added at customer request in stages over the next
several years. See "-- Terrace Expansion Program".
Deliveries by the Partnership of crude oil and natural gas liquids ("NGL")
increased 3% over the previous record levels attained in 1997. In late 1998, the
Partnership began experiencing a decline in the level of crude oil deliveries
compared with the first half of 1998. Producers of crude oil throughout North
America began reducing production of less profitable crude oil due to the
significant drop in world crude oil prices. At December 31, 1997, the benchmark
West Texas Intermediate ("WTI") crude oil price was $17.83 per barrel. At
December 31, 1998 the reference WTI price closed at $12.05 per barrel, up from
the 1998 low of $10.73.
While utilization of the Partnership's pipeline system historically has
been fairly insensitive to modest changes in the price of crude oil, the current
world crude oil price situation is anticipated to impact the supply of available
crude oil and the Partnership's short-term results. Despite this forecast
decrease in crude oil deliveries, the Partnership anticipates generating more
than sufficient cash from operating activities to continue its current level of
distribution through 1999. See "-- Future Prospects."
RESULTS OF OPERATIONS
Net income for 1998 was $88.5 million ($3.07 per unit) compared with $78.3
million ($3.02 per unit) for 1997 and $52.4 million ($2.11 per unit) for 1996.
Net income for 1996 was impacted by rate refunds ($20.1 million) and related
interest expense ($3.2 million) attributable to prior years recorded in response
to a settlement agreement (the "Settlement Agreement") between the Partnership
and certain customer representatives that concluded a dispute that began in 1992
concerning the Partnership's tariff rates. See "Items 1 & 2. Business and
Properties, -- Tariffs, -- Rate Cases."
Crude oil and NGL deliveries averaged a record 1,562,000 barrels per day in
1998, up from the 1,512,000 barrels per day averaged during 1997, a 3% growth in
Lakehead System deliveries. Crude oil and NGL deliveries increased 4% during
1997 when compared with 1996 results. Over the three-year period, increased
deliveries resulted from greater crude oil production in western Canada,
increased transportation of foreign and U.S. crude received in the Chicago area,
combined with increased pipeline capacity from the Partnership's expansion
programs. System utilization measured in barrel miles was relatively unchanged
over the three year period due to shorter average length of haul.
Net income for 1998 was $10.2 million higher than net income in 1997
primarily due to increased operating revenue and lower interest expense
partially offset by higher operating expenses and lower interest and other
income. Net income per unit increased $0.05 due to the increase in net income
despite a greater number of weighted average units outstanding during 1998
compared with 1997 and additional incentive
14
<PAGE> 17
income allocations to the General Partner related to the achievement of certain
target cash distribution levels. See Note 3 to the Partnership's consolidated
financial statements. Weighted average units outstanding increased in 1998 due
to the full year impact of the October 1997 Class A Common Unit offering.
Net income in 1997 improved $25.9 million in comparison with 1996. A 1996
non-recurring charge of $20.1 million related to prior years' rate refunds
required under the Settlement Agreement together with a related interest accrual
of $3.2 million accounts for a majority of the increase. In addition, a
combination of higher operating revenue and lower interest expense, partially
offset by higher operating expenses, led to the increase in net income. Per unit
amounts increased significantly primarily due to increased net income.
Operating revenue for 1998 was $287.7 million, or $5.6 million greater than
operating revenue for 1997. The increase was primarily due to increased
deliveries and the full year impact of a July 1, 1997, tariff increase of 1.6%,
partially offset by a 0.6% tariff decrease on July 1, 1998, as required under
the FERC's indexing methodology and an increase in the proportion of heavy crude
oil deliveries (up 9% to 625,000 barrels per day). The Partnership's current
tariff rate for medium and heavy crude oil deliveries to the Chicago area is
approximately 7% and 20% higher, respectively, than that for lighter crude oils.
The positive impact of increased deliveries and heavier crude oil mix were
somewhat offset by a decreased average length of haul (686 miles in 1998 versus
704 miles in 1997). Average length of haul decreased due to increased receipt of
crude oil in the Chicago area from U.S. and foreign sources for delivery to
markets east of Chicago including eastern Canada.
Operating revenue for 1997 was $282.1 million, or $7.6 million greater than
1996 primarily due to increased deliveries and the transportation of a greater
proportion of heavy crude oil (up 22% to 573,000 barrels per day). Operating
revenue was also favorably impacted by the full year impact of a July 1996
tariff rate increase of 0.9%, and an additional 1.6% on July 1, 1997. Operating
revenue for 1996 reflects tariff rates implied in the Settlement Agreement.
Total operating expenses of $182.3 million in 1998 were $8.3 million
greater than 1997 primarily due to higher power costs associated with increased
deliveries, and a heavier crude oil mix. Operating and administrative costs
increased $3.9 million primarily due to increased rents for rights-of-way as a
result of the renewal of certain lease agreements that expired during the year,
and higher maintenance costs associated with an increased level of internal
pipeline inspection. Depreciation expense increased due to the growth in
property, plant and equipment.
Total 1997 operating expenses were $13.1 million less than 1996 primarily
due to the absence of a $20.1 million provision for prior years' rate refunds
recorded in 1996. The decrease in total operating expenses was somewhat offset
by higher power costs associated with a heavier crude oil mix and increased
deliveries. Operating and administrative expenses increased largely due to
higher property taxes. Depreciation expense for 1997 increased due to growth in
property, plant and equipment, somewhat offset by the impact of revised
depreciation rates that became effective on July 1, 1996. The depreciation rates
were revised to better represent the expected service life of the pipeline
system.
Interest expense of $21.9 million in 1998 decreased $16.7 million from 1997
largely due to the capitalization of interest costs associated with SEP II and
Terrace as part of the costs of constructing the assets. Capitalized interest
reflects the Partnership's average cost of debt, of approximately 7.8%, and the
average level of funds invested in construction. Capitalized interest increased
due to the significant construction projects ongoing during 1998. Interest
expense is further decreased due to the utilization of the Partnership's cash
balances to finance a portion of the capital expenditures rather than issuing
additional debt or equity. Interest capitalization generally ceases once a
capital project is complete and ready for service. Interest paid increased to
$44.4 million in 1998 from $39.9 million paid in 1997 primarily due to greater
borrowing on the Partnership's revolving credit facility.
Interest expense for 1997 decreased $5.3 million from 1996 due to lower
balances and interest rates with respect to rate refunds payable, and increased
capitalized interest attributable to greater construction work in process during
1997. These changes were partially offset by additional interest on greater
average borrowings in 1997 under the Partnership's credit facility.
15
<PAGE> 18
LIQUIDITY AND CAPITAL RESOURCES
At December 31, 1998, cash, cash equivalents and short-term investments
totaled $47.0 million, down $125.5 million since December 31, 1997. In keeping
with the Partnership's financing plans for SEP II and Terrace, existing cash
balances were used to partially finance the expansion programs. Of this $47.0
million, $24.7 million ($0.86 per unit) was set aside for the cash distribution
paid on February 12, 1999, with the remaining $22.3 million available for
capital expenditures and other business needs.
Cash generated from operating activities in 1998 decreased marginally by
$3.0 million from 1997 to $103.6 million, as the impact of higher net income was
offset by changes in working capital requirements. Cash generated from operating
activities in 1997 increased $12.7 million from 1996 to $106.6 million primarily
due to higher net income, partially offset by the reduction in liability for
accrued rate refunds.
In response to the October 1996 Settlement Agreement, the Partnership made
rate refunds of $28.5 million in 1998 and $27.7 million in 1997 with the
remaining balance continuing to be repaid through a 10% reduction of tariff
rates. This reduction will continue until all refunds have been made. Based on
the $28.7 million remaining balance at December 31, 1998, and projected pipeline
system deliveries, the 10% reduction is expected to remain effective until
sometime late in the second half of 1999.
In 1998, the Partnership made capital expenditures of $487.3 million, of
which $358.0 million were for SEP II, $112.7 million were for Terrace, and $16.6
million were for other projects. With $450.0 million of capital expenditures
having been incurred or committed on SEP II through December 31, 1998, the
project is largely complete except for minor restoration and clean-up work and
the finalization of rights-of-way costs in 1999. In 1997, the Partnership made
capital expenditures of $126.9 million, including $84.9 million for SEP II and
$42.0 million for other projects.
The first phase of the Terrace expansion is largely complete and capital
expenditures are anticipated to total approximately $138.0 million. In addition
to Terrace, the Partnership anticipates spending approximately $8.2 million for
pipeline system enhancements and $13.5 million for core maintenance activities
in 1999. See "-- Future Prospects, -- Lakehead System Expansion Projects."
Excluding future phases of Terrace, ongoing capital expenditures are
expected to average $10 to $20 million on an annual basis (approximately 50% for
enhancement and 50% for core maintenance of the pipeline system). Core
maintenance activities, such as the replacement of equipment and preventive
maintenance programs, are expected to be undertaken to enable the Partnership's
pipeline system to continue to operate at its maximum operating capacity.
Enhancements to the pipeline system, such as renewal and replacement of pipe,
are expected to extend the life of the Lakehead System and permit the
Partnership to respond to developing industry and government standards and the
changing service expectations of its customers.
On an annual basis the Partnership makes expenditures of a capital and
operating nature related to maintaining compliance of the Lakehead System with
applicable environmental and safety regulations. Capital expenditures for safety
and environmental purposes comprise a portion of the routine core maintenance
and enhancement capital expenditures annually incurred by the Partnership.
Amounts are not readily segregated since individual projects may be undertaken
for a variety of reasons in addition to environment and safety considerations.
Future environment and safety expenditures are not anticipated to be material in
relation to the Partnership's results of operations.
At December 31, 1998, the Partnership had $310.0 million aggregate
principal amount of First Mortgage Notes outstanding that bear interest at the
rate of 9.15% per annum, payable semi-annually. The notes are due and payable in
ten equal annual installments beginning in the year 2002. During 1998, the
Partnership increased the size of its $205.0 million Revolving Credit Facility
to $350 million. Total borrowings under the facility of $305.0 million were
outstanding at December 31, 1998. Interest rates on this facility are variable
and currently approximate 6%.
During the third quarter of 1998, the Board of Directors of the General
Partner approved a $200 million uncommitted lending facility from the General
Partner to the Partnership. This uncommitted facility provided
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<PAGE> 19
an alternative source of funds at market interest rates in the event that a
disruption in the capital markets delayed anticipated debt and equity issuances.
In late September 1998, the Partnership borrowed, and subsequently repaid in
early October, $37.0 million under this arrangement.
In October 1998, pursuant to a $400 million shelf registration statement
filed with the Securities and Exchange Commission ("SEC"), $200 million face
amount of senior unsecured notes were issued to retire borrowings under the
Revolving Credit Facility and to repay the loan of $37 million issued by the
General Partner. The Partnership issued the senior unsecured notes in two
tranches of $100 million, each, with maturities of 2018 (with an interest rate
of 7%) and 2028 (with an interest rate of 7.125%), respectively. For additional
details relating to the Partnership's debt, see Note 6 to the Partnership's
Consolidated Financial Statements.
In October 1997, the Partnership issued 2.2 million Class A Common Units.
Net proceeds from the offering, including the General Partner's contribution,
were $99.2 million. This offering increased the number of Class A Common Units
outstanding to 22,290,000. Proceeds from this offering were used to finance a
portion of SEP II. For additional information regarding the 1997 equity offering
and Partnership organization, see Note 1 to the Partnership's Consolidated
Financial Statements. During the fourth quarter of 1998, the Partnership filed a
$200 million shelf registration statement with the SEC for the issuance of
additional Class A Common Units. As of December 31, 1998, no Class A Common
Units have been issued under this registration statement.
Distributions paid to partners during 1998 increased $20.0 million to $95.3
million ($3.36 per unit). Distributions increased as a result of the increase in
the quarterly distribution to $0.86 per unit from $0.78 per unit declared in
April 1998, the issuance of 2.2 million Class A Common Units in 1997, and
increased incentive distributions paid to the General Partner as a result of
higher levels of cash distributions per unit. Distributions paid to partners for
1997 increased $11.4 million to $75.3 million ($2.92 per unit) compared to 1996.
The Partnership distributes quarterly all of its Available Cash, which is
generally defined to mean, with respect to any calendar quarter, the sum of all
of the cash receipts of the Partnership plus net reductions to reserves less all
of its cash disbursements and net additions to reserves. These reserves are
retained to provide for the proper conduct of the Partnership's business, to
stabilize distributions of cash to Unitholders and the General Partner and as
necessary to comply with the terms of any agreement or obligation of the
Partnership. On February 12, 1999, the Partnership paid a $0.86 per unit
distribution related to the fourth quarter of 1998.
The Partnership anticipates that it will continue to have adequate
liquidity to fund future recurring operating, investing and financing
activities. The Partnership intends to fund Terrace, remaining SEP II
expenditures, and ongoing capital expenditures with the proceeds from future
debt and equity offerings, other borrowings, cash generated from operating
activities, and existing cash, cash equivalents and short-term investments. Cash
distributions are expected to be funded with internally generated cash. The
Partnership's ability to make future debt and equity offerings will depend on
prevailing market conditions and interest rates and the then-existing financial
condition of the Partnership.
FUTURE PROSPECTS
Income and cash flows of the Partnership are sensitive to oil industry
supply and demand in Canada and the United States, and the regulatory
environment. As the Partnership's pipeline system is operationally integrated
with the Enbridge Pipelines System in western Canada, the Partnership's revenues
are dependent upon the utilization of the Enbridge Pipelines System by producers
of western Canadian crude oil. The Partnership believes long-term demand for its
pipeline system will continue in light of industry's increasing production
forecasts for western Canadian crude oil and anticipated increased demand for
crude oil in the Midwest U.S. See "Items 1 & 2. Business and
Properties, -- Supply and Demand for Western Canadian Crude Oil."
In late 1998, representatives of the Canadian Association of Petroleum
Producers ("CAPP") and the Partnership concluded informal discussions concerning
the projected supply of western Canadian crude oil and
17
<PAGE> 20
NGL available for delivery during 1999. Based on these discussions, and as a
result of the general decline in crude oil prices, it is anticipated that
deliveries on the Partnership's pipeline system could be approximately 50,000 to
75,000 barrels per day (on average) less than 1998 delivery levels of 1,562,000
barrels per day. At this potential level of utilization, the Partnership will
earn a 7.5% nominal rate of return on its SEP II equity investment during 1999,
the minimum prescribed in tariff agreements reached with a majority of the
Partnership's customers. See "Items 1 & 2. Business and
Properties, -- Regulation, -- Tariffs."
The collective impact of reduced deliveries and a 7.5% rate of return on
SEP II equity is anticipated to result in net income for 1999 of approximately
$80 to $90 million. Based on current projections, the Partnership anticipates
generating sufficient cash from operating activities to continue its current
level of cash distribution through 1999. Despite the recent weakness in crude
oil prices, the Partnership's outlook regarding future growth prospects remains
positive. While the availability of western Canadian crude oil is sensitive to
the long-term outlook for crude oil prices, the Partnership believes that recent
announcements by major Canadian oil producers affirming oil sands development
and other long-term expansion projects is encouraging and illustrative of
long-term supply growth from the western Canadian sedimentary basin.
The Lakehead and Enbridge Pipelines Systems (the "System") serve as a
strategic link between the western Canadian oil fields and the markets of the
Midwest U.S. and eastern Canada and have for the last several years operated at
or near capacity. In response to a long-term trend of increasing supply of crude
oil from western Canada and the growth of demand in the markets of the Midwest
U.S., the Partnership plans not only to maintain the service capability of the
existing Lakehead System but also to expand its capacity where appropriate. This
is consistent with the Partnership's principal business objective to increase
cash generated from its operations to enhance cash distributions. This strategy
has enabled the Partnership to increase quarterly cash distributions to Common
Unitholders from $0.59 per unit in 1992 to $0.86 per unit currently.
Lakehead System Expansion Projects
Key current and future expansion projects of the Partnership are summarized
below:
- SEP II -- This expansion was largely completed in early 1999. SEP II
involved the construction of a new pipeline from the Partnership's
pipeline terminal at Superior, Wisconsin, to its Chicago, Illinois,
market area. The pipeline is expected to provide an additional 170,000
barrels per day of delivery capacity on the Lakehead System. Under a
tariff agreement with its customers ("Tariff Agreement"), a tariff
surcharge has been implemented that recovers the costs of, and return on,
the SEP II facilities. The Tariff Agreement allows the Partnership to
earn a return on its SEP II equity investment based on the benchmark
National Energy Board of Canada ("NEB") multi-pipeline rate of return.
Under the Tariff Agreement, return on SEP II equity can range from a
minimum equivalent to the NEB multi-pipeline rate of return less 3%
(subject to a 7.5% floor) to a maximum of the multi-pipeline rate of
return plus 3% (subject to a 15% ceiling). Rate of return on equity
within the range is determined by measuring SEP II capacity utilization
on the Enbridge Pipelines System in Canada. See "Items 1 & 2. Business
and Properties, -- Regulation, -- Tariffs."
- Terrace Expansion Program -- This expansion program, which is being
undertaken by the Partnership in conjunction with Enbridge Pipelines, is
a phased expansion that is expected to ultimately provide an additional
520,000 barrels per day of heavy crude oil capacity for western Canadian
producers seeking greater access to Midwest U.S. markets. Subject to
continued industry support, customer requirements and receipt of
regulatory approvals, the General Partner and Enbridge Pipelines
anticipate that this expansion program will be completed in stages
beginning in 1999. Phase I of Terrace includes construction of new
36-inch diameter pipeline facilities from Kerrobert, Saskatchewan, to
Clearbrook, Minnesota. The new pipeline will join existing 48-inch
diameter pipeline loops between Kerrobert and Clearbrook, creating
another separate pipeline joining those locations. Phase I is expected to
provide an initial 95,000 barrels per day increase in capacity in the
first half of 1999, rising to 170,000 barrels per day by September 1999.
Phase I construction is expected to cost the Partnership approximately
$138 million for construction of facilities in the U.S., and Enbridge
Pipelines Cdn. $610 million for construction of facilities in Canada.
Subsequent phases of Terrace are dependent upon customer
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<PAGE> 21
requirements and, if completed, are expected to provide up to 350,000
barrels per day of added heavy crude oil capacity in addition to the
170,000 barrels per day to be provided by Phase I. Subject to completion
of all phases, and after allowing for anticipated declines in light crude
oil production, total System delivery capability is expected to increase
by 350,000 barrels per day. A tariff surcharge for Terrace of
approximately $0.013 per barrel (for light crude oil to Chicago) is
anticipated to be filed in the first half of 1999. This tariff surcharge
is premised on the completion of Phase 2 and Phase 3 of Terrace. Should
these later phases not proceed, the Partnership will be allowed to
increase its tariff surcharge on a cost of service basis to allow
recovery of, and return on, its Phase I Terrace investment including any
revenue variances between the application of the toll increment and
annual Terrace cost of service. See "Items 1 & 2. Business and
Properties, -- Regulation, -- Tariffs."
The Partnership is subject to a rate regulatory methodology that prescribes
rate ceilings that are adjusted each July 1. The rate ceilings are adjusted by
reference to annual changes in the Producer Price Index for Finished Goods minus
one percent ("PPIFG-1"). The General Partner expects the PPIFG-1 to decrease
approximately 1.9% for 1998. This decrease in the PPIFG-1 should not have a
material effect on 1999 operating revenue since the decrease does not apply to
SEP II or Terrace tariff surcharges and will be effective mid-year 1999. To
date, the Partnership has been able to manage its pipeline system to ensure
inflationary cost pressures in excess of the PPIFG-1 have not materially
impacted net income. The FERC is scheduled to review the appropriateness of the
indexing methodology, and specifically the PPIFG-1 index, in year 2000.
The indexed rate environment, the Settlement Agreement, and other
negotiated settlements with customers for SEP II and Terrace are benefiting the
Partnership and its customers by restoring stability and providing predictable
tariff rates. Customer representatives who are a party to the various agreements
have agreed not to challenge any rates within the indexed ceiling until October
2001. In addition, to the extent allowed under FERC orders or by agreement with
customers, the Partnership has filed, and will continue to file, for additional
tariff increases from time to time to reflect ongoing expansion programs.
Enbridge Inc. Projects
Enbridge Inc. ("Enbridge" formerly IPL Energy Inc.) the ultimate parent of
the General Partner, is also engaged in North American crude oil pipeline
projects which are related to the Enbridge Pipelines and Lakehead Systems. The
General Partner believes that certain of these projects are complementary to
ongoing and future expansion projects even though they are not owned by the
Partnership, since the projects may result in increased deliveries on the
Lakehead System. Such projects are summarized below:
- Mustang -- In 1996, a U.S. subsidiary of Enbridge entered into a
partnership ("Mustang Pipe Line Partners") with Mobil Illinois Pipe Line
Company, a subsidiary of Mobil Oil Corporation, to own and operate a
crude oil pipeline that connects the Lakehead System to the Patoka/Wood
River refinery area and pipeline hub south of Chicago. The Partnership
has entered into a joint tariff agreement with Mustang Pipe Line Partners
that became effective January 1, 1999. The agreement covers shipments of
western Canadian crude oil over the Lakehead System and the Mustang
pipeline. The joint tariff agreement provides lower transportation costs
to shippers desiring access to the Patoka/Wood River market area. Prior
to the joint tariff agreement, this market area was not competitively
accessible to Partnership customers. The joint tariff agreement results
in a reduction in the Partnership's light crude oil rate for deliveries
destined for the Patoka/Wood River market area. The Mustang system has a
capacity of approximately 100,000 barrels per day.
- Enbridge Toledo -- Enbridge has completed construction of a new pipeline,
which connects the Partnership's facilities at Stockbridge, Michigan, to
two refineries in the Toledo, Ohio, area. This pipeline is anticipated to
have an approximate capacity in excess of 80,000 barrels per day in heavy
crude oil service and became available for service in early February
1999.
- Enbridge Athabasca (formerly Wild Rose)-- Enbridge is scheduled to
complete construction of a new 30-inch diameter pipeline for the delivery
of heavy crude oil from the Athabasca oil sands region near Fort
McMurray, Alberta, to Hardisty, Alberta, by March 31, 1999. At Hardisty,
the Athabasca pipeline would access other pipeline systems including the
Enbridge Pipelines System in western
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<PAGE> 22
Canada. This project would provide new pipeline capacity to accommodate
anticipated growth in production in the Athabasca oil sands region. When
fully powered, the Athabasca pipeline is anticipated to have an ultimate
capacity of 570,000 barrels per day. Enbridge has entered into a 30-year
transportation arrangement with Suncor Energy Inc., the initial shipper
on the pipeline.
Montreal Extension Reversal
The Enbridge Pipelines System includes a section which extends from Sarnia,
Ontario, to Montreal, Quebec (the "Montreal Extension" or "Line 9"). The portion
of the Montreal Extension from Sarnia to North Westover, Ontario, is currently
in west-to-east service and the portion of the Montreal Extension from North
Westover to Montreal has been purged with nitrogen and remains available for
service. Enbridge Pipelines and a group of refiners have developed the Line 9
reversal project to enable crude oil imported into eastern Canada through
facilities of Portland Pipe Line Corporation and Montreal Pipe Line Limited to
be transported on Line 9 in an east-to-west direction from Montreal to the major
refining centers in Ontario. The reversal of the Montreal Extension will result
in Enbridge Pipelines becoming a competitor of the Lakehead System for supplying
crude oil to the Ontario market. This reversal is expressly permitted by the
agreements entered into at the time of formation of the Partnership. The NEB
approved construction of facilities as well as the tolling methodology for the
Line 9 project on December 18, 1997. Enbridge received notice in July 1998 from
the group of sponsoring refiners to proceed with construction of facilities
necessary for reversal. Construction to allow for full reversal is expected to
be completed late in the third quarter or early in the fourth quarter of 1999 at
which time the reversed Line 9 is anticipated to have a capacity of
approximately 240,000 barrels per day from Montreal to Sarnia. Due to upstream
capacity constraints, the Montreal extension is anticipated to be reversed in
two stages, with the first stage entering service in May 1999 with a capacity of
120,000 barrels per day from Montreal to North Westover.
The Partnership anticipates that the reversal of Line 9 will result in a
decline in deliveries over the Lakehead System to eastern Canada. Displaced
volumes originating in western Canada are anticipated to be diverted to other
markets in the Midwest U.S. U.S. domestic and foreign crude oil volumes that
enter the Lakehead System in Chicago are also anticipated to decline from recent
historical levels due to the reversal of Line 9. The level of decline in
deliveries over the Lakehead System to eastern Canada will be dependent upon the
global crude oil market dynamics and the level of utilization of Line 9.
Year 2000 Issue
The Partnership's pipeline system is operationally dependent on the ability
of Enbridge Pipelines to transport crude oil and other liquid hydrocarbons from
western Canada to reach markets in the United States and eastern Canada. Due to
the integrated nature of these two pipeline systems, the Partnership's Year 2000
Readiness Program is being conducted in conjunction with Enbridge Pipelines.
The Partnership's Year 2000 Readiness Program continues on schedule, with
several milestone points being reached by December 31, 1998. The Year 2000
Project Teams of Enbridge Pipelines and the Partnership have compiled a
comprehensive list of all computer hardware and software, embedded chip
technologies and business processes including those having significant third
party interdependencies. A risk assessment and business impact analysis of each
item has also been completed and the Partnership is prioritizing its efforts and
resources to ensure that all critical processes and assets are made to be
compliant on a timely basis. Some critical systems, such as certain accounting
systems which have been replaced under a business system upgrade project, are
already known to be Year 2000 compliant, thereby reducing the risk of failure.
The most critical systems are those that operate and control crude oil and
NGL pipelines, as they are essential to Partnership operations. These systems
are used to control the entire liquid pipeline system, including related tank
farms and pumping stations. Instrumentation along the pipelines measure and
control temperatures, pressures, volume flow, pump operation, valve operation
control equipment and alarm states. This information is also passed to various
control systems to help monitor and track flowing crude oil and NGL in the
pipeline system. The control systems are expected to be compliant by mid 1999.
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<PAGE> 23
In addition, the Year 2000 Project Teams have identified third parties
whose non compliance may have a significant effect on the ability of the
Partnership to continue to conduct its business without disruption. Dialogue has
been established with these entities in order to ascertain whether they will be
Year 2000 compliant in advance of January 1, 2000.
The most significant third party interdependencies are reliance on
electrical and telecommunication suppliers as they are essential to the ability
to transport crude oil and NGL through the System. Also of significance are
feeder pipeline systems that deliver much of the crude oil and NGL entering the
System, as are the receiving connecting pipelines and refineries.
While the Partnership is unable to provide a current assessment of these
critical suppliers' Year 2000 compliance progress, communication with these
entities and monitoring of their Year 2000 readiness status will continue. In
the case of critical suppliers and feeder pipelines, joint testing initiatives
may also be implemented. Where timely assurance is not received, restrictions on
use or replacement of vendors will be considered.
In the review of the systems potentially impacted by the Year 2000 problem,
Enbridge Pipelines and the Partnership are giving consideration to the repair,
replacement, workaround, outsourcing and other methods of eliminating
deficiencies. Enbridge Pipelines and the Partnership are currently involved in
various stages of implementing their Year 2000 compliance initiatives and expect
to have all critical processes and assets compliant by mid 1999, at which point
lower risk systems will be remediated.
In order to address unforeseen Year 2000 problems that could arise and in
an attempt to minimize business disruptions, Enbridge Pipelines and the
Partnership are developing business continuity plans for all critical processes,
systems, technologies and external relationships. These plans are also expected
to be completed before the end of the year.
Preliminary cost estimates for achieving Year 2000 compliance of the
Partnership are approximately $6 million, including $1 million in capital costs
and $5 million of operating expense, with approximately $1 million of expense
having been incurred to date. A majority of the remaining costs are anticipated
to be incurred in 1999. No material resource constraints have been encountered
to date. Although management believes this estimate to be reasonable, due to the
complexities outlined above, there can be no assurance that the actual costs of
the project will not differ materially from the estimated amounts.
Despite the Partnership's best efforts, there can be no guarantees that all
systems and applications will continue without interruption through January 1,
2000 and beyond. Limited testing ability on commercial software packages and the
complexity of identifying all embedded microprocessors that may be used in a
great variety of hardware used for process or flow control, environmental,
transportation, security, communication and other systems may result in non
compliant systems. Additionally, despite ongoing dialogue with interdependent
third parties there can be no assurance that their systems will be fully
compliant. In the event of critical system or supplier failure, crude oil and
NGL deliveries could be temporarily delayed until corrective action is taken or
continuity plans are implemented. Failures that result in substantial
disruptions of business activities could be material to the Partnership.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The Partnership's market risk is primarily impacted by changes in interest
rates. The Partnership has minimal foreign exchange risk and its cash flows are
not significantly impacted by changes in commodity prices as the Partnership
does not own the crude oil and NGL it transports. However, commodity prices have
a significant impact on the underlying supply and demand for crude oil and NGL
that the Partnership transports. The Partnership does not currently hold or
issue derivative instruments for trading or any other purposes.
The Partnership's market risk with respect to interest rate exposure is
managed through its long-term debt ratio target, and its allocation of fixed and
floating rate debt. The table below provides information about
21
<PAGE> 24
the Partnership's financial instruments that are sensitive to changes in
interest rates. For debt obligations the table presents principal cash flows and
related weighted average interest rates by expected maturity date.
<TABLE>
<CAPTION>
EXPECTED MATURITY DATE OF DEBT INSTRUMENTS
----------------------------------------------
THERE- FAIR
DECEMBER 31, 1998 1999 - 2001 2002 2003 AFTER TOTAL VALUE
----------------- ----------- ---- ---- ------ ----- -----
($U.S. IN MILLIONS)
<S> <C> <C> <C> <C> <C> <C>
FIXED RATE:
First Mortgage Notes............. $0 $31.0 $ 31.0 $248.0 $310.0 $369.0
Interest Rate.................... -- 9.15% 9.15% 9.15%
Senior Unsecured Notes........... $0 $ 0 $ 0 $200.0 $200.0 $209.0
Interest Rate.................... -- -- -- 7.06%
VARIABLE RATE:
Revolving Credit Facility........ $0 $ 0 $305.0 $ 0 $305.0 $305.0
Interest Rate.................... -- -- 5.8% --
</TABLE>
The average interest rate of debt outstanding on the Partnership's
Revolving Credit facility was 5.8% during 1998. For additional information
concerning the Partnership's debt obligations, please see Note 6 to the
Partnership's Consolidated Financial Statements.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
The consolidated financial statements of the Partnership together with the
notes thereto and the independent accountants' reports thereon, appear on pages
F-2 through F-12 of this Report, and are incorporated by reference. Reference
should be made to the Index to Financial Statements, Supplementary Information
and Financial Statement Schedules on page F-1 of this Report.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
None.
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
(a) Directors and Executive Officers of the Registrant
The Registrant is a limited partnership and has no officers, directors or
employees. Set forth below is certain information concerning the directors and
executive officers of the General Partner. Enbridge Pipelines, the sole
stockholder of the General Partner, elects the directors of the General Partner
on an annual basis. All officers of the General Partner serve at the discretion
of the directors of the General Partner.
<TABLE>
<CAPTION>
NAME AGE POSITION WITH GENERAL PARTNER
---- --- -----------------------------
<S> <C> <C>
E. C. Hambrook..................... 61 Chairman and Director
P. D. Daniel....................... 52 Director
S. J. Wuori........................ 41 President and Director
R. C. Sandahl...................... 48 Vice President and Director
F. W. Fitzpatrick.................. 66 Director
C. A. Russell...................... 65 Director
D. P. Truswell..................... 55 Director
S. R. Wilson....................... 41 Vice President (since January 14,
1999) and Treasurer
M. A. Maki......................... 34 Chief Accountant
S. D. Lenczewski................... 38 Secretary
</TABLE>
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<PAGE> 25
Mr. Hambrook was elected a Director of the General Partner in January 1992
and has served as Chairman of the General Partner since July 1996. He also
serves on the Audit Committee. Mr. Hambrook is the President of Hambrook
Resources Inc.
Mr. Daniel was elected a Director of the General Partner in July 1996 and
served as its President from July 1996 through October, 1997. Since June 1998,
Mr. Daniel has also served as President and Chief Operating Officer Energy
Delivery of Enbridge. Prior thereto, Mr. Daniel served as Executive Vice
President and Chief Operating Officer -- Energy Transportation Services of
Enbridge from September 1997 through June 1998, as Senior Vice President of
Enbridge from May 1994 to August 1997, as President and Chief Executive Officer
of Enbridge Pipelines from August 1996 to August 1997, and as President and
Chief Operating Officer of Enbridge Pipelines from May 1994 to August 1996.
Prior to May 1994, he served as Vice President, Planning of Enbridge.
Mr. Wuori was appointed President and elected a Director of the General
Partner as of November 1, 1997. He has served as President of Enbridge Pipelines
since September 1997. Prior thereto, he served as Vice President, Operations of
Enbridge Pipelines from May 1994 to August 1997, and, prior thereto, as District
Manager of the General Partner.
Mr. Sandahl was elected a Director and appointed Vice President of the
General Partner in July 1996. He served as Vice President, Operations of the
General Partner from May 1994 to August 1996. Prior thereto, he was employed by
Enbridge Pipelines for six years where he served in various capacities, most
recently as Director of Engineering Services from June 1990 to May 1994.
Mr. Fitzpatrick was elected a Director of the General Partner in April 1993
and serves on the Audit Committee. He is also a Director of Enbridge and serves
as Chairman of the Audit, Finance and Risk Committee of the Board of Enbridge.
Mr. Russell was elected a Director of the General Partner in October 1985
and serves as the Chairman of the Audit Committee. Mr. Russell served as
Chairman and Chief Executive Officer of Norwest Bank Minnesota North, N.A. from
January through December 1995. Prior to January 1995, he served as President of
Norwest Bank Minnesota North, N.A. He also served as a Director of Minnesota
Power and Light Co. until May 1996.
Mr. Truswell was elected a Director of the General Partner in May 1991 and
served as a Vice President of the General Partner from October 1991 to May 1994.
Mr. Truswell has served as Senior Vice President and Chief Financial Officer of
Enbridge since May 1994 and prior thereto, as Vice President, Finance of
Enbridge from 1992 to May 1994. He also served in various senior executive
capacities with Enbridge Pipelines, including as Vice President, Finance from
May 1991 to May 1994.
Mr. Wilson was appointed Treasurer of the General Partner as of November 1,
1997. He has served as Treasurer of Enbridge since September 1997 and, prior
thereto, as its Assistant Treasurer from September 1995 to August 1997. Mr.
Wilson has served as Treasurer of The Consumers' Gas Company Ltd., a subsidiary
of Enbridge since April 1991.
Mr. Maki has served as Chief Accountant of the General Partner since June
1997. Prior thereto, he served in various supervisory and professional positions
with the General Partner or Enbridge affiliates in the areas of Internal Audit,
Rate Regulation and Accounting.
Ms. Lenczewski has served as Secretary of the General Partner since June
1998. Prior thereto, she served as Assistant Secretary of the General Partner,
from July 1996 to June 1998.
ITEM 11. EXECUTIVE COMPENSATION
The General Partner is responsible for the management and operation of the
Partnership. The Partnership does not directly employ any of the persons
responsible for managing or operating the Partnership's operations, but instead
reimburses the General Partner or its affiliates for the services of such
persons. The General Partner, in turn, because it has no employees, has entered
into services agreements with
23
<PAGE> 26
Enbridge (U.S.) Inc., ("Enbridge U.S.") and other affiliates to provide the
services required by the Partnership.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
(a) Security Ownership of Certain Beneficial Owners
<TABLE>
<CAPTION>
TITLE OF CLASS NAME AND ADDRESS AMOUNT PERCENT OF CLASS
-------------- ---------------- ------ ----------------
<S> <C> <C> <C>
Class A Common Units............. No person or group is known to be
the beneficial owner of more than
5% of the Class A Common Units as
at February 5, 1999
Class B Common Units............. Lakehead Pipe Line Company, Inc. 3,912,750 100
Lake Superior Place
21 West Superior Street
Duluth, Minnesota 55802-2067
</TABLE>
(b) Security Ownership of Management
As of February 5, 1999, E. C. Hambrook beneficially owned 1,000 Class A
Common Units and R. C. Sandahl beneficially owned 200 Class A Common Units.
Class A Common Units beneficially held by all directors and officers as a group
represented less than 1% of the Partnership's outstanding Class A Common Units.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
The Partnership is managed by the General Partner pursuant to the Amended
and Restated Agreements of Limited Partnership of the Partnership and the
Operating Partnership, as amended ("Partnership Agreements"). The General
Partner has entered into a services agreement with Enbridge U.S. whereby the
General Partner will utilize the resources of Enbridge U.S. to operate the
Partnership. Under this agreement, Enbridge U.S. will be reimbursed for all
direct and indirect expenses it incurs or payments it makes on behalf of the
Partnership. The General Partner also receives certain administrative,
engineering, treasury and computer services from Enbridge and Enbridge Pipelines
for the benefit of the Partnership. The Partnership reimburses the General
Partner for the cost of these services. For information about reimbursements to
the General Partner, see Note 7 to the Partnership's Consolidated Financial
Statements.
The Partnership has entered into an easement acquisition agreement with
Enbridge Holdings (Mustang) Inc. ("Enbridge Mustang" formerly IPL Patoka
Pipeline Holdings (U.S.A.) Inc.), a subsidiary of Enbridge U.S. For the benefit
of the Partnership, Enbridge Mustang has acquired certain real property for
purposes of granting a pipeline easement to the Partnership. Enbridge Mustang is
reimbursed for all net costs associated with this process at cost by the
Partnership and will be indemnified by the Partnership from and against all
liabilities that may arise in connection with this process. This agreement was
entered into to facilitate easement acquisitions for SEP II. Enbridge Mustang
will begin to dispose of real property acquired in 1997 and 1998 and repay
advances from the Partnership as properties are sold beginning in 1999.
The Partnership has implemented an agreement with Mustang Pipe Line
Partners to provide for a joint tariff covering shipments of western Canadian
crude oil to the Patoka/Wood River market area south of Chicago. These shipments
travel on the Lakehead System to Chicago and on the Patoka/Wood River market
area through the Mustang pipeline system. The joint tariff agreement provides
for lower transportation costs to shippers desiring access to the Patoka/Wood
River market area, an incentive which the Partnership believes complements its
expansion programs. Mustang Pipe Line Partners is a Delaware general partnership
owned by Mobil Illinois Pipe Line Company and a wholly owned subsidiary of
Enbridge U.S.
Under the terms of the Revolving Credit Facility Agreement, the
Partnership, Lakehead Services, Limited Partnership ("Services Partnership") and
the General Partner may draw down funds up to a combined maximum of $350.0
million. The Partnership has a 1% general partner interest in the Services
24
<PAGE> 27
Partnership, with the General Partner having a 99% limited partner interest. For
additional details, see Note 6 to the Partnership's Consolidated Financial
Statements.
The Partnership has entered into a $200 million uncommitted lending
facility with the General Partner. This uncommitted facility provided an
alternative source of funds at market interest rates in the event that a
disruption in the capital markets delayed access to debt and equity markets. In
late September 1998, the Partnership borrowed, and subsequently repaid in early
October, $37.0 million under this arrangement.
For discussion of distribution restrictions and incentive distributions
payable to the General Partner, see Note 3 to the Partnership's Consolidated
Financial Statements.
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
(a) As to financial statements, supplementary information and financial
statement schedules, reference is made to "Index to Financial Statements,
Supplementary Information and Financial Statement Schedules" on page F-1 of this
Report.
(b) The Registrant filed the following reports on Form 8-K during the
fourth quarter of 1998: A report on Form 8-K was filed on December 28, 1998,
submitting a press release of the Registrant dated December 21, 1998, announcing
a tariff filing and net income expectations for 1999.
(c) The following Exhibits (numbered in accordance with Item 601 of
Regulation S-K) are filed or incorporated herein by reference as part of this
Report.
<TABLE>
<CAPTION>
EXHIBIT
NUMBER DESCRIPTION
- ------- -----------
<C> <S>
3.1 Certificate of Limited Partnership of the Partnership.
(Partnership's Registration Statement No.
33-43425 -- Exhibit 3.1)
4.1 Form of Certificate representing Class A Common Units.
(Registrant's Form 8-A/A, dated May 2, 1997)
4.2 Amended and Restated Agreement of Limited Partnership of the
Partnership, dated April 15, 1997. (Registrant's Form 8-A/A,
dated May 2, 1997)
10.1 Note Agreement and Mortgage, dated December 12, 1991. (1991
Form 10-K -- Exhibit 10.1)
10.2 [Intentionally Omitted].
10.3 Distribution Support Agreement, dated December 27, 1991,
among the Partnership, Lakehead Pipe Line Company, Inc. and
Interprovincial Pipe Line Inc. (1991 Form 10-K -- Exhibit
10.3)
10.4 Assumption and Indemnity Agreement, dated December 18, 1992,
between Interprovincial Pipe Line Inc. and Interprovincial
Pipe Line System Inc. (1992 Form 10-K -- Exhibit 10.4)
10.5 Amended Services Agreement, dated February 29, 1988, between
Interprovincial Pipe Line Inc. and Lakehead Pipe Line
Company, Inc. (1991 Form 10-K -- Exhibit 10.4)
10.6 Amended Services Agreement, dated January 1, 1992, between
Interprovincial Pipe Line Inc. and Lakehead Pipe Line
Company, Inc. (1992 Form 10-K -- Exhibit 10.6)
10.7 Certificate of Limited Partnership of the Operating
Partnership. (Partnership's Registration Statement No.
33-43425 -- Exhibit 10.1)
10.8 Amended and Restated Agreement of Limited Partnership of the
Operating Partnership, dated December 27, 1991. (1991 Form
10-K -- Exhibit 10.6)
10.9 Certificate of Limited Partnership of Lakehead Services,
Limited Partnership. (Partnership's Registration Statement
No. 33-43425 -- Exhibit 10.4)
10.10 Amendment No. 1 to the Certificate of Limited Partnership of
Lakehead Services, Limited Partnership. (Partnership's
Registration Statement No. 33-43425 -- Exhibit 10.16)
</TABLE>
25
<PAGE> 28
<TABLE>
<CAPTION>
EXHIBIT
NUMBER DESCRIPTION
- ------- -----------
<C> <S>
10.11 Amended and Restated Agreement of Limited Partnership of
Lakehead Services, Limited Partnership, dated December 27,
1991. (1991 Form 10-K -- Exhibit 10.9)
10.12 Contribution, Conveyance and Assumption Agreement, dated
December 27, 1991, among Lakehead Pipe Line Company, Inc.,
Lakehead Pipe Line Partners, L.P. and Lakehead Pipe Line
Company, Limited Partnership. (1991 Form 10-K -- Exhibit
10.10)
10.13 LPL Contribution and Assumption Agreement, dated December
27, 1991, among Lakehead Pipe Line Company, Inc., Lakehead
Pipe Line Partners, L.P. and Lakehead Pipe Line Company,
Limited Partnership and Lakehead Services, Limited
Partnership. (1991 Form 10-K -- Exhibit 10.11)
10.14 Services Agreement, dated January 1, 1996, between IPL
Energy (U.S.A.) Inc. and Lakehead Pipe Line Company, Inc.
(1995 Form 10-K -- Exhibit 10.14)
10.15 Amended and Restated Revolving Credit Agreement, dated
September 6, 1996, among Lakehead Pipe Line Company, Inc.,
Lakehead Pipe Line Partners, L.P., Lakehead Services,
Limited Partnership, Lakehead Pipe Line Company, Limited
Partnership and the Bank of Montreal and Harris Trust and
Savings Bank. (1996 Form 10-K -- Exhibit 10.15)
10.16 First Amendment to Amended and Restated Revolving Credit
Agreement, dated September 6, 1996, among Lakehead Pipe Line
Company, Inc., Lakehead Pipe Line Partners, L.P., Lakehead
Services, Limited Partnership, Lakehead Pipe Line Company,
Limited Partnership and the Bank of Montreal. (1996 Form
10-K -- Exhibit 10.16)
10.17 Second Amendment to Amended and Restated Revolving Credit
Agreement, dated June 16, 1998, among Lakehead Pipe Line
Company, Inc., Lakehead Pipe Line Partners, L.P., Lakehead
Services Limited Partnership, Lakehead Pipe Line Company,
Limited Partnership and Bank of Montreal, The Toronto
Dominion Bank, Canadian Imperial Bank of Commerce, ABN AMRO
Bank, N.V. Cayman Islands Branch and Bank of Montreal, as
agent. (Form 10-Q/A, filed September 14, 1998 -- Exhibit
10.1)
10.18 Settlement Agreement, dated August 28, 1996, between
Lakehead Pipe Line Company, Limited Partnership and the
Canadian Association of Petroleum Producers and the Alberta
Department of Energy. (1996 Form 10-K -- Exhibit 10.17)
10.19 Promissory Note, dated as of September 30, 1998, among
Lakehead Pipe Line Company, Inc. as lender and Lakehead Pipe
Line Company, Limited Partnership as borrower.
10.20 Treasury Services Agreement, dated January 1, 1996, between
IPL Energy Inc. and Lakehead Pipe Line Company, Inc. (1996
Form 10-K -- Exhibit 10.18)
10.21 Tariff Agreement as filed with the Federal Energy Regulatory
Commission for the System Expansion Program II, and Terrace
Expansion Project.
10.22 Indenture dated September 15, 1998, between Lakehead Pipe
Line Company, Limited Partnership and the Chase Manhattan
Bank. (1998 Form 8-K of Lakehead Pipe Line Company, Limited
Partnership -- Exhibit 4.1, dated October 20, 1998)
10.23 First Supplemental Indenture dated September 15, 1998,
between Lakehead Pipe Line Company, Limited Partnership and
the Chase Manhattan Bank. (1998 Form 8-K of Lakehead Pipe
Line Company, Limited Partnership -- Exhibit 4.2, dated
October 20, 1998)
10.24 Second Supplemental Indenture dated September 15, 1998,
between Lakehead Pipe Line Company, Limited Partnership and
the Chase Manhattan Bank. (1998 Form 8-K of Lakehead Pipe
Line Company, Limited Partnership -- Exhibit 4.3, dated
October 20, 1998)
10.25 Indenture dated September 15, 1998, between Lakehead Pipe
Line Company, Limited Partnership and the Chase Manhattan
Bank. (1998 Form 8-K of Lakehead Pipe Line Company, Limited
Partnership -- Exhibit 4.4, dated October 20, 1998)
</TABLE>
26
<PAGE> 29
<TABLE>
<CAPTION>
EXHIBIT
NUMBER DESCRIPTION
- ------- -----------
<C> <S>
21 Subsidiaries of the Registrant.
27 Financial Data Schedule as of and for the year ended
December 31, 1998.
</TABLE>
All Exhibits listed above, with the exception of Exhibits 10.19, 10.21, 21,
and 27 are incorporated herein by reference to the documents identified in
parentheses.
Copies of Exhibits may be obtained upon written request of any Unitholder
to Investor Relations, Lakehead Pipe Line Company, Inc., Lake Superior Place, 21
West Superior Street, Duluth, Minnesota 55802-2067.
(d) As to financial statement schedules, reference is made to "Financial
Statement Schedules" on page F-1 of this report.
27
<PAGE> 30
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the Registrant has duly caused this Report to be signed on
its behalf by the undersigned, thereunto duly authorized.
Lakehead Pipe Line Partners, L.P.
(Registrant)
By: Lakehead Pipe Line Company, Inc.,
as General Partner
Date: March 9, 1999 By: /s/ S.J. WUORI
------------------------------------
S.J. Wuori
(President)
Pursuant to the requirements of the Securities Exchange Act of 1934, this
Report has been signed below on March 9, 1999 by the following persons on behalf
of the Registrant and in the capacities indicated with Lakehead Pipe Line
Company, Inc., General Partner.
<TABLE>
<S> <C>
/s/ S.J. WUORI /s/ E.C. HAMBROOK
- ------------------------------------------ ------------------------------------------
S.J. Wuori E.C. Hambrook
President and Director Chairman and Director
(Principal Executive Officer)
/s/ R.C. SANDAHL /s/ M.A. MAKI
- ------------------------------------------ ------------------------------------------
R.C. Sandahl M.A. Maki
Vice President and Director Chief Accountant
(Principal Financial and Accounting
Officer)
/s/ F.W. FITZPATRICK /s/ P.D. DANIEL
- ------------------------------------------ ------------------------------------------
F.W. Fitzpatrick P.D. Daniel
Director Director
/s/ C.A. RUSSELL /s/ D.P. TRUSWELL
- ------------------------------------------ ------------------------------------------
C.A. Russell D.P. Truswell
Director Director
</TABLE>
28
<PAGE> 31
INDEX TO FINANCIAL STATEMENTS, SUPPLEMENTARY INFORMATION AND
FINANCIAL STATEMENT SCHEDULES
LAKEHEAD PIPE LINE PARTNERS, L.P.
<TABLE>
<CAPTION>
PAGE
----
<S> <C>
Financial Statements
Report of Independent Accountants......................... F-2
Consolidated Statement of Income for the Years Ended
December 31, 1998, 1997, 1996.......................... F-3
Consolidated Statement of Cash Flows for the Years Ended
December 31, 1998, 1997, 1996.......................... F-4
Consolidated Statement of Financial Position as at
December 31, 1998 and 1997............................. F-5
Consolidated Statement of Partners' Capital for the Years
Ended December 31, 1998, 1997, 1996.................... F-6
Notes to the 1998 Consolidated Financial Statements....... F-7
Supplementary Information (Unaudited)
Selected Quarterly Financial Data......................... F-14
</TABLE>
FINANCIAL STATEMENT SCHEDULES
Financial statement schedules not included in this Report have been omitted
because they are not applicable or the required information is shown in the
financial statements or notes thereto.
F-1
<PAGE> 32
REPORT OF INDEPENDENT ACCOUNTANTS
To the Partners of
Lakehead Pipe Line Partners, L.P.
In our opinion, the accompanying consolidated statements of financial
position and the related consolidated statements of income, of partners' capital
and of cash flows present fairly, in all material respects, the financial
position of Lakehead Pipe Line Partners, L.P. and its subsidiary (the
"Partnership") at December 31, 1998 and 1997, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 1998 in conformity with generally accepted accounting principles.
These financial statements are the responsibility of the Partnership's
management; our responsibility is to express an opinion on these financial
statements based on our audits. We conducted our audits of these statements in
accordance with generally accepted auditing standards which require that we plan
and perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements, assessing the accounting principles used and significant estimates
made by management, and evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for the opinion expressed
above.
PRICEWATERHOUSECOOPERS LLP
Minneapolis, Minnesota
January 8, 1999
F-2
<PAGE> 33
LAKEHEAD PIPE LINE PARTNERS, L.P.
CONSOLIDATED STATEMENT OF INCOME
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-----------------------------
1998 1997 1996
---- ---- ----
(DOLLARS IN MILLIONS,
EXCEPT PER UNIT AMOUNTS)
<S> <C> <C> <C>
Operating Revenue (Note 9).................................. $ 287.7 $ 282.1 $ 274.5
------- ------- -------
Expenses
Power..................................................... 69.0 65.9 62.0
Operating and administrative.............................. 71.9 68.0 66.7
Depreciation.............................................. 41.4 40.1 38.3
Provision for prior years' rate refunds (Note 9).......... -- -- 20.1
------- ------- -------
182.3 174.0 187.1
------- ------- -------
Operating Income............................................ 105.4 108.1 87.4
Interest and Other Income................................... 6.0 9.7 9.6
Interest Expense (Note 6)................................... (21.9) (38.6) (43.9)
Minority Interest........................................... (1.0) (0.9) (0.7)
------- ------- -------
Net Income.................................................. $ 88.5 $ 78.3 $ 52.4
======= ======= =======
Net Income Per Unit (Note 4)................................ $ 3.07 $ 3.02 $ 2.11
======= ======= =======
Weighted Average Units Outstanding (millions)............... 26.2 24.4 24.0
======= ======= =======
</TABLE>
The accompanying notes to the consolidated financial statements are an integral
part of these statements.
F-3
<PAGE> 34
LAKEHEAD PIPE LINE PARTNERS, L.P.
CONSOLIDATED STATEMENT OF CASH FLOWS
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-----------------------------
1998 1997 1996
---- ---- ----
(DOLLARS IN MILLIONS)
<S> <C> <C> <C>
Cash Provided from Operating Activities
Net income................................................ $ 88.5 $ 78.3 $ 52.4
Adjustments to reconcile net income to cash provided from
operating activities:
Depreciation......................................... 41.4 40.1 38.3
Accrued rate refunds and related interest (Note 9)... 2.1 3.5 42.6
Minority interest.................................... 1.0 0.9 0.7
Other................................................ 0.1 0.5 0.6
Changes in operating assets and liabilities:
Accounts receivable and other..................... (2.8) 4.8 (0.7)
Materials and supplies............................ -- (0.1) (1.6)
General Partner and affiliates.................... (1.0) 2.4 0.2
Accounts payable and other........................ 2.1 1.5 3.6
Interest payable.................................. 0.2 2.1 0.7
Property and other taxes.......................... 0.5 0.3 (1.1)
Payment of rate refunds and related interest (Note
9).............................................. (28.5) (27.7) (41.8)
------- ------- -------
103.6 106.6 93.9
------- ------- -------
Investing Activities
Short-term investments, net............................... 53.9 29.8 (8.0)
Advances to affiliate (Note 7)............................ (25.5) (6.5) --
Additions to property, plant and equipment................ (487.3) (126.9) (76.7)
Changes in construction payables.......................... 31.0 1.9 --
------- ------- -------
(427.9) (101.7) (84.7)
------- ------- -------
Financing Activities
Variable rate financing, net (Note 6)..................... 152.0 -- 68.0
Fixed rate financing, net (Note 6)........................ 196.9 -- --
Proceeds from unit issuance, net (Note 1)................. -- 99.2 --
Distributions to partners (Note 3)........................ (95.3) (75.3) (63.9)
Minority interest......................................... (0.9) 0.2 (0.7)
------- ------- -------
252.7 24.1 3.4
------- ------- -------
Increase (Decrease) in Cash and Cash Equivalents............ (71.6) 29.0 12.6
Cash and Cash Equivalents at Beginning of Year.............. 118.6 89.6 77.0
------- ------- -------
Cash and Cash Equivalents at End of Year.................... $ 47.0 $ 118.6 $ 89.6
======= ======= =======
</TABLE>
The accompanying notes to the consolidated financial statements are an integral
part of these statements.
F-4
<PAGE> 35
LAKEHEAD PIPE LINE PARTNERS, L.P.
CONSOLIDATED STATEMENT OF FINANCIAL POSITION
<TABLE>
<CAPTION>
DECEMBER 31,
----------------------
1998 1997
---- ----
(DOLLARS IN MILLIONS)
<S> <C> <C>
ASSETS
Current Assets
Cash and cash equivalents................................. $ 47.0 $ 118.6
Short-term investments.................................... -- 53.9
Advances to affiliate (Note 7)............................ 32.0 6.5
Accounts receivable and other............................. 25.2 22.4
Materials and supplies.................................... 7.1 7.1
--------- ---------
111.3 208.5
Deferred Charges and Other.................................. 6.9 4.4
Property, Plant and Equipment, Net (Note 5)................. 1,296.2 850.3
--------- ---------
$ 1,414.4 $ 1,063.2
========= =========
LIABILITIES AND PARTNERS' CAPITAL
Current Liabilities
Due to General Partner and affiliates..................... $ 2.9 $ 3.9
Accounts payable and other................................ 53.3 20.2
Interest payable.......................................... 5.5 5.3
Property and other taxes.................................. 11.9 11.4
Current portion of accrued rate refunds and related
interest (Note 9)...................................... 28.7 29.0
--------- ---------
102.3 69.8
Long-Term Debt (Note 6)..................................... 814.5 463.0
Accrued Rate Refunds and Related Interest (Note 9).......... -- 26.1
Minority Interest........................................... 2.6 2.5
Contingencies (Note 10).....................................
--------- ---------
919.4 561.4
--------- ---------
Partners' Capital
Class A Common Unitholders (Units authorized and
issued -- 22,290,000).................................. 453.4 461.6
Class B Common Unitholder (Units authorized and
issued -- 3,912,750)................................... 37.3 36.7
General Partner........................................... 4.3 3.5
--------- ---------
495.0 501.8
--------- ---------
$ 1,414.4 $ 1,063.2
========= =========
</TABLE>
The accompanying notes to the consolidated financial statements are an
integral part of these statements.
F-5
<PAGE> 36
LAKEHEAD PIPE LINE PARTNERS, L.P.
CONSOLIDATED STATEMENT OF PARTNERS' CAPITAL
<TABLE>
<CAPTION>
CLASS A CLASS B
COMMON COMMON GENERAL
UNITHOLDERS UNITHOLDER PARTNER TOTAL
----------- ---------- ------- -----
(DOLLARS IN MILLIONS)
<S> <C> <C> <C> <C>
Partners' capital at December 31, 1995................ $ 387.9 $ 21.7 $ 1.5 $ 411.1
Net income allocation................................. 40.6 10.2 1.6 52.4
Distributions to partners............................. (52.2) (10.2) (1.5) (63.9)
------- ------- ------- -------
Partners' capital at December 31, 1996................ 376.3 21.7 1.6 399.6
Allocation of net proceeds from unit issuance (Note
1).................................................. 85.6 12.6 1.0 99.2
Net income allocation................................. 60.1 13.8 4.4 78.3
Distributions to partners............................. (60.4) (11.4) (3.5) (75.3)
------- ------- ------- -------
Partners' capital at December 31, 1997................ 461.6 36.7 3.5 501.8
Net income allocation................................. 66.7 13.8 8.0 88.5
Distributions to partners............................. (74.9) (13.2) (7.2) (95.3)
------- ------- ------- -------
Partners' capital at December 31, 1998................ $ 453.4 $ 37.3 $ 4.3 $ 495.0
======= ======= ======= =======
</TABLE>
The accompanying notes to the consolidated financial statements are an integral
part of these statements.
F-6
<PAGE> 37
LAKEHEAD PIPE LINE PARTNERS, L.P.
NOTES TO THE 1998 CONSOLIDATED FINANCIAL STATEMENTS
(DOLLARS IN MILLIONS, EXCEPT PER UNIT AMOUNTS)
1. PARTNERSHIP ORGANIZATION AND NATURE OF OPERATIONS
Lakehead Pipe Line Partners, L.P. ("Lakehead Partnership") is a publicly
traded limited partnership that owns a 99% limited partner interest in Lakehead
Pipe Line Company, Limited Partnership ("Operating Partnership"), both Delaware
limited partnerships, and collectively known as the "Partnership". The
Partnership was formed in 1991 to acquire, own and operate the crude oil and
natural gas liquids pipeline business of Lakehead Pipe Line Company, Inc. (the
sole "General Partner"). The General Partner is a wholly-owned subsidiary of
Enbridge Pipelines Inc. ("Enbridge Pipelines") (formerly Interprovincial Pipe
Line Inc.), a Canadian company owned by Enbridge Inc. (formerly IPL Energy Inc.)
of Calgary, Alberta, Canada.
In October 1997, the Lakehead Partnership issued an additional 2,200,000
Class A Common Units for total net proceeds of $99.2 million, including the
General Partner's contribution, bringing the total number of Class A Common
Units issued to 22,290,000. Class A Common Units are publicly traded and
represent an 83.4% limited partner interest in the Partnership. The General
Partner has a 14.8% limited partner (in the form of 3,912,750 Class B Common
Units) and 1.0% general partner interest in the Lakehead Partnership, as well as
a 1.0% general partner interest in the Operating Partnership (an effective 16.6%
combined interest in the Partnership).
The Lakehead Partnership holds a 1% general partner interest in Lakehead
Services, Limited Partnership ("Services Partnership"), a Delaware limited
partnership, originally formed to facilitate the financing of the Operating
Partnership.
The Operating Partnership is engaged in the transportation of crude oil and
natural gas liquids through a common carrier pipeline system. Substantially all
of the shipments delivered originate in western Canadian oil fields. The
majority of the shipments reach the Operating Partnership at the Canada/United
States border in North Dakota, through a Canadian pipeline system owned by
Enbridge Pipelines. Deliveries are made in the Great Lakes region of the United
States and to the Canadian Province of Ontario, principally to refineries,
either directly or through the connecting pipelines of other companies.
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
The consolidated financial statements of the Partnership are prepared in
accordance with generally accepted accounting principles in the United States
and conform in all material respects with the historical cost accounting
standards of the International Accounting Standards Committee. The preparation
of financial statements in conformity with generally accepted accounting
principles requires management to make estimates and assumptions that affect the
reported amounts of assets, liabilities, revenues, expenses and related
disclosures.
PRINCIPLES OF CONSOLIDATION
The financial statements of the Partnership include the accounts of the
Lakehead Partnership and the Operating Partnership on a consolidated basis. The
equity method is used to account for the Partnership's 1% general partner
interest in the Services Partnership. The General Partner's 1% interest in the
Operating Partnership is accounted for by the Partnership as a minority
interest.
REGULATION OF PIPELINE SYSTEM
As an interstate common carrier oil pipeline, rates and accounting
practices are under the regulatory authority of the Federal Energy Regulatory
Commission ("FERC").
F-7
<PAGE> 38
LAKEHEAD PIPE LINE PARTNERS, L.P.
NOTES TO THE 1998 CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
REVENUE RECOGNITION
Substantially all pipeline system revenues are derived from transportation
of crude oil and natural gas liquids and are recognized in income upon delivery.
Amounts provided for accrued rate refunds are recognized as a direct reduction
from revenues except for amounts related to prior years (Note 9), which are
separately stated as a provision for prior years' rate refunds.
CASH EQUIVALENTS AND SHORT-TERM INVESTMENTS
Cash equivalents are defined as all highly marketable securities with a
maturity of three months or less when purchased. Short-term investments are
marketable securities with a maturity of more than three months when purchased.
Both are accounted for as held-to-maturity securities and valued at amortized
cost.
MATERIALS AND SUPPLIES
Materials and supplies are stated at the lower of cost or market value.
DEFERRED FINANCING CHARGES
Deferred financing charges are amortized on the straight-line basis over
the life of the related debt which is comparable to results using the effective
interest method.
PROPERTY, PLANT AND EQUIPMENT
Expenditures for system expansion and major renewals and betterments are
capitalized; maintenance and repair costs are expensed as incurred. An allowance
for interest incurred on external borrowings during construction is capitalized.
Depreciation of property, plant and equipment is provided on the straight line
basis over their estimated service lives. When property, plant and equipment are
retired or otherwise disposed of, the cost less net proceeds is normally charged
to accumulated depreciation and no gain or loss is recognized.
INCOME TAXES
The Partnership is not a taxable entity for federal and state income tax
purposes. Accordingly, no recognition has been given to income taxes for
financial reporting purposes. The tax on Partnership net income is borne by the
individual partners through the allocation of taxable income. Such taxable
income reportable to Unitholders may vary substantially from financial income as
a result of differences between the tax basis and financial reporting basis of
assets and liabilities and the taxable income allocation requirements under the
Partnership Agreement. The aggregate difference in the basis of the
Partnership's net assets for financial and tax reporting purposes cannot be
readily determined due to inaccessible information regarding each partner's tax
attributes in the Partnership.
COMPARATIVE AMOUNTS
Certain comparative amounts are reclassified to conform with the current
year's financial statement presentation.
3. CASH DISTRIBUTIONS
The Partnership distributes quarterly all of its "Available Cash", which is
generally defined in the Partnership Agreement as cash receipts less cash
disbursements and net additions to reserves for future requirements. These
reserves are retained to provide for the proper conduct of the Partnership
business and as necessary to comply with the terms of any agreement or
obligation of the Partnership. Distributions by the
F-8
<PAGE> 39
LAKEHEAD PIPE LINE PARTNERS, L.P.
NOTES TO THE 1998 CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
3. CASH DISTRIBUTIONS (CONTINUED)
Partnership of its Available Cash generally are made 98% to the Class A and B
Common Unitholders and 2% to the General Partner, subject to the payment of
incentive distributions to the General Partner to the extent that certain target
levels of cash distributions to the Unitholders are achieved. The incremental
incentive distributions payable to the General Partner are 15%, 25% and 50% of
all quarterly distributions of Available Cash that exceed target levels of
$0.59, $0.70, and $0.99 per Class A and B Common Units, respectively.
In 1998, the Partnership paid cash distributions of $3.36 per unit
consisting of $0.78 per unit paid in February and $0.86 per unit paid in May,
August and November. In 1997, the Partnership paid cash distributions of $2.92
per unit consisting of $0.68 per unit paid in February and May, and $0.78 per
unit paid in August and November. In 1996, distributions of $2.60 per unit
consisted of $0.64 per unit paid in February, May and August, and $0.68 per unit
paid in November.
The cash distribution in respect of the fourth quarter 1996 was the last
distribution subject to certain preferential rights of the Class A Common Units
and certain support obligations of the General Partner. These rights terminated
with the distribution paid in February 1997 and, with respect to subsequent cash
distributions, Class A and B Common Units are treated as one class of units.
4. NET INCOME PER UNIT
Net income per unit is computed by dividing net income, after deduction of
the General Partner's allocation, by the weighted average number of Class A and
Class B Common Units outstanding. The General Partner's allocation is equal to
an amount based upon its 1% general partner interest, adjusted to reflect an
amount equal to incentive distributions and an amount required to reflect
depreciation on the General Partner's historical cost basis for assets
contributed on formation of the Partnership. Net income per unit was determined
as follows:
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
--------------------------
1998 1997 1996
---- ---- ----
<S> <C> <C> <C>
Net income.................................................. $ 88.5 $ 78.3 $ 52.4
------ ------ ------
Net income allocated to General Partner..................... (0.9) (0.8) (0.5)
Adjusted to reflect:
Incentive distributions................................... (7.0) (3.5) (1.0)
Historical cost basis depreciation........................ (0.1) (0.1) (0.1)
------ ------ ------
(8.0) (4.4) (1.6)
------ ------ ------
Net income allocable to Common Units........................ $ 80.5 $ 73.9 $ 50.8
====== ====== ======
Weighted average units outstanding (millions)............... 26.2 24.4 24.0
====== ====== ======
Net income per unit......................................... $ 3.07 $ 3.02 $ 2.11
====== ====== ======
</TABLE>
F-9
<PAGE> 40
LAKEHEAD PIPE LINE PARTNERS, L.P.
NOTES TO THE 1998 CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
5. PROPERTY, PLANT AND EQUIPMENT, NET
<TABLE>
<CAPTION>
AVERAGE DECEMBER 31,
DEPRECIATION --------------------
RATES 1998 1997
------------ ---- ----
<S> <C> <C> <C>
Land........................................................ -- $ 6.2 $ 6.1
Rights-of-way............................................... 3.6% 126.4 12.6
Pipeline.................................................... 4.1% 783.0 519.6
Pumping equipment, buildings and tanks...................... 4.6% 427.1 355.4
Vehicles, office and communications equipment............... 13.9% 28.8 27.4
Construction in progress.................................... -- 115.8 87.4
-------- --------
1,487.3 1,008.5
Accumulated depreciation.................................... (191.1) (158.2)
-------- --------
$1,296.2 $ 850.3
======== ========
</TABLE>
6. DEBT
<TABLE>
<CAPTION>
DECEMBER 31,
------------------
1998 1997
---- ----
<S> <C> <C>
First Mortgage Notes........................................ $ 310.0 $ 310.0
Revolving Credit Facility Agreement......................... 305.0 153.0
Senior Unsecured Notes, Net................................. 199.5 --
------- -------
$ 814.5 $ 463.0
======= =======
</TABLE>
FIRST MORTGAGE NOTES
The First Mortgage Notes ("Notes") are secured by a first mortgage on
substantially all of the property, plant and equipment of the Partnership and
are due and payable in ten equal annual installments beginning 2002. The
interest rate on the Notes is 9.15% per annum, payable semi-annually. The Notes
contain various restrictive covenants applicable to the Partnership, and
restrictions on the incurrence of additional indebtedness including compliance
with certain issuance tests. The General Partner believes these issuance tests
will not negatively impact the Partnership's ability to finance current
expansion projects. Under the Note Agreements, the Partnership is permitted to
make cash distributions not more frequently than quarterly in an amount not to
exceed Available Cash (Note 3) for the immediately preceding calendar quarter.
REVOLVING CREDIT FACILITY AGREEMENT
The Partnership has a $350.0 million ($205.0 million prior to June 18,
1998) Revolving Credit Facility Agreement scheduled to mature during September
2003, but is subject to extension. Each year, on the anniversary date of the
facility, the current maturity date may be extended by one year subject to the
approval of the lending banks. Upon drawdown, the loans are secured by a first
lien on the mortgaged property that ranks equally with the Notes or may be fully
collateralized with U.S. or Canadian government securities. The facility
contains restrictive covenants substantially identical to those in the Note
Agreements, provides for borrowing at variable interest rates and currently
attracts a facility fee of 0.075% (1997 - 0.075%, 1996 - 0.085%) per annum on
the entire $350.0 million ($205.0 million prior to June 18, 1998). At December
31, 1998, $305.0 million of the facility was utilized and is classified as
long-term debt (1997 - $153.0 million). The interest rate on loans averaged 5.8%
(1997 - 6.2%; 1996 - 6.8%) and was 5.5% at the end of 1998 (1997 - 6.2%).
F-10
<PAGE> 41
LAKEHEAD PIPE LINE PARTNERS, L.P.
NOTES TO THE 1998 CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
6. DEBT (CONTINUED)
SENIOR UNSECURED NOTES
On October 1, 1998, the Operating Partnership issued a total of $200.0
million Senior Unsecured Notes in two tranches of $100.0 million. The first
tranche of $100 million carries an interest rate of 7.00% and matures in 2018.
The second tranche carries an interest rate of 7.125% and matures in 2028.
Interest on both tranches is payable semi-annually. The Senior Unsecured Notes
do not contain any financial tests restricting the issuance of additional
indebtedness.
INTEREST
Interest expense includes $2.1 million related to accrued rate refunds
(1997 -$3.5 million; 1996 - $9.7 million) and is net of amounts capitalized of
$25.5 million (1997 - $3.3 million; 1996 - $2.4 million). Interest paid amounted
to $44.4 million (1997 - $39.9 million; 1996 - $44.8 million).
7. RELATED PARTY TRANSACTIONS
The Partnership, which does not have any employees, uses the services of
the General Partner and its affiliates for managing and operating its pipeline
business. These services, which are reimbursed at cost in accordance with
service agreements, amounted to $34.9 million (1997 - $33.2 million; 1996 -$33.9
million) and are included in operating and administrative expenses. At December
31, 1998, the Partnership has accounts payable to the General Partner and
affiliates of $2.9 million (1997 - $3.9 million).
Under the terms of the Revolving Credit Facility Agreement, the Services
Partnership and the Partnership may draw down funds up to a combined maximum of
$350.0 million ($205.0 million prior to June 18, 1998). The Partnership is
entitled to require the Services Partnership to repay any amounts owed by the
Services Partnership in order to allow the Partnership to borrow thereunder.
During 1996, the Partnership paid the Services Partnership a standby fee of $0.4
million for this entitlement. Effective September 1996, the standby fee was
eliminated and replaced with a facility fee, which the Partnership pays directly
to the lenders. The Partnership will continue to have borrowing priority over
the Services Partnership. At December 31, 1998, the Services Partnership had no
borrowings under the facility.
The Partnership has entered into an easement acquisition agreement with
Enbridge Holdings (Mustang) Inc. ("Enbridge Mustang") (formerly IPL Patoka
Pipeline Holdings (U.S.A.) Inc.), an affiliate of the General Partner. Enbridge
Mustang has acquired certain real property for the purpose of granting pipeline
easements to the Partnership for a new pipeline constructed by the Partnership
from Superior, Wisconsin to Chicago, Illinois. The Partnership has made
non-interest bearing cash advances to Enbridge Mustang in order to provide for
these real property acquisitions by Enbridge Mustang. These advances amounted to
$32.0 million at December 31, 1998 (1997 - $6.5 million).
During the third quarter of 1998, the Board of Directors of the General
Partner approved a $200.0 million lending facility from the General Partner to
the Partnership to provide an alternative backup source of funds in the event
that a temporary disruption in the capital markets delays anticipated debt and
equity issuances. Under this facility, in late September 1998, the Partnership
borrowed $37.0 million from the General Partner at an interest rate of 8.75%.
This loan was repaid in early October upon completion of the Operating
Partnership's Senior Unsecured Note offering. No amounts were outstanding at
December 31, 1998.
F-11
<PAGE> 42
LAKEHEAD PIPE LINE PARTNERS, L.P.
NOTES TO THE 1998 CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
8. MAJOR CUSTOMERS
Operating revenue received from major customers was as follows:
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-----------------------
1998 1997 1996
---- ---- ----
<S> <C> <C> <C>
Amoco Oil Company........................................... $57.9 $60.7 $63.2
Mobil Oil Company of Canada Ltd............................. $40.0 $42.5 $37.2
Imperial Oil Limited........................................ $33.6 $33.2 $35.4
</TABLE>
The Partnership has a concentration of trade receivables from companies
operating in the oil and gas industry. These receivables are collateralized by
the crude oil and other products contained in the Partnership's pipeline and
storage facilities.
9. ACCRUED RATE REFUNDS AND RELATED INTEREST
In October 1996, the FERC approved a July 1996 agreement ("Settlement
Agreement") between the Partnership and customer representatives on all
outstanding contested tariff rates. The Settlement Agreement resulted in an
approximate tariff rate reduction of 6% and total rate refunds and related
interest of $120.0 million through the effective date of October 1, 1996.
The Partnership provided for $42.6 million of rate refunds and related
interest in 1996 to reflect the Settlement Agreement. Of the amount provided,
rate refunds related to 1996 of $12.8 million have reduced operating revenue,
with prior years' portion, $20.1 million, separately stated as a provision for
prior years' rate refunds. Rate refund interest expense for 1996 and prior year
amounts totaling $9.7 million were recorded in interest expense. The balance of
the $120.0 million of accrued rate refunds and related interest required under
the Settlement Agreement was provided for prior to 1996.
Refunds required under the Settlement Agreement began in 1996 with $41.8
million repaid during the fourth quarter of 1996, with the remaining balance
being repaid through a 10% reduction on future rates. This reduction will
continue until all refunds have been made, which is expected to remain effective
until sometime during the second half of 1999. During 1998, refunds of $28.5
million (1997 - $27.7 million) were made to customers and interest expense of
$2.1 million (1997 - $3.5 million) was recorded by the Partnership. Interest
will continue to accrue on the unpaid balance based on the 90-day Treasury bill
rate.
10. CONTINGENCIES
ENVIRONMENT
The Partnership is subject to federal and state laws and regulations
relating to the protection of the environment. Environmental risk is inherent to
liquid pipeline operations and the Partnership could, at times, be subject to
environmental cleanup and enforcement actions. The General Partner manages this
environmental risk through appropriate environmental policies and practices to
minimize the impact to the Partnership. To the extent that the Partnership is
unable to recover environmental costs in its rates (if not covered through
insurance), the General Partner has agreed to indemnify the Partnership from and
against any costs relating to environmental liabilities associated with the
pipeline system prior to its transfer to the Partnership in 1991. This excludes
any liabilities resulting from a change in laws after such transfer. The
Partnership continues to voluntarily investigate past leak sites for the purpose
of assessing whether any remediation is required in light of current
regulations, and to date no material environmental risks have been identified.
F-12
<PAGE> 43
LAKEHEAD PIPE LINE PARTNERS, L.P.
NOTES TO THE 1998 CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
10. CONTINGENCIES (CONTINUED)
OIL IN CUSTODY
The Partnership transports crude oil and natural gas liquids ("NGL") owned
by its customers for a fee. The volume of liquid hydrocarbons in the
Partnership's pipeline system at any one time approximates 12 million barrels,
virtually all of which is owned by the Partnership's customers. Under terms of
the Partnership's tariffs, losses of crude oil not resulting from direct
negligence of the Partnership may be apportioned among its customers. In
addition, the Partnership maintains adequate property insurance coverage with
respect to crude oil and NGL in the Partnership's custody.
11. FAIR VALUE OF FINANCIAL INSTRUMENTS
The carrying amounts of cash equivalents and short-term investments
approximate fair value. The short-term investments consist of high quality
commercial paper.
Based on the borrowing rates currently available for instruments with
similar terms and remaining maturities, the carrying value of borrowings under
the Revolving Credit Facility approximate fair value, the fair value of the
First Mortgage Notes approximates $369 million (1997 - $363 million) and the
fair value of the Senior Unsecured Notes approximates $209 million. Due to
defined contractual arrangements, refinancing of the First Mortgage Notes and
Senior Unsecured Notes would not result in any financial benefit to the
Partnership.
F-13
<PAGE> 44
LAKEHEAD PIPE LINE PARTNERS, L.P.
SUPPLEMENTARY INFORMATION (UNAUDITED)
SELECTED QUARTERLY FINANCIAL DATA
(DOLLARS IN MILLIONS, EXCEPT PER UNIT AMOUNTS)
<TABLE>
<CAPTION>
FIRST SECOND THIRD FOURTH TOTAL
----- ------ ----- ------ -----
<S> <C> <C> <C> <C> <C>
1998 QUARTERS
Operating revenue.................... $ 72.9 $ 74.4 $ 70.2 $ 70.2 $ 287.7
Operating income..................... $ 28.0 $ 28.6 $ 27.2 $ 21.6 $ 105.4
Net income........................... $ 22.9 $ 24.2 $ 22.6 $ 18.8 $ 88.5
Net income per unit(1)............... $ 0.80 $ 0.85 $ 0.78 $ 0.64 $ 3.07
</TABLE>
<TABLE>
<CAPTION>
FIRST SECOND THIRD FOURTH TOTAL
----- ------ ----- ------ -----
<S> <C> <C> <C> <C> <C>
1997 QUARTERS
Operating revenue.................... $ 68.7 $ 66.9 $ 72.3 $ 74.2 $ 282.1
Operating income..................... $ 25.7 $ 26.9 $ 27.1 $ 28.4 $ 108.1
Net income........................... $ 17.7 $ 19.2 $ 19.4 $ 22.0 $ 78.3
Net income per unit(1)............... $ 0.71 $ 0.75 $ 0.76 $ 0.80 $ 3.02
</TABLE>
- ---------------
(1) The General Partner's allocation of net income has been deducted before
calculating net income per unit.
F-14
<PAGE> 1
EXHIBIT 10.19
PROMISSORY NOTE
$37,000,000.00 Dated: September 30, 1998
FOR VALUE RECEIVED, the undersigned, LAKEHEAD PIPE LINE COMPANY, LIMITED
PARTNERSHIP, a Delaware limited partnership (the "Borrower"), HEREBY PROMISES TO
PAY to the order of LAKEHEAD PIPE LINE COMPANY, INC., a Delaware corporation
(the "Lender") at its offices in Duluth, Minnesota or as otherwise directed, in
lawful money of the United States of America and in immediately available funds,
the principal sum of THIRTY SEVEN MILLION AND NO/100 DOLLARS ($37,000,000.00),
together with interest on the outstanding principal balance from day to day
remaining unpaid as herein specified in monthly installments as follows:
(a) On October 1, 1998, and continuing monthly and regularly
thereafter on the first day of each and every month until September 1,
2013, interest only at the Loan Interest Rate on the outstanding principal,
with the interest rate being adjusted on each Interest Rate Adjustment
Date, shall be due and payable; and
(b) A final installment in the amount of all outstanding principal,
plus accrued and unpaid interest, shall be due and payable on the Maturity
Date.
INTEREST
Each change in the rate of interest charged hereunder shall become
effective, without notice to Borrower, on each Interest Rate Adjustment Date.
Without limiting the foregoing, Lender shall use its best efforts to notify
Borrower of any change in the interest rate hereunder, and until Borrower is
notified by Lender of such change, Borrower may continue to make payments
hereunder at the prior interest rate; provided, however, nothing contained
herein shall be construed as limiting Lender's right to collect interest at the
rates described in this Note and Borrower will promptly pay any shortfall
occasioned by Borrower's underpayment of interest on demand. In the event of
overpayment, Lender will apply the overpayment against the next accruing payment
of interest.
It is the intention of the parties hereto that the Lender shall conform
strictly to usury laws applicable to it. Accordingly, if the transactions
contemplated hereby would be usurious as to the Lender under laws applicable to
it (including the laws of the United States of America or any other jurisdiction
whose laws may be mandatorily applicable to the Lender notwithstanding the other
provisions of this Note) then, in that event, notwithstanding anything to the
contrary herein, it is agreed as follows:
(a) the aggregate of all consideration which constitutes interest
under applicable law that is contracted for, taken, reserved, charged or
received by the Lender shall under no circumstances exceed the maximum
amount allowed by such applicable law, and any excess shall be canceled
automatically, and if theretofore paid, shall be credited by the Lender on
the principal amount outstanding hereunder (or, to the extent that the
principal amount outstanding hereunder shall have been or would thereby be
paid in full, refunded by Lender to Borrower); and
(b) in the event that the Maturity Date is accelerated by reason of
any Event of Default, or in the event of any prepayment, then such
consideration that constitutes interest under applicable law may never
include more than the maximum amount allowed by such applicable law, and
excess interest, if any, provided for herein shall be canceled
automatically by the Lender as of the date of such acceleration or
prepayment and, if theretofore paid, shall be credited by the Lender on the
principal amount outstanding hereunder (or, to the extent that the
principal amount shall have been or would thereby be paid in full, refunded
by Lender to the Borrower).
All sums paid or agreed to be paid to the Lender for the use, forbearance
or detention of sums due hereunder shall, to the extent permitted by applicable
law, be amortized, prorated, allocated and spread in
<PAGE> 2
equal parts throughout the full term hereof until payment in full so that the
rate or amount of interest on account of the principal outstanding hereunder
does not exceed the maximum amount and rate of interest allowed by such
applicable law. If at any time and from time to time (i) the amount of interest
payable to the Lender on any date shall be computed at the Highest Lawful Rate,
and (ii) in respect of any subsequent interest computation period the amount of
interest otherwise payable to the Lender would be less than the amount of
interest payable to the Lender computed at the Highest Lawful Rate, then the
amount of interest payable to the Lender in respect of such subsequent interest
computation period shall continue to be computed at the Highest Lawful Rate
until the total amount of interest payable hereunder shall equal the total
amount of interest which would have been payable if the total amount of interest
had been computed without giving effect to this paragraph.
DEFINITIONS
As used in this Note, the following terms shall have the respective
meanings indicated below:
"Acquired Assets" shall mean, at any date of determination, any assets
other than Newly Constructed Assets acquired by the Borrower or any of its
Subsidiaries from any Person at any time during the four consecutive calendar
quarter period used to determine Consolidated Cash Flow as at such date of
determination.
"Applicable Margin" means the following percentages for the specified
levels, which shall be determined on each Quarterly Reporting Date for the
following calendar quarter:
PRICING CHART
<TABLE>
<CAPTION>
LEVELS APPLICABLE MARGIN
------ -----------------
<S> <C>
I........................................................... .50%
II.......................................................... .625%
III......................................................... .8125%
IV.......................................................... 1.25%
V........................................................... 2.50%
</TABLE>
For purposes of the foregoing Pricing Chart, the applicable levels shall be
determined as set forth below. The Cash Flow/Interest Coverage Pricing
Ratio will be determined by the stated ratio on each Quarterly Certificate.
In the event that Borrower does not deliver a Quarterly Certificate on any
Quarterly Reporting Date, Level V shall apply during the following quarter
until such Quarterly Certificate is delivered.
Level I shall be applicable, as at any date of determination, if the
Cash Flow/Interest Coverage Pricing Ratio as at such date shall be equal to
or greater than 3.75;
Level II shall be applicable, as at any date of determination, if the
Cash Flow/Interest Coverage Pricing Ratio as at such date shall be equal to
or greater than 3.00 but less than 3.75;
Level III shall be applicable, as at any date of determination, if the
Cash Flow/Interest Coverage Pricing Ratio as at such date shall be equal to
or greater than 2.50 but less than 3.00;
Level IV shall be applicable, as at any date of determination, if the
Cash Flow/Interest Coverage Pricing Ratio as at such date shall be equal to
or greater than 2.25 but less than 2.50; and
Level V shall be applicable, as at any date of determination, if the
Cash Flow/Interest Coverage Pricing Ratio as at such date shall be less
than 2.25.
"Business Day" shall mean any day excluding Saturday, Sunday, and any other
day on which banks are required or authorized to close in New York City, New
York or Chicago, Illinois and, if the applicable day relates to LIBOR Rate
Loans, on which trading is carried on by and between banks in Dollar deposits in
the interbank eurodollar market.
<PAGE> 3
"Capital Lease" shall mean, as applied to any Person, any lease of any
property (whether real, personal or mixed) by such Person (as lessee or
guarantor or other surety) which would, in accordance with GAAP, be required to
be classified and accounted for as a capital lease on a balance sheet of such
Person.
"Cash Flow/Interest Coverage Pricing Ratio" means, as of the end of each
calendar quarter, the quotient obtained by dividing (A) the sum of (a) EBITDA
plus (b) to the extent not included in EBITDA, EBITDA with respect to Acquired
Assets, excluding, however, (c) any nonrecurring amounts (including, without
limitation, amounts paid to shippers (or accrued) pursuant to decisions of
regulatory bodies or negotiated settlement agreements) to the extent included in
the foregoing clauses (a) and (b), less (d) the amount of investment income
generated by such Person and its Subsidiaries on a consolidated basis from the
investment of cash and cash equivalents, in each case for the period of four
consecutive calendar quarters ending on such calendar quarter ending date by (B)
the sum of (x) the Consolidated Gross Interest Expense less (y) the amount of
investment income generated by such Person and its Subsidiaries on a
consolidated basis from the investment of cash and cash equivalents for the same
four consecutive calendar quarter period.
"Consolidated Cash Flow" shall mean, at any date of determination, (a) all
cash receipts of the Borrower and its Subsidiaries from operations (except in
respect of Acquired Assets or Newly Constructed Assets which are treated below
in this definition) during the period of four consecutive calendar quarters most
recently ended prior to such date of determination, but excluding (A) cash
proceeds from Interim Capital Transactions and (B) net cash receipts from
operations in respect of assets sold pursuant to Section 8.07(c), less (b) the
amount of investment income received by such Person and its Subsidiaries on a
consolidated basis during such period from the investment of cash and cash
equivalents, less (c) the sum of:
(i) all cash operating expenditures of the Borrower and its
Subsidiaries during such period (including, without limitation, cash
operating expenditures of Subsidiaries prior to the acquisition thereof by
the Borrower and taxes paid by the Borrower as an entity and by its
Subsidiaries during such period),
(ii) an amount equal to the actual reserves, if any, established by
the general partner of the Borrower during such period for the incremental
revenues collected by the Borrower and its Subsidiaries during such period
pursuant to a rate increase which revenues are, at such date of
determination, subject to possible refund,
(iii) the amount, if any, by which cash reserves outstanding as of the
end of the period that the general partner of the Borrower determines in
its reasonable discretion to be necessary or appropriate to provide for the
future cash payment of expenditures of the type referred to in clause (i)
above exceeds such cash reserves outstanding at the beginning of such
period, plus
(iv) the amount, if any, by which cash reserves outstanding at the end
of the period that the general partner of the Borrower determines in its
reasonable discretion to be necessary or appropriate to provide funds for
distributions with respect to the four calendar quarters following the end
of such period exceeds such cash reserves outstanding at the beginning of
such period,
plus (d) with respect to Acquired Assets, an amount equal to the cash receipts
generated by such Acquired Assets (less actual cash operating expenditures paid
with respect to such Acquired Assets) during the four consecutive calendar
quarters ending on the date of determination (regardless of the ownership
thereof during such period), plus (e) with respect to Newly Constructed Assets,
an amount equal to the product obtained by multiplying (i) the cost thereof by
(ii) the interest rate applicable to United States Treasury Bonds with a
maturity of 30 years (which interest rate shall be determined as of the
applicable date of determination) plus 1%, all as determined on a consolidated
basis and after elimination of intercompany items.
"Consolidated Gross Interest Expense" means, as of the end of any calendar
quarter, Consolidated Interest Expense plus the amount of capitalized interest
(as determined in accordance with GAAP) of the Borrower and its consolidated
Subsidiaries during the same four calendar quarters used to determine
Consolidated Interest Expense as of such calendar quarter-end.
"Consolidated Interest Expense" means, as of the end of any calendar
quarter, the interest expense of the Borrower and its consolidated Subsidiaries
incurred for the financing of the ordinary course of business
<PAGE> 4
operations of the Borrower and its consolidated Subsidiaries during the period
of the four most recently completed calendar quarters ending on such calendar
quarter ending date (as determined in accordance with GAAP).
"EBITDA" shall mean, for any period, (a) Net Income for such period plus
(b) depreciation, amortization, interest expense, and income taxes for such
period, in each case to the extent deducted in determining Net Income for such
period, all as determined on a consolidated basis for the Borrower and its
Subsidiaries.
"GAAP" shall mean generally accepted accounting principles in effect in the
United States from time to time.
"Highest Lawful Rate" means the maximum nonusurious interest rate that may
under applicable law be contracted for, charged, received, taken or reserved by
Lender in connection with loans made by Lender.
"Indebtedness" of any Person shall mean (without duplication):
(a) any indebtedness for borrowed money which such Person has directly
or indirectly created, incurred or assumed;
(b) any indebtedness, whether or not for borrowed money, secured by
any Lien in respect of property owned by such Person, whether or not such
Person has assumed or become liable for the payment of such indebtedness,
provided that the amount of such Indebtedness if not so assumed shall in no
event be deemed to be greater than the fair market value from time to time
(as determined in good faith by such Person) of the property subject to
such Lien;
(c) any indebtedness, whether or not for borrowed money, with respect
to which such Person has become directly or indirectly liable and which
represents the deferred purchase price (or a portion thereof) or has been
incurred to finance the purchase price (or a portion thereof) of any
property, service or business acquired by such Person, whether by purchase,
consolidation, merger or otherwise, excluding, however, trade accounts
payable incurred in the ordinary course of business by the Person whose
Indebtedness is being determined;
(d) any obligations under Capital Leases to the extent such
obligations would, in accordance with GAAP, appear on a balance sheet of
such Person;
(e) any indebtedness of the character referred to in clause (a), (b),
or (d) of this definition deemed to be extinguished under GAAP but for
which such Person remains legally liable; and
(f) any indebtedness of any other Person of the character referred to
in clause (a), (b), (c), (d) or (e) of this definition with respect to
which the Person whose Indebtedness is being determined has become liable
by way of a Guaranty.
"Interest Rate Adjustment Date" means the date hereof and the first day of
each and every month thereafter prior to the Maturity Date.
"Interim Capital Transactions" shall mean (a) borrowings and sales of debt
securities (other than for working capital purposes and other than for items
purchased on open account in the ordinary course of business) by the Borrower,
(b) sales of equity interests by the Borrower or capital contributions to the
Borrower, and (c) sales or other voluntary or involuntary dispositions of any
assets of the Borrower (other than (i) sales or other dispositions of inventory
in the ordinary course of business, (ii) sales or other dispositions of other
current assets including accounts receivable or (iii) sales or other
dispositions of assets as a part of normal retirements or replacements), in each
case prior to the commencement of the dissolution and liquidation of the
Borrower.
"Lien" shall mean, as to any Person, any mortgage, lien (statutory or
otherwise), pledge, reservation, right of entry, encroachment, easement,
right-of-way, restrictive covenant, license, charge, security interest or other
encumbrance in or on, or any interest or title of any vendor, lessor, lender or
other secured party to or of such Person under any conditional sale or other
title retention agreement or Capital Lease with respect to, any
<PAGE> 5
property or asset owned or held by such Person, or the signing or filing of a
financing statement with respect to any of the foregoing which names such Person
as debtor, or the signing of any security agreement with respect to any of the
foregoing authorizing any other party as the secured party thereunder to file
any financing statement or any other agreement to give or grant any of the
foregoing. For the purposes of this Note, a Person shall be deemed to be the
owner of any asset which it has placed in trust for the benefit of the holders
of Indebtedness of such Person and such trust shall be deemed to be a Lien if
such Indebtedness is deemed to be extinguished under GAAP and such Person
remains legally liable therefor.
"Loan Interest Rate" means from the date hereof until the next Interest
Rate Adjustment Date 8.75% per annum and thereafter means the lesser of (i) the
Highest Lawful Rate, or (ii) the sum of the LIBOR Rate plus the Applicable
Margin.
"LIBOR Rate" means the rate per annum (rounded to 1/16 of 1%) at which
dollar deposits approximately equal in principal amount to the entire principal
amount of this Note and for a period of one (1) month are offered, as quoted on
the display designated as page 4136 on the Telerate Service (or such other
display as may replace Page 4136 on the Telerate Service), or such other
nationally-recognized rate quoting service selected by Lender.
"Maturity Date" means September 30, 2013.
"Net Income" shall mean, for any period, the net earnings income (or loss)
after taxes for such period taken as a single accounting period on a
consolidated basis for the Borrower and its Subsidiaries determined in
accordance with GAAP.
"Newly Constructed Assets" shall mean, at any date of determination, any
pipeline assets and facilities related thereto which are intended to be included
in the common carrier rate base of the Borrower and which are then being either
constructed by or on behalf of the Borrower or any of its Subsidiaries or if
already owned by the Borrower or its Subsidiaries, substantially rehabilitated
or enhanced.
"Person" means any individual, partnership, firm, corporation, association,
joint venture, trust or other entity or enterprise, or any governmental or
political subdivision or agency, department or instrumentality thereof.
"Quarterly Certificate" means a certificate signed by an officer of the
general partner of Borrower, stating (i) what the Cash Flow/Interest Coverage
Pricing Ratio is for the immediately preceding calendar quarter and (ii) that
there exists no Event of Default hereunder.
"Quarterly Reporting Date" means the first day of each January, April, July
and November during the term hereof.
"Subsidiary" shall mean any corporation, association, partnership, joint
venture or other business entity at least a majority (by number of votes) of the
stock of any class or classes (or equivalent interests) of which is at the time
owned by a Person or by one or more Subsidiaries of such Person or by a Person
and one or more Subsidiaries of such Person, if the holders of the stock of such
class or classes (or equivalent interests) (a) are ordinarily, in the absence of
contingencies, entitled to vote for the election of a majority of the directors
(or Persons performing similar functions) of such business entity, even though
the right so to vote has been suspended by the happening of such a contingency,
or (b) are at the time entitled, as such holders, to vote for the election of
the majority of the directors (or Persons performing similar functions) of such
business entity, whether or not the right so to vote exists by reason of the
happening of a contingency.
COVENANTS
During the term hereof, Borrower shall comply with the following covenants:
(a) Borrower shall deliver to Lender a Quarterly Certificate on each
Quarterly Reporting Date.
(b) Borrower will at all times preserve and keep in full force and
effect its partnership existence.
<PAGE> 6
(c) Borrower will at all times comply with all laws and regulations
applicable to it, the failure with which to comply, individually or in the
aggregate, would materially adversely affect its business or its
operations.
(d) Borrower will, and will cause each Subsidiary to, pay all taxes,
assessments and other governmental charges imposed upon it or any of its
properties or assets or in respect of any of its franchises, business,
income or profits when the same become due and payable, but in any event
before any penalty or interest accrues thereon, and all claims (including,
without limitation, claims for labor, materials and supplies) for sums
which have become due and payable and which by law have or might become a
Lien upon any of its properties or assets; provided that no such tax,
assessment, charge or claim need be paid or reimbursed if being contested
in good faith by appropriate proceedings properly initiated and diligently
conducted and if such reserves or other appropriate provision, if any, as
shall be required by GAAP shall have been made therefor and be adequate in
its good faith judgment.
(e) Borrower will maintain or cause to be maintained in good repair,
working order and condition all properties used or useful in its business
and that of its Subsidiaries and from time to time will make or cause to be
made all appropriate repairs, renewals and replacements thereof. Borrower
will maintain or cause to be maintained, with financially sound and
reputable insurance companies, on commercially reasonable terms, insurance
with respect to its properties and business and the properties and business
of its Subsidiaries of the types and in the amounts generally carried by
similar businesses in the same industry.
DEFAULT; REMEDIES
It shall be a default hereunder upon the occurrence of any of the following
(each an "Event of Default"):
(a) Borrower shall default in the payment of any amount due hereunder,
and such default shall continue for more than five (5) Business Days; or
(b) Borrower shall fail to comply with any covenant contained herein,
and such default shall not have been remedied within thirty (30) days after
written notice thereof is received by Borrower; or
(c) Borrower or any Subsidiary of Borrower (as principal or guarantor
or other surety) shall default in the payment of any amount of principal
of, or premium or interest on Indebtedness which is outstanding in a
principal amount of at least $15,000,000 (other than the Indebtedness
governed by this Note); or any event shall occur or condition shall exist
in respect of any Indebtedness which is outstanding in a principal amount
of at least $15,000,000 (other than the Indebtedness governed by this Note)
or of any mortgage, indenture or other agreement relating thereto, the
effect of which is to cause (or to permit one or more Persons to cause)
such Indebtedness to become due and payable before its stated maturity or
before its regularly scheduled dates of payment, and such default, event or
condition shall continue for more than the period of grace, if any,
specified therein and shall not have been waived; or
(d) The filing by or behalf of Borrower or its general partner of a
voluntary petition or an answer seeking reorganization, arrangement,
readjustment of its debts or for any other relief under any bankruptcy,
reorganization, compromise, arrangement, insolvency, readjustment of debt,
or dissolution, liquidation, or similar act or law, state or federal, now
or hereafter existing ("Bankruptcy Law"), or any action by Borrower or its
general partner for, or consent or acquiescence to, the appointment of a
receiver, trustee or other custodian of Borrower or its general partner or
of all or a substantial part of its property; or the making by Borrower or
its general partner of any assignment for the benefit of creditors; or the
admission by Borrower or its general partner in writing of its inability to
pay its debts as they become due; or
(e) Any of the following: (i) the filing of any involuntary petition
against Borrower or its general partner in bankruptcy or seeking
reorganization, arrangement, readjustment of its debts or for any other
relief under any Bankruptcy Law and an order for relief by a court having
jurisdiction in the premises
<PAGE> 7
shall have been issued or entered therein; (ii) any other similar relief
shall be granted under any applicable federal or state law; (iii) a decree
or order of a court having jurisdiction in the premises for the appointment
of a receiver, liquidator, sequestrator, trustee or other officer having
similar powers over Borrower or its general partner or over all or a part
of its property shall have been entered; (iv) the involuntary appointment
of an interim receiver, trustee or other custodian of Borrower or its
general partner or of all or a substantial part of its property; or (v) the
issuance of a warrant of attachment, execution or similar process against
any substantial part of the property of Borrower or its general partner,
and the continuance of any such event described in the foregoing clauses
(i) -- (v), both inclusive, for 60 consecutive days unless dismissed,
bonded to the satisfaction of the court having jurisdiction in the premises
or discharged; or
(f) A final judgment or judgments (which is or are non-appealable or
which has not or have not been stayed pending appeal or as to which all
rights to appeal have expired or been exhausted) shall be rendered against
Borrower for the payment of money in excess of $15,000,000 and the same
shall not be discharged or execution thereon stayed pending appeal within
60 days after entry thereof, or, in the event of such a stay, such judgment
shall not be discharged within 30 days after such stay expires.
Upon an Event of Default, the principal of this Note and any accrued interest
shall become, forthwith, due and payable without presentment, demand, protest or
other notice of any kind (including, without limitation, notice of intent to
accelerate), all of which are hereby waived by Borrower.
MISCELLANEOUS
The principal balance under this Note and any accrued interest thereon may
be prepaid in whole or in part at any time without premium or penalty.
The Borrower and any and all endorsers, guarantors and sureties hereof
severally waive grace, demand, presentment for payment, notice of dishonor or
default or intent to accelerate, protest and notice of protest and diligence in
collecting and bringing of suit against any party hereto, and agree to all
renewals, extensions or partial payments hereon and to any release or
substitution of security herefor, in whole or in part, with or without notice,
before or after maturity.
This Note shall be governed by, and construed and interpreted in accordance
with, the laws of the State of Texas and any applicable laws of the United
States of America.
LAKEHEAD PIPE LINE COMPANY, LIMITED
PARTNERSHIP
By: Lakehead Pipe Line Company, Inc.,
its general partner
By:
----------------------------------
Name: Mark A. Maki
Title: Chief Accountant
By:
----------------------------------
Name: Scott R. Wilson
Title: Treasurer
<PAGE> 1
EXHIBIT 10.21
UNITED STATES OF AMERICA
BEFORE THE
FEDERAL ENERGY REGULATORY COMMISSION
Lakehead Pipe Line Company, ) Docket No. OR99-______
Limited Partnership )
OFFER OF SETTLEMENT
Pursuant to 18 C.F.R. Section 385.602 (1998), Lakehead Pipe Line Company,
Limited Partnership ("Lakehead"), a common carrier oil pipeline regulated by
this Commission, hereby submits this Offer of Settlement. By this offer,
Lakehead seeks Commission approval for a comprehensive settlement agreement
(hereafter the "1998 Settlement Agreement"), which was entered into on October
21, 1998 by Lakehead and the Canadian Association of Petroleum Producers
("CAPP"), the principal representative of the producers Lakehead serves. The
1998 Settlement Agreement is intended to govern the rate recovery by Lakehead
of the costs of three projects for the expansion of Lakehead's capacity and the
broadening of its capability to transport heavier crude oil. Its primary
features are:
(1) a cost-of-service based surcharge, for 15 years, on terms included as
part of the settlement of Lakehead's most recent rate case, for recovery of
costs associated with Lakehead's portion of the System Expansion Program Phase
II ("SEP II");
(2) an agreed-upon flat-rate surcharge for 15 years for recovery of costs
associated with Lakehead's portion of the so-called Terrace Expansion Project
("Terrace"); and
<PAGE> 2
(3) an increase in the existing heavy oil surcharge from 20 percent of the
standard rate to as much as 22 percent to reflect a planned operational change
permitting shippers to transport heavier grades of crude through the Lakehead
system.
In the case of the two expansion-related surcharges, the terms of those
surcharges have been extensively negotiated between CAPP and Lakehead's
Canadian affiliate Enbridge Pipelines, Inc. ("Enbridge"),1 on behalf of itself
and Lakehead. The resulting agreements have been formally approved by the
National Energy Board of Canada ("NEB"), and the terms of the SEP II surcharge
were included in the Lakehead rate settlement approved by this Commission on
October 18, 1996. The proposed change to the heavy oil surcharge has also been
agreed to by CAPP and the affected heavy oil producers, and has been approved
in principle by the NEB. This change is conditional on CAPP giving notice to
Enbridge and Lakehead of CAPP's intent to have the higher viscosity limit
implemented, and on Lakehead's operations being altered to permit movement of
much heavier crudes than could be accommodated in the past.
This Offer of Settlement is being filed now, in advance of any rate filing
or litigated proceeding, to facilitate public notice of the proposed changes
and to permit timely Commission consideration of those changes before they are
scheduled to take effect in January 1999. Following the procedures in Rule
602, the Commission should approve the 1998 Settlement Agreement as being fair,
reasonable and in the public interest, and should grant a
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1 Enbridge was formerly known as Interprovincial Pipe Line Inc. ("IPL"). The
name was changed to Enbridge effective October 7, 1998. For simplicity and
clarity, "Enbridge" will be used throughout this pleading to refer to the
former IPL, even in historical references.
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<PAGE> 3
limited waiver of the tariff filing rules to permit implementation of the
resulting surcharges and longer-term rate provisions.
EXECUTIVE SUMMARY
Lakehead and Enbridge each operate separate portions of a single oil
pipeline system connecting Western Canadian oil fields to major U.S. Midwest
and Eastern Canadian refining centers. Due largely to sharply increased oil
production in Western Canada and the attractiveness of the U.S. market in and
around Chicago, the existing capacity of the Enbridge/Lakehead system has been
consistently oversubscribed in recent years. This bottleneck, in turn, has had
a negative effect on Canadian oil producers' revenues from sale of their oil,
as well as a deleterious effect on U.S. refiners seeking access to Western
Canadian sources of supply.
In an attempt to relieve this capacity shortfall, and in consultation with
the producers, Enbridge and Lakehead embarked on a series of major, staged
expansions designed to add capacity in increments over a period of years. SEP
II was in its formative stages at the time of the settlement of Lakehead's most
recent FERC rate case in 1996 ("1996 FERC Settlement").2 General provision was
made in the 1996 FERC Settlement for the future rate treatment of the SEP II
expansion costs through an incremental cost-based surcharge. After that
settlement, Lakehead and Enbridge, in consultation with CAPP, undertook a
further series of expansions known as the Terrace project. The Terrace
project, in conjunction with the additional capacity made available through SEP
II, is expected to facilitate increased production as well as enhanced
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2 The 1996 FERC Settlement is Attachment A to the 1998 Settlement Agreement
(Ex. 1 hereto).
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<PAGE> 4
net sales revenues (i.e., "netbacks") to the producers. These projects are
also expected to increase the availability of Canadian crude oil for U.S.
Midwest refiners. The total cost of these expansions, however, is daunting -
more than $1 billion (U.S.) over a period of ten years, much of it concentrated
in the early period. While the expanded capacity will yield increased
throughput - and thus increased revenue - for Enbridge and Lakehead even at
existing rates, that increased revenue is insufficient by itself to cover the
entire cost of these massive projects.
Accordingly, Enbridge and Lakehead have worked with the producers,
represented by CAPP, to develop cost recovery mechanisms that are fair,
reasonable, consistent and flexible enough to accommodate even unexpected
contingencies without provoking a renewal of the burdensome tariff litigation
that both sides have previously endured. As noted above, Enbridge, Lakehead
and CAPP initially reached agreement on a rate surcharge for SEP II costs, the
terms of which were included in the 1996 FERC Settlement. In anticipation of
the Terrace project, the parties sought to negotiate an even more innovative
agreement. The result is the Terrace Toll Agreement (Attachment B to the 1998
Settlement Agreement (Ex. 1)), which embodies a set of principles for recovery
of the Terrace costs during the next 15 years. The centerpiece of this
agreement is a fixed-rate surcharge on Enbridge and Lakehead's rates to remain
in effect through 2013, with only limited adjustments pursuant to the
agreement.
The Terrace Toll Agreement has already been reviewed and approved by the
NEB under its guidelines for negotiated settlements and the just and reasonable
rate standard.3 By this
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3 The NEB approved the draft of the Terrace Toll Agreement as it existed in
June 1998. The details of the agreement have been further refined since that
time, resulting in the definitive statement, dated October 21, 1998, which
appears as Attachment B to the 1998 Settlement Agreement (Ex. 1). None of
the essential substantive terms has been altered in the definitive agreement,
which will be resubmitted to the NEB for review in the very near future.
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<PAGE> 5
Offer of Settlement, Lakehead seeks similar approval from this Commission for
the Terrace surcharge, and confirmation of the terms of the SEP II surcharge,
so that these innovative agreements can be implemented unconditionally as
expeditiously as possible. As described below, Lakehead also seeks a limited
waiver of the technical tariff regulations to the extent necessary to permit
the surcharges to be put in place in Lakehead's FERC tariffs. This limited
waiver should also extend to the proposed increase in Lakehead's heavy oil
surcharge to reflect the ability of Lakehead to accept heavier crude oil once
the SEP II facilities are in service.4
BACKGROUND
Lakehead and Enbridge collectively own and operate the longest crude oil
pipeline system in North America. The system stretches from Western Canada
through the Great Lakes region of the United States, to Eastern Canada and
upstate New York. All portions of the system north of the international border
are owned and operated by Enbridge, while all portions of the system in the
United States are owned and operated by Lakehead. Approximately 90 percent of
the throughput transported by Lakehead originates on the Enbridge system in
Canada. About two-thirds of that volume is delivered in the United States and
the remainder is delivered in Eastern Canada. The rates charged by Enbridge
for the portion of the transportation service
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4 The specific provisions from which a waiver is sought are 18 C.F.R. Section
Section 342.1, 342.3(a) and 342.4 (1998).
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<PAGE> 6
that occurs in Canada are regulated by the NEB. This Commission regulates the
rates charged by Lakehead for its service within the United States.5
Since 1995, Enbridge's rates in Canada have been governed by an Incentive
Toll Settlement Agreement that was negotiated between Enbridge and CAPP. CAPP
represents Canadian oil producers that collectively account for more than 95
percent of the throughput transported on the Enbridge/Lakehead system. The
Incentive Toll Settlement Agreement was approved by the NEB on March 24, 1995.
In general, it provides a methodology for setting rates in Canada based on an
incentive ratemaking approach designed to align the interests of Enbridge and
its shippers.6
1996 FERC Settlement
Lakehead's rates are currently governed by the 1996 FERC Settlement, which
resolved Lakehead's most recent major rate proceeding before this Commission.
That proceeding originated with a rate filing by Lakehead on April 1, 1992 that
was protested by CAPP and other parties, leading to a series of phased hearings
before a FERC administrative law judge. The judge issued an initial decision in
Phase I of the proceeding on December 7, 1993, Lakehead Pipe Line Co., Limited
Partnership, 65 FERC Paragraph 63,021 (1993), and a Phase II initial decision on
October 31, 1994. Lakehead Pipe Line Co., Limited Partnership, 69 FERC
Paragraph 63,006 (1994).
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5 Lakehead is a master limited partnership whose units are traded on the New
York Stock Exchange. Approximately 84 percent of its partnership interests
are held by public unitholders (including other corporations), with the
remaining approximately 16 percent being held by Lakehead Pipe Line Company,
Inc., the general partner of the Lakehead partnership and a wholly owned
subsidiary of Enbridge.
6 Although the incentive methodology is intended to continue indefinitely,
specific parameters for setting rates have been established only through
1999. Enbridge and CAPP have commenced negotiations regarding continuation of
the agreement beyond 1999.
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<PAGE> 7
The Commission issued its decision in Phase I on June 15, 1995. Opinion No.
397, Lakehead Pipe Line Co., Limited Partnership, 71 FERC Paragraph 61,338
(1995). The Commission largely reaffirmed that decision on rehearing in Opinion
No. 397-A, Lakehead Pipe Line Co., Limited Partnership, 75 FERC Paragraph 61,181
(1996), which was issued on May 1, 1996.
While the Commission's Phase I decision was pending on petitions for review
filed by Lakehead and CAPP in the U.S. Court of Appeals for the District of
Columbia Circuit, the parties reached a settlement of the entire dispute,
including both Phase I and Phase II rates, as well as future rates for at least
five years. That settlement provided that Lakehead would provide monetary
relief totaling $120 million for past rates found not to be just and reasonable,
with the relief divided between direct refunds and a 10 percent surcredit
applicable to future rates.7 1996 FERC Settlement (Ex. 1, Att. A) Paragraph 7.
Lakehead also instituted an immediate 6 percent decrease in its filed rates for
the future, providing an aggregate annual revenue decrease of approximately $17
million. In return, CAPP and the Alberta Department of Energy agreed not to
challenge Lakehead's rates for five years, provided those rates do not (other
than as permitted in the settlement) exceed the amount allowed under the
Commission's indexing regulations. Id. Paragraphs 12, 13.
Under the 1996 FERC Settlement, the limitation of Lakehead's rates to the
indexed ceilings has two specific exceptions. First, to the extent Lakehead
undertakes system capacity expansions during the five-year period, including
specifically SEP II, the costs of such expansions can be recovered through an
incremental surcharge to Lakehead's rates calculated in
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<PAGE> 8
accordance with Appendix D to the 1996 FERC Settlement. Id. Paragraph 13.A.
Appendix D, in turn, is an excerpt from the Enbridge Incentive Toll Settlement
Agreement. The general effect of paragraph 13.A. and Appendix D is to permit
Lakehead to calculate a separate cost of service for the SEP II expansion
facilities, using the agreed-upon terms, and to add the resulting tariff
increment onto the existing rates as a tariff surcharge. The second exception
is that Lakehead is permitted to increase its indexed rates to reflect so-called
"non-routine adjustments" to the extent reflected in Appendix E to the FERC 1996
Settlement, which is an excerpt from paragraph 7.0 of the Enbridge Incentive
Toll Settlement Agreement. 1996 FERC Settlement (Ex. 1, Att. A) Paragraph
13.B.
SEP II
The SEP II expansion project commenced in January 1996 with Enbridge's
filing of an application with the NEB for a certificate of public convenience
and necessity for the portion of the SEP II facilities in Canada. As reflected
in the NEB order approving SEP II, the goal at that time was to increase the
delivery capacity from Western Canada into Chicago by approximately 120,000
barrels per day (b/d).8 This increase was expected to result from two primary
sources - (1) construction of a new Enbridge line and associated facilities
from
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7 The 10 percent surcredit is scheduled to remain in effect until such time as
the remainder of the $120 million, plus interest, has been returned to
Lakehead's shippers. Under current projections, the surcredit will expire in
the second half of 1999.
8 See Reasons for Decision, Interprovincial Pipe Line Inc., Docket OH-1-96
(NEB, July 1996) (hereafter "NEB SEP II Decision"). A copy of the NEB SEP II
Decision is attached hereto as Exhibit 2.
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<PAGE> 9
Edmonton to Hardisty, Alberta and (2) construction of a new Lakehead line (Line
14) from Superior, Wisconsin, to Chicago.9
While the SEP II project was pending before the NEB, Enbridge, Lakehead
and CAPP concluded an agreement regarding the future rate treatment of the SEP
II costs (the so-called "Risk Sharing Agreement" or "RSA").10 The Risk Sharing
Agreement provides, in general, that the SEP II costs will be recovered during
a 15-year period through a cost-of-service calculation based on terms outlined
in the agreement. Included in those terms are variations in the return on
equity to reflect the degree of utilization of the facilities. In essence, at
higher utilization rates, Enbridge and Lakehead can recover a higher return on
equity, whereas at lower utilization rates, the return on equity falls below
the level normally allowed. The RSA also provides that the rates will be
calculated "in a manner and amount consistent with existing toll [i.e., rate]
design for Lakehead and [Enbridge]." 1996 FERC Settlement (Ex. 1, Att. A),
Appendix D.11
The RSA was submitted to the NEB for approval on May 31, 1996. In
approving the agreement, the NEB noted that no party had opposed it and that
the so-called "Shippers Group" had characterized the agreement as "an
innovative and appropriate method of ensuring that some of the risk associated
with potential under-utilization of expansion capacity would be
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9 SEP II also involved other modifications and upgrades to various Enbridge
and Lakehead facilities that increase both the overall capacity of the
system and its capability to handle heavier grades of crude oil.
10 A copy of the Risk Sharing Agreement is attached to the FERC Settlement
(Ex. 1, Att. A) as Appendix D.
11 Exhibit 3 hereto is an Explanatory Statement describing in more detail the
terms of the Risk Sharing Agreement as it applies to Lakehead.
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<PAGE> 10
borne by the pipeline, rather than by shippers." NEB SEP II Decision (Ex. 2)
at 13. The Board therefore concluded that the Risk Sharing Agreement "has
broad shipper support" and "the settlement represented by the RSA is just and
reasonable in the circumstances." Id. at 14.
As noted earlier, the RSA was also incorporated into the 1996 FERC
Settlement, which was then being negotiated between Lakehead and CAPP.
Paragraph 13.A. of the 1996 FERC Settlement provides that the SEP II surcharge
is an exception to the general requirement that Lakehead's settlement rates not
be increased by more than the amount allowed by the FERC index. That paragraph
also specifies that the terms of the surcharge are to be governed by the RSA
(which was attached as Appendix D), and that, in calculating the surcharge,
Lakehead will utilize a tax allowance "equal to 30 percent of the tax allowance
that would apply if Lakehead were a corporation," reflecting the fact that
under Opinion Nos. 397 and 297-A Lakehead is not entitled to a tax allowance on
the portion of its net income attributable to individual unitholders. The 1996
FERC Settlement was submitted to the Commission on September 5, 1996, and was
not opposed by any shipper or other party. It was approved by the Commission
by letter order on October 18, 1996. 77 FERC Paragraph 61,051 (1996).
Terrace
The Terrace project originated out of the realization that SEP II would
not, by itself, be sufficient to eliminate the capacity constraints on the
Enbridge/Lakehead system, in light of the projected growth in the volume of
Western Canadian production available for transportation to Chicago and beyond.
The importance of Terrace is highlighted in the NEB order approving
construction by Enbridge of the Phase I facilities for the project. Reasons
for
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<PAGE> 11
Decision, Interprovincial Pipe Line Inc., Docket OH-1-98 (NEB, June 9, 1998)
(hereafter "NEB Terrace Decision").12 In that decision, the NEB accepted as
reasonable Enbridge's supply forecasts indicating that production of Western
Canadian crude oil is expected to increase from 1,980,000 barrels per day (b/d)
in 1996 to 2,580,000 b/d in 2009. NEB Terrace Decision (Ex. 4) at 12. The NEB
also accepted Enbridge's forecast that its system would remain
capacity-constrained for the foreseeable future if it is not expanded
significantly. Id. at 16. Noting Enbridge's projection that the expanded
capacity would increase the revenues of Western Canadian producers by $5.6
billion on a net present value basis over the period 2000 to 2010, id. at 17,
the NEB concluded:
some of the benefits of this expansion would include
the production of crude oil that would otherwise be
shut in or sold to less attractive markets due to
apportionment [i.e., prorationing] on [Enbridge], as
well as a potential improvement in the competitive
position of western Canadian crude oil deliveries in
[the U.S. Midwest] as a result of increased
reliability of these deliveries.
Id.
In the course of planning and executing the Terrace project, Lakehead and
Enbridge have consulted and coordinated closely with CAPP as the representative
of the interests of the Western Canadian producers seeking expanded access to
the markets served by Lakehead. This coordination has involved the scope and
timing of the various expansion stages, as well as the proposed rate treatment
of the expansion costs. Having been through extensive rate litigation both at
this agency (for Lakehead) and at the NEB (for Enbridge), the pipelines and
CAPP were interested in avoiding a tariff dispute over the expansion costs if
at all possible. Both sides also
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12 For the Commission's convenience, a copy of the NEB Terrace Decision is
attached as Exhibit 4.
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<PAGE> 12
saw opportunities to put in place innovative tariff structures that would
appropriately balance the risks between the shippers and the carrier.
The provision in the 1996 FERC Settlement relating to the SEP II expansion
was an early example of this forward-thinking attempt to anticipate and resolve
potential disputes before they arise. The parties took an even more innovative
approach in structuring an agreement regarding the treatment of costs
associated with Terrace. The Terrace Toll Agreement (Ex. 1, Att. B) is a
statement of principles intended to govern the recovery of costs for all phases
of the Terrace expansion. The agreement was submitted to the NEB and approved
by the Board in the NEB Terrace Decision. Unlike the SEP II Risk Sharing
Agreement, which contemplates a cost-of-service based surcharge added to the
existing Lakehead rates, the Terrace Toll Agreement provides for a flat
cents-per-barrel surcharge to be kept in place through December 31, 2013,
subject to adjustment only as provided in the agreement.
The provisions of the Terrace Toll Agreement are described in detail in an
Explanatory Statement that is attached as Exhibit 5 to this Offer of Settlement.
In broad summary, the agreement provides that the costs of all phases of the
Terrace expansion project will be recovered by Enbridge and Lakehead
collectively through an incremental surcharge of five cents Canadian (Cdn) per
barrel. Terrace Toll Agreement (Ex. 1, Att. B) Paragraph 7.13 Consistent with
the terms of the Agreement, id. Paragraph 9, Enbridge and Lakehead have agreed
to an initial division in which three cents (Cdn) per barrel will be recovered
by Enbridge and two cents (Cdn)
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13 The base surcharge of five cents (Cdn) applies to transportation of one
barrel of light crude oil from Edmonton, Alberta, to Griffith, Indiana. The
agreement provides that the base surcharge "shall be adjusted on a distance
basis and for commodity credits or surcharges, consistent with [Enbridge]
and [Lakehead]'s then existing [rate] design." Terrace Toll Agreement
(Ex. 1, Att. B) Paragraph 7.
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<PAGE> 13
per barrel will be recovered by Lakehead.14 Using the currency conversion
formula specified in the agreement, this results in a base surcharge of
approximately 1.3 cents (U.S.) per barrel on Lakehead's rates.
Subject only to adjustments specified in the agreement, this 1.3 cent
(U.S.) per barrel surcharge will remain unchanged for the life of the agreement
(through 2013). It is the parties' intent that the surcharge - unlike
Lakehead's underlying rates - will not be subject to indexing, either upwards or
downwards, since the anticipated impact of inflation has already been taken into
account in the negotiation of the surcharge amount and the various adjustments
to it. Thus, barring variances contemplated in the Terrace Toll Agreement,
Lakehead's surcharge would remain at the 1.3 cent (U.S.) per barrel level no
matter what happens with general inflation rates. This means that Lakehead and
Enbridge are absorbing 100 percent of the operating cost risk on this project,
excluding changes to property tax expenses exceeding the forecast amount by
20 percent or more. Id. Paragraph 12. As explained in more detail in the
Explanatory Statement (Ex. 5), with respect to the capital costs of constructing
the expansion facilities, Lakehead and Enbridge bear all of the risk for the
first 5 percent of any cost variation, and 50 percent of the risk after the
first 5 percent. Id. Paragraph 13.15
- ---------------
14 Those proportions correspond generally to the relative levels of investment
in the expansion facilities by Enbridge and Lakehead.
15 The agreement also permits future adjustment of the 1.3-cent surcharge for
such items as agreed-upon scope and timing changes to the project, capital
cost and construction cost variances, and variations in bond rates or equity
rates of return by more than two percentage points from stipulated 1998
levels. Id. Paragraph 17. In addition, Lakehead may receive an additional
increment as specified in the agreement if the constructed facilities are
underutilized due to lack of total throughput at designated levels.
Id. Paragraph 19.
- 13 -
<PAGE> 14
The Terrace Toll Agreement assumes that all phases of the planned expansion
will go forward at CAPP's request. Id. Paragraph 3. It is essentially designed
to recover the costs of all phases - including both capital and operating costs
- - on a levelized basis through the fixed per-barrel surcharge. In the event CAPP
were to elect not to go forward with future phases of the expansion, Enbridge
and Lakehead would substitute a cost-of-service based surcharge (similar to the
one agreed upon for SEP II) in place of the fixed rate surcharge set forth in
the agreement. Id. Paragraph 14. This cost-of-service surcharge would take
account not only of Lakehead's future unrecovered costs, but also of revenues
foregone by Lakehead during the period the 1.3 cent (U.S.) surcharge was in
place instead of a higher cost-of-service based surcharge. Id. If Lakehead and
Enbridge fail to achieve the capacity increases forecast for the various phases
of the Terrace project, they are required to refund one cent (Cdn) per barrel
for each 5,500 cubic meters per day (m3/d) (approximately 34,600 barrels per
day) by which capacity falls short. Id. Paragraph 17.
350 Centistoke Project
The third component of the 1998 Settlement Agreement involves the
surcharge for heavy crude oil. Lakehead's existing rates provide, for each
point-to-point movement, a standard rate for light petroleum, and associated
surcharges and surcredits for varying categories of petroleum such as heavy and
medium (both of which are more viscous and thus more costly to transport) and
gasolines/condensates and natural gas liquids ("NGL") (both of which are less
- 14 -
<PAGE> 15
viscous and thus less costly to transport). The existing surcharges and
surcredits range from a 20 percent surcharge for heavy crude to a 10 percent
surcredit for NGL.
Historically, as a result of operational limitations, Enbridge and
Lakehead have defined "Heavy Crude Petroleum" as a commodity having a density
of 904 kg/m3 to 927 kg/m3 and a viscosity of 100 to 250 centistokes.16 As a
result, heavy oil shippers seeking to transport crude with a higher density or
viscosity have been required to blend their crude with a diluent (usually
condensate) to lower its viscosity to an acceptable level. This blending
requirement raises the cost of transporting heavy crude and has at times
strained supplies of condensate in Western Canada.
In response to industry concern over this issue, Enbridge and Lakehead
developed the so-called "350 Centistoke Project." This project involves
certain modifications to the Enbridge/Lakehead system, principally in the form
of added capability to heat the heavier crudes prior to transportation, that
will permit the shipment of heavy crudes up to a viscosity of 350 centistokes.
As part of the development of this project, Enbridge and Lakehead also reached
agreement with industry on the rate implications of transporting these heavier
crudes. In essence, it was agreed that the heavy crude surcharge would be
increased from 20 percent to up to 22 percent at such time as the heavier
grades of crude begin to be accepted on the system. This increase reflects the
additional cost on average to move the heavier grades of crude relative
- ---------------
16 A "centistoke" is a unit of kinematic viscosity which is commonly used as
measure of the viscosity of crude petroleum.
- 15 -
<PAGE> 16
to the standard rate, as determined through the same computer modeling process
that produced the existing surcharges and surcredits.17
The 350 Centistoke Project was presented to the NEB for approval of both
the new facilities and the proposed rate treatment on April 22, 1997. The
Board issued its approval of the project on August 21, 1997.18 The approval
order states:
The Board notes that the 350 Centistoke Project was
developed between [Enbridge] and an industry task
force represented by heavy oil interests and has
received the formal support of [CAPP]. The Alberta
Department of Energy and Pan Canadian Petroleum
Limited have filed letters in support of the project.
The Board further notes that no party has expressed
any concerns with [Enbridge's] application.
NEB 350 Centistoke Decision (Ex. 7) at 1. The Board thus "approved in
principle a two percentage point surcharge (to 22 percent) for heavy crude
petroleum. . . . " Id. at 2.
- ---------------
17 A copy of Enbridge's application to the NEB for approval of the 350
Centistoke Project, and CAPP's letter of agreement to the terms of the
project (hereafter collectively the "350 Centistoke Agreement") is
Attachment C to the 1998 Settlement Agreement (Ex. 1). An Explanatory
Statement describing the 350 Centistoke Agreement is attached hereto as
Exhibit 6.
18 A copy of the NEB 350 Centistoke Decision is attached hereto
as Exhibit 7.
- 16 -
<PAGE> 17
DISCUSSION
The public interest and the Commission's policies encouraging settlements
strongly favor implementation in Lakehead's tariffs of the SEP II, Terrace and
350 Centistoke agreements, all of which are consolidated in the 1998 Settlement
Agreement. Because of the long-term nature of these agreements, Commission
approval will facilitate their implementation both now and in future Lakehead
rate filings.19
I. THE COMMISSION'S PRO-SETTLEMENT POLICIES SUPPORT IMPLEMENTATION OF THE
1998 SETTLEMENT AGREEMENT
The Commission has long maintained a policy favoring the voluntary
resolution of controversies involving regulated companies.20 In particular,
the Commission has consistently recognized that the parties directly involved
in a matter can often structure a solution better adapted to their particular
circumstances than the general rules that necessarily are designed to cover a
wide variety of cases.21 The Commission thus generally approves
- ---------------
19 The Commission has broad discretion to waive its regulations as necessary to
achieve its statutory mandate to serve the broader public interest. See,
e.g., 18 C.F.R. Section 385.101(e). That discretion is more than sufficient
in this case to justify the limited waiver of the indexing rules necessary to
permit Lakehead to go forward with the innovative agreements negotiated with
CAPP and approved by the NEB.
20 E.g., Northern Wasco County People's Utility District, 60 FERC Paragraph
61,087, at 61,280-81 (1992) ("The Commission encourages voluntary settlements
as beneficial to the orderly and expeditious conduct of its business, and
gives substantial deference to consensual resolutions that are consistent
with the Commission's statutory responsibilities."); Order No. 561, FERC
Stats. & Regs. Paragraph 30,985, at 30,941 (The final rule "retains the
Commission's current policy of encouraging settlements of rate issues at any
stage in our proceedings.").
21 See Tennessee Gas Pipeline Company, 20 FERC Paragraph 61,096, at 61,206-07
(1982); Order No. 561, FERC Stats. & Regs. Paragraph 30,985, at 30,959 ("The
Commission . . . finds that allowing rate changes to reflect the agreement of
shippers and the pipeline would further its policy of favoring settlements as
a means for parties to avoid litigation and thereby lessen the regulatory
burdens of all concerned.").
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<PAGE> 18
uncontested settlement agreements when they are shown to be "fair, reasonable
and in the public interest." 18 C.F.R. Section 385.602(g)(3) (1998).
Here, of course, no rate dispute presently exists between Lakehead and any
of its shippers. Nonetheless, Lakehead has looked ahead and attempted to steer
away from a potential future rate dispute by reaching a negotiated agreement on
the manner in which the costs of the SEP II, Terrace and 350 Centistoke
projects will be handled. This negotiated agreement includes provisions
benefiting both sides, and represents a reasonable accommodation of all of the
relevant interests. In fact, as noted above, each of the underlying agreements
has been approved by the NEB as ones "that will result in just and reasonable
tolls." E.g., NEB Terrace Decision (Ex. 4) at 18. The SEP II provisions were
also included in the previously approved 1996 FERC Settlement. Taken as a
whole, therefore, it is clear that the SEP II, Terrace and 350 Centistoke
agreements are a fair and reasonable resolution of the various interests
involved, and that approval of the 1998 Settlement Agreement is strongly in the
public interest.
The SEP II and Terrace expansions are expected to add hundreds of
thousands of barrels of daily capacity to the Enbridge and Lakehead systems.
The incremental capacity added by these expansions standing alone would dwarf
many other pipeline systems in the lower 48 states. In that sense, the
expansions more closely resemble the addition of new service than the
continuation of existing service. On the other hand, none of the projects will
allow Lakehead to serve any additional destinations after the expansions that
it could not previously serve. It will simply be able to deliver substantially
larger quantities of oil to the existing destinations on its system, with
essentially all of the increase coming from shippers that are already utilizing
- 18 -
<PAGE> 19
Lakehead's existing transportation services. Technically, therefore, there is
no "new service" to which a separate cost-of-service or other new rate can be
applied.22
The solution embodied in the SEP II and Terrace agreements is to impose a
separate surcharge on top of the underlying indexed settlement rates. Those
surcharges are based on the incremental cost of adding the new capacity,
measured over a period of years, and are not intended to affect the indexed
rates for pre-existing service levels (which were already set by the 1996 FERC
Settlement). All system shippers will benefit from the substantial increase in
capacity (and consequent avoidance of prorationing of volumes), and these
surcharges consequently are distributed across Lakehead's rates, in accordance
with its pre-existing rate design. As described above, in the case of Terrace,
the surcharge will essentially take the form of a flat rate for 15 years. In
the case of SEP II, since the surcharge is based on the facilities costs
incurred by Lakehead, the surcharge will be recalculated each year to
incorporate such changes as depreciation of the rate base, throughput increases
or decreases, and modifications to the return on equity permitted under the
agreement.23
- ---------------
22 Similarly, the 350 Centistoke project will broaden the category of heavy
crude that can be transported on the Enbridge/Lakehead system, but will not
result in "new" service to any additional destinations or customers.
23 Lakehead will provide an incremental cost of service calculation with
its initial SEP II surcharge filing to be effective upon completion of the
SEP II facilities (currently projected for January 1999), and will update
that cost of service showing for each subsequent year's rate filings. Those
filings will, of course, be subject to challenge by the Commission or any
shipper based on the specific costs included in that year's surcharge. By
this Offer of Settlement, however, Lakehead is seeking confirmation that the
basic concepts set forth in paragraph 13.A. and Appendix D to the 1996 FERC
Settlement will apply to any evaluation of the SEP II surcharge, including
specifically the exemption of that surcharge from indexing and the adjustment
of the equity rate of return in accordance with system utilization.
- 19 -
<PAGE> 20
The exemption of the SEP II and Terrace surcharges from indexing is
supported by two major considerations. First, the principal representative of
the producers of the vast majority of Lakehead's shipments by volume (CAPP) has
expressly agreed to the surcharge mechanism, indicating that the producers that
effectively bear Lakehead's rates expect the surcharge approach to be more
beneficial than alternative regulatory approaches.24 This Commission and the
NEB previously approved settlements incorporating the SEP II mechanism, and,
after thorough consideration, the NEB approved the Terrace agreement as one
that "has broad shipper support" and that "will result in just and reasonable
tolls." NEB Terrace Decision (Ex. 4) at 18. The Terrace Toll Agreement also
includes a number of innovative provisions that are designed to benefit
shippers. These include:
- the amount of the Terrace surcharge is fixed (subject
only to adjustments specified in the agreement) through
December 31, 2013;
- because the surcharge is levelized over a 15-year
period (1999-2013), the shippers avoid a "front-end shock"
from the costs of the expansion project;
- Enbridge and Lakehead are absorbing 100 percent of the
operating cost risk over 15 years, subject only to a narrow
exception for property taxes;
- Enbridge and Lakehead are absorbing the bulk of the
capital cost risks;
- Enbridge and Lakehead are obligated to make refunds if
the expansion facilities do not yield the amount of
additional capacity specified in the agreement; and
- shippers avoid the need to undertake lengthy and
expensive regulatory proceedings regarding Lakehead's
recovery of the Terrace costs.
- ---------------
24 Like Enbridge, Lakehead is an independent pipeline system, unaffiliated with
any of the shippers or producers on the system.
- 20 -
<PAGE> 21
Similarly, Lakehead is benefited by the avoidance of unnecessary regulatory
litigation, as well as the relative certainty and stability of cost recovery
for an expansion which is being undertaken largely for the benefit of the
shippers.
A second major consideration favoring these settlements is that it is
important both to Lakehead and to shippers that the SEP II and Terrace
surcharges be administered under the terms of the relevant agreements, and not
under the generic indexing rules As noted above, one of the key benefits to
shippers from the Terrace settlement is that Lakehead and Enbridge are
absorbing virtually all of the operating cost risk (i.e., the risk that
operating costs for the expansion facilities will exceed projections), as well
as the majority of the capital cost risks. Subjecting the agreed-upon
surcharge to possible upward adjustments for general inflation, as measured by
the PPI-1 index, would deprive the shippers of this benefit, at least in part,
and would defeat the purpose of imposing a fixed-rate charge in place of a
year-by-year cost of service increment. Similarly, from Lakehead's point of
view, it would be unfair to require a reduction in the Terrace surcharge in a
year when the PPI-1 index is negative, since Lakehead would not be able to
avail itself of upward changes in the index. With respect to SEP II, since the
surcharge is designed to track the costs of the expansion year by year, adding
(or subtracting) an indexing adjustment would likewise undermine the central
purpose of the mechanism.
In short, Lakehead and CAPP have fashioned an overall, long-term
settlement to govern recovery of the costs of the SEP II, Terrace and 350
Centistoke projects in a balanced, reasonable manner. The Commission's
pro-settlement policies strongly favor approval of this agreement.
- 21 -
<PAGE> 22
II. THE COMMISSION SHOULD WAIVE ITS TARIFF REGULATIONS AS NECESSARY TO PERMIT
LAKEHEAD TO IMPLEMENT THE SEP II, TERRACE AND 350 CENTISTOKE SURCHARGES
By this Offer of Settlement, Lakehead seeks confirmation that the indexing
rules will not preclude it from filing the SEP II and Terrace surcharges as an
increment on top of its existing indexed settlement rates. Plainly, while the
PPI-1 index was intended to take account of normal variations in operating and
capital costs over time,25 it was never meant to cover the sudden substantial
increase in costs attributable to major expansion programs such as SEP II and
Terrace.26 If Lakehead were constrained to charge only its indexed rates, it
would have no economic incentive to undertake expansions such as these, where
the incremental revenue at the existing rate level would not cover its
increased capital and operating expenses. Yet, given the potential benefit to
the producers (on a net present value basis, $5.6 billion from Terrace alone
according to Enbridge's estimate, see NEB Terrace Decision (Ex. 4) at 17), the
public interest would plainly be harmed by discouraging Lakehead (or other
pipelines in similar situations) from proceeding with needed expansions that
the parties who bear the rates overwhelmingly favor.
With respect to the 350 Centistoke surcharge, similar reasoning applies.
The affected heavy oil producers in Canada supported this surcharge increase
before the NEB, and CAPP, which represents those producers, has agreed to its
implementation by Lakehead.
- ---------------
25 Order No. 561, Revisions to Oil Pipeline Regulations Pursuant to the Energy
Policy Act of 1992, FERC Stats. & Regs. Paragraph 30,985, at 30,951-52
(1993), on reh'g, Order No. 561-A, FERC Stats. & Regs. Paragraph 31,000, at
31,093-98 (1994); petitions for review denied sub nom. Association of Oil
Pipe Lines v. FERC, 83 F.3d 1424, 1433-36 (D.C. Cir. 1996) ("AOPL").
26 Order No. 561-A, FERC Stats. & Regs. Paragraph 31,000, at 31,107; AOPL,
83 F.3d at 1437 n.27.
- 22 -
<PAGE> 23
Although this change is nominally a rate increase above the indexed ceiling, it
is not in fact an increase when measured against the increased facilities
utilization required to transport 350 centistoke crude oil. In other words,
the heavier crude will be more costly to transport because it is more viscous,
and thus, among other things, will tend to displace greater volumes of less
heavy crudes. The increase of up to two percentage points in the heavy crude
surcharge will merely reflect that additional cost burden in a way that is
consistent with Lakehead's existing rate design and that the affected producers
have agreed in advance is fair and reasonable. It will also maintain parity
between the heavy oil surcharge structure for Enbridge and Lakehead.
In sum, the public interest supports approval of the SEP II, Terrace and
350 Centistoke agreements and waiver of the Commission's regulations to the
extent necessary to permit the periodic filing of the appropriate surcharges
and exemption of those surcharges from indexing.
PROPOSED PROCEDURE
Although there is no pending proceeding in which the 1998 Settlement
Agreement can be submitted, Lakehead proposes that the Commission follow its
Rule 602 procedures for processing this Offer of Settlement. In particular,
parties seeking to comment on any aspect of the proposed settlement would be
required to do so within 20 days of the date of the filing of this Offer of
Settlement (Rule 602(f)(2)). Reply comments would then be due 10 days later.
Following receipt of the comments and reply comments (if any), the Commission
could proceed expeditiously to consideration of the Offer of Settlement.
From a timing standpoint, Lakehead intends to file the various surcharges
to be effective upon completion of the various facilities, which may be as
early as January 1999. In order to provide the 30 days notice required by
statute, Lakehead may need to make its tariff
- 23 -
<PAGE> 24
filing as early as December 1998. Lakehead therefore respectfully requests
that the Commission act on this Offer of Settlement as expeditiously as
possible (ideally by no later than December 1, 1998), so that Lakehead will
have an adequate opportunity to prepare the necessary tariff materials for
filing with the Commission on a timely basis.
CONCLUSION
For the reasons set forth above, Lakehead seeks Commission approval of the
1998 Settlement Agreement with CAPP (Ex. 1), and a waiver of the tariff filing
regulations to the extent necessary to permit implementation of the surcharges
as described in that agreement.
Respectfully submitted,
/s/ S. Reed
-------------------------------------------------
Steven H. Brose
Steven Reed
STEPTOE & JOHNSON LLP
1330 Connecticut Avenue, NW
Washington, DC 20036
(202) 429-6232
Counsel for Lakehead Pipe Line Company,
Limited Partnership
October 27, 1998
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<PAGE> 25
Exhibit No. 1
-------------
UNITED STATES OF AMERICA
BEFORE THE
FEDERAL ENERGY REGULATORY COMMISSION
Lakehead Pipe Line Company, ) Docket No. OR 99-____
Limited Partnership )
SETTLEMENT AGREEMENT
--------------------
This Settlement Agreement is executed as of this 21st day of October,
1998, between Lakehead Pipe Line Company, Limited Partnership ("Lakehead") and
the Canadian Association of Petroleum Producers ("CAPP"). The purpose of this
Settlement Agreement is to govern the rate recovery by Lakehead of the costs of
three projects for the expansion of Lakehead's capacity and the broadening of
its capability to transport heavier crude oil. Those three projects are
designated as System Expansion Program Phase II ("SEP II"), the Terrace
Expansion Program ("Terrace") and the 350 Centistoke Project. In consideration
of the provisions set forth in this Settlement Agreement, Lakehead and CAPP
(hereafter the "Settling Parties") agree as follows:
1. Following the execution of this Settlement Agreement, Lakehead will
submit it to the Federal Energy Regulatory Commission ("FERC") for approval as
an offer of settlement under 18 C.F.R. Section 385.602 (1998). The Settling
Parties shall cooperate fully, each at its own expense, in seeking and
supporting such approval.
2. The Settling Parties intend this Settlement Agreement to be an
integrated package, no part of which is separable from the whole. Each side
<PAGE> 26
has made compromises on various positions in order to reach a voluntary
agreement on the proposed rate recovery of the SEP II, Terrace and 350
Centistoke project costs. Accordingly, this Settlement Agreement shall be
deemed withdrawn, and shall no longer be of any force or effect, in the event
the FERC or a reviewing court orders any modification of its terms.
3. The Settling Parties hereby acknowledge and reaffirm their prior
agreement that the costs of Lakehead's portion of the SEP II facilities, which
are now expected to go into service in January 1999, will be recovered by
Lakehead for 15 years through a cost-of-service surcharge in the Lakehead
tariffs to be determined as set forth in paragraph 13.A and Appendix D of the
Settlement Agreement of August 28, 1996 ("1996 Settlement"), which was approved
by the FERC on October 18, 1996. 77 FERC Paragraph 61,051 (1996). A copy of
the 1996 Settlement is attached hereto as Attachment A. The intent of the
Settling Parties is that the initial SEP II surcharge be filed to be effective
at the time the Lakehead SEP II facilities go into service.
4. The Settling Parties further agree that the costs of Lakehead's portion
of the Terrace project will be recovered by Lakehead for 15 years through a
specified surcharge in the Lakehead tariffs on the terms set forth in the
"Terrace Toll Agreement Statement of Principles," executed on October ___, 1998
("Terrace Agreement"). A copy of the Terrace Agreement is attached hereto as
Attachment B. The intent of the Settling Parties is that the initial Terrace
surcharge be filed to be effective at the time the Lakehead Terrace Phase I
facilities go into service.
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<PAGE> 27
5. The Settling Parties also agree that, at such time as Lakehead begins
to offer transportation service for heavy crude petroleum having a viscosity of
up to 350 centistokes, the surcharge in the Lakehead tariffs for the heaviest
grade of crude petroleum will increase from 20 percent of the standard rate to
up to 22 percent of the standard rate on the terms set forth in Attachment C
hereto ("350 Centistoke Agreement"), which constitutes the Settling Parties'
agreement on the rate treatment of the 350 Centistoke Project.
6. This Settlement Agreement is not intended to supersede, replace, limit
or modify the 1996 Settlement previously approved by the FERC.
7. The intent of the Settling Parties is that approval by the FERC of this
Settlement Agreement shall also constitute a waiver of the FERC's technical
tariff filing regulations, specifically including 18 C.F.R. Section 342.1,
342.3(a) and 342.4, to the extent necessary to put the tariff surcharges
provided for in this Settlement Agreement into effect.
8. The Term of this Settlement Agreement shall be for 15 years from the
later of the date when the SEP II surcharge or the Terrace surcharge becomes
effective as provided herein.
9. Approval of this Settlement Agreement by the FERC does not constitute
approval of, or precedent regarding, any principle or issue settled herein.
10. The language of this Settlement Agreement shall, in all cases, be
construed according to its fair meaning and not strictly for or against
- 3 -
<PAGE> 28
any of the Settling Parties. This Settlement Agreement may be modified, amended
or supplemented only by a written instrument executed by the Settling Parties.
WHEREFORE, the foregoing Settlement Agreement is executed on behalf of the
Settling Parties by their duly authorized representatives on the date shown
below.
/s/ O. DeVries /s/ S. R. Wilson
- ---------------------------------- ---------------------------------------
Name: O. Devries Name: Scott Wilson
Title: Manager, Crude Oil & Title: Treasurer
Fiscal Lakehead Pipe Line Company,
Policy Limited Partnership
Canadian Association of
Petroleum Producers
Date: October 21, 1998
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<PAGE> 29
EXHIBIT NO. 1 - ATTACHMENT A
UNITED STATES OF AMERICA
BEFORE THE
FEDERAL ENERGY REGULATORY COMMISSION
Lakehead Pipe Line Company, ) Docket Has. IS92-27-000,
Limited Partnership ) IS93-4-000, 1593-33-000,
) IS94-20-000, 1594-24-000,
) IS95-5-000, 1595-26-000,
) IS95-27-000, and
) IS96-15-000
SETTLEMENT AGREEMENT
This Settlement Agreement is executed as of this 28th day of August, 1996,
between Lakehead Pipe Line Company, Limited Partnership ("Lakehead"), on the
one hand, and the Canadian Association of Petroleum Producers ("CAPP") and the
Alberta Department of Energy ("ADOE") (collectively "CAPP/ADOE"), on the other,
each of which is a party to various rate proceedings before the Federal Energy
Regulatory Commission ("FERC" or "Commission") regarding Lakehead's interstate
tariff rates, as well as judicial review proceedings relating thereto (the
"Lakehead Proceedings"). In consideration of the provisions set forth in this
Settlement Agreement, Lakehead and CAPP/ADOE (collectively the "Settling
Parties") agree as follows:
1. Following the execution of this Settlement Agreement, the Settling
Parties will jointly submit it to the FERC for approval as an offer of
settlement under 18 C.F.R. Section 385.602 (1995). The Settling Parties shall
cooperate fully, each at its own expense, in seeking and supporting such
approval, including the opposition, whether written or otherwise, of all
protests, interventions and comments that seek modification or rejection of the
Settlement
<PAGE> 30
Agreement. Lakehead will prepare the offer of settlement documentation,
including the Explanatory Statement, for submission to the FERC, subject to
approval by CAPP/ADOE. The Settling Parties agree to request and support a
stay of all aspects of the Lakehead Proceedings pending disposition of this
Settlement Agreement.
2. The Settling Parties intend this Settlement Agreement to be an
integrated package, no part of which is segregable from the whole. Each side
has made compromises on various positions in order to reach a voluntary,
negotiated resolution of the Lakehead Proceedings. Accordingly, as provided in
paragraph 15 below, this Settlement Agreement shall be deemed withdrawn, and
shall no longer be of any force or effect, in the event the Commission or a
reviewing court orders a modification of its terms.
3. This Settlement Agreement is intended to resolve all outstanding rate
issues in all pending phases of the Lakehead Proceedings. The FERC Dockets
that are resolved by this Settlement Agreement, and that will be terminated
upon approval of this Settlement Agreement, are listed in Appendix A hereto.
In addition, within 20 days after the date on which this Settlement Agreement
has been approved by the FERC in an order that is no longer subject to judicial
review, the Settling Parties shall withdraw their pending petitions for review
at the United States Court of Appeals for the District of Columbia Circuit in
Docket Nos. 96-1177 and 96-1218.
4. The purpose of this Settlement Agreement is to avoid further
administrative and judicial proceedings with respect to Lakehead's interstate
tariff rates. This Settlement Agreement is not intended to be inconsistent with
any orders of the Commission previously entered in this proceeding, including
specifically Opinion No. 397, 71 FERC (CCH) Paragraph 61,338 (1995) and Opinion
No. 397-A, 75 FERC (CCH) Paragraph 61,181 (1996). This Settlement
- 2 -
<PAGE> 31
Agreement also is not intended to affect the resolution of any issues regarding
facilities for transportation of natural gas liquids on the Lakehead system.
5. Except with respect to paragraph 1 above and as otherwise specified
herein, the Effective Date of this Settlement Agreement shall be the date on
which a FERC order is issued approving the Settlement Agreement without
modification.
6. Notwithstanding the Effective Date as specified in paragraph 5 above,
no later than September 20, 1996, Lakehead shall file the rates set forth in
the pro forma tariff attached as Appendix B hereto ("Appendix B rates") to take
effect on October 1, 1996 pursuant to 18 C.F.R. Section 341.14 (1995), in
place of the rates set forth in Lakehead FERC tariff nos. 18 and 19. The
Appendix B rates constitute a rate decrease of approximately 6 percent
across-the-board, and are intended to bring Lakehead's forward-looking rates
into compliance with Opinion Nos. 397 and 397-A on a reasonable, compromise
basis. If this Settlement Agreement has not received FERC approval prior to
October 1, 1996, it is the intent of the Settling Parties that the Appendix B
rates shall go into effect subject to investigation and refund until such time
as the Settlement Agreement is acted upon by the FERC. If and when the FERC
approves the Settlement Agreement, the refund condition on the Appendix B rates
will be removed and any proceeding instituted with respect to those rates will
be terminated. If the Settlement Agreement is disapproved, disposition of the
Appendix B rates will be subject to further order of the Commission. The
Appendix B rates shall be subject to indexing under 18 C.F.R. Section 342.3
(1995) commencing on July 1, 1997. If and when the Settlement Agreement is
approved by the FERC, CAPP/ADOE agree that they will not thereafter challenge
the Appendix B rates, including any increases or decreases to those rates
permitted under the Commission's indexing regulations, 18 C.F.R. Section 342.3
(1995), in any judicial or administrative forum during the Term of this
Agreement as defined in paragraph 12 below. If the Settlement Agreement is not
approved without
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<PAGE> 32
modification, the Settling Parties shall retain all their rights with respect
to the Lakehead Proceedings.
7. The Settling Parties agree that Lakehead shall fulfill its obligation
to provide a remedy for the past rates found not to be just and reasonable in
Opinion Nos. 397 and 397-A by providing total monetary relief of $120 million
measured as of October 1, 1996. This relief shall be provided in two
components: (1) a Refund Component of $37,144,124 for Phase I of Docket Nos.
IS92-27-000, IS93-3-000 and IS93-33-000, which is addressed in paragraph 8
below, and (2) a Surcredit Component of $82,855,876 for Phase II and subsequent
rate periods, which is addressed in paragraph 9 below.
8. No later than 30 days after the Effective Date defined in paragraph 5
above, Lakehead shall pay the sum of $37,144,124 (measured as of October 1,
1996) to its shippers of record under FERC tariff no. 2, which shall fulfill
Lakehead's refund obligation in Phase I of FERC Docket Nos. IS92-27-000,
IS93-4-000 and IS93-33-000. Interest shall accrue on the Phase I refund amount
of $37,144,124 from October 1, 1996 through the date of payment of the refunds
provided for in this paragraph at the 90-day Treasury bill rate measured for
each quarter at the close of business on the last day of the previous quarter.
The amount to be refunded for the period May 3, 1992 through December 31, 1992
is based upon an agreed-upon test period cost-of-service of $214,830,000, and
the amount to be refunded for the period January 1, 1993 through July 5, 1993
is based upon an agreed-upon test period cost-of-service of $219,090,000. The
amount to be refunded to each shipper shall be calculated by comparing the rate
actually paid to the rate applicable to each service at the agreed-upon
cost-of-service level using Lakehead's existing rate design and shall reflect
the Commission's ruling in Opinion Nos. 397 and 397-A regarding rate floors.
Within 30 days after the date of payment of the Refund Component, Lakehead
shall file a refund report with the Commission showing the amounts
- 4 -
<PAGE> 33
refunded pursuant to this provision. In the event the FERC's initial approval
of the Settlement Agreement is overturned or modified through further
administrative or judicial proceedings after the date of payment of the refunds
as provided hereunder, such that the Lakehead Proceedings are reinstituted,
Lakehead shall be entitled to credit any refunds paid under this Settlement
Agreement against any refund obligation ultimately determined to apply in that
litigation.
9. Within 20 days after the Effective Date as defined in paragraph 5
above, Lakehead shall file a tariff provision in the form set forth in Appendix
C hereto establishing a Surcredit over a period of approximately three years.
The Surcredit shall consist of a 10 percent across-the-board reduction in
Lakehead's interstate tariff rates that shall remain in effect until the
purpose of the Surcredit is accomplished. The purpose of the Surcredit shall
be to reduce Lakehead's tariff revenues by the sum of $82,855,876 plus interest
on the outstanding balance for the period from October 1, 1996 through the
termination of the Surcredit (the total amount, including interest, being
referred to as the Surcredit Amount). Once the Surcredit Amount has been
exhausted, the Surcredit tariff provision may be cancelled by Lakehead pursuant
to paragraph 10 below. The interest component of the Surcredit Amount shall be
calculated monthly on the outstanding balance of the Surcredit Amount using the
90-day Treasury bill rate measured for each quarter at the close of business on
the last day of the previous quarter.
10. Lakehead shall keep account of the cumulative amount of tariff
reductions pursuant to the Surcredit provided under paragraph 9 above. When
the total amount of tariff reductions received is expected to equal the
Surcredit Amount (including interest) within 30 days, Lakehead shall file a
cancellation of the Surcredit tariff provision, together with a report showing
the total amount accumulated, or expected to be accumulated within 30 days,
under the Surcredit. The cancellation of the Surcredit tariff provision shall
be effective upon 30 days' notice. Lakehead shall have no further obligation
to make the Surcredit available after it has
- 5 -
<PAGE> 34
provided Surcredit tariff reductions equal to $82,855,876 as of October 1,
1996, plus interest calculated as set forth in paragraph 9. CAPP/ADOE agree
that, if and when the Commission approves this Settlement Agreement, they will
not challenge the Surcredit or the cancellation of the Surcredit, provided such
cancellation conforms to the terms of this Settlement Agreement, in any
administrative or judicial forum.
11. In the case of the joint tariff between Lakehead and Portal Pipe Line
Company ("Portal") filed to be effective September 1, 1996 (FERC Tariff No.
94), which sets forth joint rates for transportation via Portal and Lakehead
from the Canada-U.S. Border to various Lakehead destinations, Lakehead will,
within 20 days after the Effective Date as defined in paragraph 5 above, file a
tariff reduction applicable to FERC Tariff No. 94. That reduction will lower
each joint rate by an amount at least equal to the difference between (a)
Lakehead's current local tariff rate for Lakehead's portion of the joint
movement and (b) the Appendix B local rate as reduced by the Surcredit. For
the duration of the Surcredit, Lakehead's share of the Portal-Lakehead joint
rates will be no greater than 90 percent of the Appendix B local rates for
corresponding local movements, as adjusted pursuant to paragraphs 6 and 13.
The Settling Parties accordingly agree that Lakehead shall be entitled to
credit 10 percent of the Appendix B local rate otherwise applicable to each
such movement against its Surcredit obligation.
In the event Lakehead enters into additional joint rates in the future,
the Settling Parties agree to negotiate regarding the extent to which (if at
all) any portion of the reduction in Lakehead's share of such joint rates below
the corresponding Appendix B rates should be credited against Lakehead's
Surcredit obligation.
12. The Term of this Settlement Agreement shall be for five years
commencing on the Effective Date.
- 6 -
<PAGE> 35
13. During the Term of this Settlement Agreement, Lakehead may, at its
discretion, seek to file tariffs containing rates in excess of those set forth
in Appendix B as adjusted pursuant to the Commission's index methodology. CAPP
and the ADOE are free to pursue challenges to any such rate filings in excess
of the indexed Appendix B rates, except as follows:
A. CAPP and the ADOE agree not to challenge Lakehead's filing of an
incremental surcharge over and above the indexed Appendix B rates to recover
the costs of a significant enhancement to the Lakehead system agreed to by
CAPP, including the System Expansion Program II ("SEP II") project anticipated
in 1998, provided that the incremental surcharge conforms to the terms set
forth in Appendix D hereto, which were previously agreed to between CAPP,
Lakehead and the Canadian pipeline to which Lakehead connects, Interprovincial
Pipe Line Inc. ("IPL"), and provided further that, in calculating the
surcharge, Lakehead shall utilize a tax allowance that is equal to 30 percent
of the tax allowance that would apply if Lakehead were a corporation; and
B. CAPP and the ADOE agree not to challenge Lakehead's filing of an
incremental surcharge over and above the indexed Appendix B rates, solely to
recover non-routine cost increases limited specifically to the events set forth
in sections 7.1(d) and 7.1(e) of the Incentive Toll Settlement Agreement
Between IPL and CAPP dated February 16, 1995, which are attached as Appendix E
hereto, to the extent events of the type described involve Lakehead.
14. Lakehead agrees that it will file with the FERC, as soon as possible
but in no event later than October 1, 1996, a depreciation study incorporating
a new truncation date of 2020 A.D. and corresponding revised depreciation rates
for Lakehead's assets. CAPP and the ADOE agree that they will support
Commission approval of Lakehead's revised depreciation
- 7 -
<PAGE> 36
rates. CAPP and the ADOE further agree that the depreciation rates to be used
in calculating the incremental surcharge for the SEP II expansion costs
anticipated to be incurred in 1998 shall be determined using the same curves
and economic useful lives as in the depreciation study to be filed under this
paragraph.
15. If the FERC rejects this Settlement Agreement in its entirety, or if
FERC or a reviewing court makes approval of this Settlement Agreement
contingent upon modification of any provision of this Agreement, this
Settlement Agreement shall immediately terminate and shall be deemed withdrawn
as an offer of settlement or for any other purpose, and the Settling Parties
shall be free to pursue all appeals or other courses of action necessary to
protect their rights.
16. This Settlement Agreement is intended to supersede the Settlement
Agreement filed with the Commission by Lakehead and CAPP and the ADOE on March
23, 1995 in Phase II of the Lakehead Proceedings ("March 23 Settlement"). If
and when the present Settlement Agreement is approved by the FERC without
modification, the March 23 Settlement shall be deemed withdrawn and shall no
longer have any force or effect.
17. Unless and until this Settlement Agreement is approved by the FERC
without modification in an order that is final and no longer subject to
judicial review, it shall be privileged and shall not be admissible in evidence
or in any way described or discussed in any proceeding, other than as necessary
to secure approval by the FERC or to permit judicial review of any order of
FERC approving, disapproving or modifying the Settlement Agreement. Approval
of this Settlement Agreement by the FERC does not constitute approval of, or
precedent regarding, any principle or issue settled herein.
18. The language of this Settlement Agreement shall, in all cases, be
construed according to its fair meaning and not strictly for or against any of
the Settling Parties.
- 8 -
<PAGE> 37
This Settlement Agreement may be modified, amended or supplemented only by a
written instrument executed by the Settling Parties. No obligation under this
Settlement Agreement shall be for the benefit of or be enforceable by any third
party.
19. This Settlement Agreement shall be governed by, and construed in
accordance with, federal law to the extent applicable and otherwise by the laws
of the State of Minnesota. It is the intent of the Settling Parties that the
terms of this Settlement Agreement, once approved by the FERC without
modification, shall be enforceable by the FERC.
20. All notices under this Settlement Agreement shall be effective when
deposited in the mails, postage prepaid, certified mail, return receipt
requested, or when dispatched by Federal Express or by telefacsimile, addressed
to the respective Settling Parties at the addresses set forth below:
R. C. Sandahl
Vice President, Operations
Lakehead Pipe Line Company, Inc.
21 West Superior Street
Duluth, MN 55802--2067
Mark Pinney
Manager, Markets & Transportation
Canadian Association of Petroleum Producers
2100, 350 Seventh Avenue, S.W.
Calgary, Alberta T2P 3N9
Canada
Paul Kahler
Senior Regulatory Analyst
Markets and Regulatory Policy
The Alberta Department of Energy
1900, 250 Sixth Avenue, S.W.
Calgary, Alberta T2P 3E7
Canada
- 9 -
<PAGE> 38
A Settling Party may, at any time, substitute in writing a different person or
address for the one shown in this paragraph.
21. This Settlement Agreement may be executed in separate and identical
counterparts.
WHEREFORE, the foregoing Settlement Agreement is executed on behalf of the
Settling Parties by their duly authorized representatives on the date indicated
below.
/s/ L. A. Alexander /s/ S. Reed
- ---------------------------------- -------------------------------------------
Lee A. Alexander Steven Reed
DICKSTEIN SHAPIRO MORIN STEPTOE & JOHNSON LLP
& OSHINSKY LLP 1330 Connecticut Avenue, NW
2101 L Street, NW Washington, DC 20036-1795
Washington, D.C. 20036-1526
Counsel for Lakehead Pipe Line
Counsel for Canadian Association Company, Limited Partnership
of Petroleum Producers and the
Alberta Department of Energy
Dated: August 28, 1996
- 10 -
<PAGE> 39
APPENDIX A
Below is a list of the FERC Docket Numbers associated with Lakehead's rate
proceedings.
IS92-27-000
IS93-4-000
IS93-33-000
IS-94-20-000
IS94-24-000
IS95-5-000
IS95-26-000
IS95-27-000
IS96-15-000
<PAGE> 40
APPENDIX B
Attached is a proforma FERC No. 20 tariff filing reflecting the rates agreed to
in the Settlement Agreement.
<PAGE> 41
FERC NO. 20
CANCELS FERC NO. 18 & 19
DRAFT
LAKEHEAD PIPE LINE COMPANY, LIMITED PARTNERSHIP
III. LOCAL TARIFF APPLYING ON CRUDE PETROLEUM AND NATURAL GAS LIQUIDS
FROM
THE INTERNATIONAL BOUNDARIES NEAR NECHE, NORTH DAKOTA, AND
GRAND ISLAND, NEW YORK, AND POINTS IN THE STATES
OF ILLINOIS, INDIANA, MICHIGAN, AND MINNESOTA
TO
POINTS IN THE STATES OF ILLINOIS, INDIANA, MICHIGAN, MINNESOTA,
NEW YORK, WISCONSIN AND
THE INTERNATIONAL BOUNDARY NEAR MARYSVILLE, MICHIGAN
THE RATES LISTED IN THIS TARIFF ARE FOR THE TRANSPORTATION OF CRUDE PETROLEUM
AND NATURAL GAS LIQUIDS BY THE CARRIER. THE TRANSPORTATION RATES LISTED IN
THIS TARIFF ARE SUBJECT TO THE RULES AND REGULATIONS PUBLISHED IN THE CARRIER'S
TARIFFS FERC NOS. 16 AND 17, SUPPLEMENTS THERETO AND REISSUES THEREOF.
THE PROVISIONS PUBLISHED HEREIN WILL, IF EFFECTIVE, NOT RESULT IN AN EFFECT ON
THE QUALITY OF THE HUMAN ENVIRONMENT.
ISSUED EFFECTIVE
ISSUED BY
P.D. DANIEL
PRESIDENT AND CHIEF OPERATING OFFICER
LAKEHEAD PIPE LINE COMPANY, INC.
GENERAL PARTNER
21 WEST SUPERIOR STREET
DULUTH, MINNESOTA 55802-2067
TEL. (218) 725-0100
<PAGE> 42
PAGE TWO
FERC NO. 20
DRAFT
The rates listed in this tariff are payable in United States currency and are
applicable on the United States movement of Crude Petroleum and Natural Gas
Liquids tendered to the Carrier at established receiving points in the United
States for delivery to established delivery points in the United States.
TRANSPORTATION RATES
Commodities shall be classified on the basis of the density and viscosity of
such commodities at the earlier time of receipt by the Carrier or
Interprovincial Pipe Line Inc. and assessed a transportation rate as listed in
the transportation rate tables below. Density shall be based on l5 degrees
Celsius. Viscosity shall be based on the lower of the temperature of the
commodity at the time of receipt or the Carrier's reference line temperature at
the time of receipt. Where the density of a commodity falls within the density
range of one commodity classification and the viscosity of the commodity falls
within the viscosity range of another commodity classification, then the
commodity shall be deemed to be in the commodity classification with the higher
transportation rate.
NGL - A commodity having a maximum absolute vapor pressure of 1 100 kilopascals
at 37.8 degrees Celsius and a density of up to but not including 600 kilograms
per cubic metre (kg/m3) and a viscosity of up to but not including 0.4 square
millimetres per second (mm2/s) will be classified as NATURAL GAS LIQUIDS.
LIGHT CRUDE PETROLEUM - A commodity having a density from 600 kg/m3 up to but
not including 876 kg/m3 and a viscosity from 0.4 mm2/s up to but not including
20 mm2/s will be classified as LIGHT CRUDE PETROLEUM.
MEDIUM CRUDE PETROLEUM - A commodity having a density from 876 kg/m3 up to but
not including 904 kg/m3 and a viscosity from 20 mm2/s up to but not including
100 mm2/s will be classified as MEDIUM CRUDE PETROLEUM.
HEAVY CRUDE PETROLEUM - A commodity having a density from 904 kg/m3 to 927
kg/m3 inclusive and a viscosity from 100 to 250 mm2/s will be classified as
HEAVY CRUDE PETROLEUM.
NATURAL GAS LIQUIDS
<TABLE>
<S> <C>
TABLE OF TRANSPORTATION RATES FOR NGL IN DOLLARS PER CUBIC METRE
- --------------------------------------------------------------------------------
TO FROM
- --------------------------------------------------------------------------------
International Boundary near Neche, North Dakota
Superior, Wisconsin (c) 1.491 [D]
Rapid River, Michigan (i) 2.457 [U]
Marysville, Michigan (c), (g) 3.576 [D]
International Boundary near Marysville, Michigan(g) 3.410 [D]
- --------------------------------------------------------------------------------
</TABLE>
<PAGE> 43
ALL RATES ON THIS PAGE ARE DECREASES.
PAGE THREE
FERC NO. 20
DRAFT
<TABLE>
<CAPTION>
LIGHT CRUDE PETROLEUM
TABLE OF TRANSPORTATION RATES FOR LIGHT CRUDE PETROLEUM IN DOLLARS PER CUBIC METRE
FROM
---------------------------------------------------------------------------------------------------
International
International Boundary near
TO Boundary near Clearbrook, Mokena, Griffith, Stockbridge, Lewiston, Grand Island,
Neche, North Dakota Minnesota Illinois Indiana Michigan Michigan New York
(a), (b) (b) (b), (h) (b) (b), (f)
- ---------------------- ---------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C>
Clearbrook, Minnesota (c) 0.908 - - - - - -
Superior, Wisconsin (c), (d) 1.704 1.545 - - - - -
Lockport & Mokena, Illinois (c) 3.348 3.188 - - - - -
Griffith, Indiana (c), (e) 3.348 3.188 0.757 0.656 - - -
Bay City, Michigan (c) 3.620 3.461 - - - .967 -
Stockbridge, Michigan (c) 3.986 3.825 1.346 1.346 - - -
Marysville, Michigan (c) 3.986 3.825 1.707 1.707 1.018 1.302 -
International Boundary near
Marysville, Michigan 3.820 3.660 1.553 1.553 0.863 1.147 -
West Seneca, New York (c) 4.078 3.919 1.811 1.811 1.122 1.400 0.498
</TABLE>
<TABLE>
<CAPTION>
MEDIUM CRUDE PETROLEUM
TABLE OF TRANSPORTATION RATES FOR MEDIUM CRUDE PETROLEUM IN DOLLARS PER CUBIC METRE
FROM
---------------------------------------------------------------------------------------------------
International
International Boundary near
TO Boundary near Clearbrook, Mokena, Griffith, Stockbridge, Lewiston, Grand Island,
Neche, North Dakota Minnesota Illinois Indiana Michigan Michigan New York
(a), (b) (b) (b), (h) (b) (b), (f)
- ---------------------- ---------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C>
Clearbrook, Minnesota (c) 948 - - - - - -
Superior, Wisconsin (c), (d) 1.801 1.601 - - - - -
Lockport & Mokena, Illinois (c) 3.583 3.383 - - - - -
Griffith, Indiana (c), (e) 3.583 3.383 0.765 0.656 - - -
Bay City, Michigan (c) 3.878 3.678 - - - . 993 -
Stockbridge, Michigan (c) 4.272 4.071 1.401 1.401 - - -
Marysville, Michigan (c) 4.272 4.071 1.791 1.791 1.047 1.354 -
International Boundary near
Marysville, Michigan 4.107 3.906 1.637 1.637 0.894 1.199 -
West Seneca, New York (c) 4.372 4.172 1.904 1.904 1.159 1.460 0.505
</TABLE>
<PAGE> 44
ALL RATES ON THIS PAGE ARE DECREASES.
PAGE FOUR
FERC NO. 20
DRAFT
<TABLE>
<CAPTION>
HEAVY CRUDE PETROLEUM
TABLE OF TRANSPORTATION RATES FOR HEAVY CRUDE PETROLEUM IN DOLLARS PER CUBIC METRE
FROM
---------------------------------------------------------------------------------------------------
International
International Boundary near
TO Boundary near Clearbrook, Mokena, Griffith, Stockbridge, Lewiston, Grand Island,
Neche, North Dakota Minnesota Illinois Indiana Michigan Michigan New York
(a), (b) (b) (b), (h) (b) (b), (f)
- ---------------------- ---------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C>
Clearbrook, Minnesota (c) 1.009 - - - - - -
Superior, Wisconsin (c), (d) 1.945 1.686 - - - - -
Lockport & Mokena, Illinois (c) 3.936 3.677 - - - - -
Griffith, Indiana (c), (e) 3.936 3.677 0.778 0.656 - - -
Bay City, Michigan (c) 4.263 4.004 - - - 1.030 -
Stockbridge, Michigan (c) 4.702 4.441 1.484 1.484 - - -
Marysville, Michigan (c) 4.702 4.441 1.917 1.917 1.090 1.431 -
International Boundary near
Marysville, Michigan 4.537 4.275 1.765 1.765 0.938 1.278 -
West Seneca, New York (c) 4.813 4.553 2.042 2.042 1.215 1.550 0.516
</TABLE>
(a) RECEIPT TANKAGE - The transportation rates from this receiving point
include a receipt tankage charge of $0.091 per cubic metre.
(b) RECEIPT TERMINALLING - The transportation rates from this receiving point
include a receipt terminalling charge of $0.251 per cubic metre.
(c) DELIVERY TERMINALLING - The transportation rates to this delivery point
include a delivery terminalling charge of $0.165 per cubic metre.
(d) DELIVERY TANKAGE - The transportation rates to this delivery point include
a delivery tankage charge of $0.091 per cubic metre.
(e) In addition to the transportation rate shown, a delivery tankage charge of
$0.091 per cubic metre will be assessed if the Carrier's delivery tankage at
Griffith, Indiana is used by the Shipper.
(f) BREAK-OUT TANKAGE CREDIT - The transportation rates from this receiving
point include a break-out tankage credit of 1.992 cents per hundred cubic metre
miles for light crude petroleum, 2.151 cents per hundred cubic metre miles for
medium crude petroleum, and 2.390 cents per hundred cubic metre miles for heavy
crude petroleum.
(g) BREAK-OUT TANKAGE CREDIT - The transportation rate to this delivery point
includes a break-out tankage credit of 0.541 cents per hundred cubic metre
miles.
(h) In addition to the transportation rate shown, a receipt tankage charge of
$0.091 per cubic metre will be assessed if the Carrier's receipt tankage at
Griffith, Indiana is used by the Shipper.
(i) The toll includes a delivery terminalling charge of $0.182 per cubic metre
and a break-out tankage credit of 0.594 cents per hundred cubic metre miles.
[D] - Denotes decrease in rate.
[U] - Denotes unchanged rate.
<PAGE> 45
APPENDIX C
Attached is a proforma supplement to FERC No. 20 reflecting the 10% surcredit.
<PAGE> 46
SUPPLEMENT
SUPPLEMENT NO. 1
TO FERC NO. 20
DRAFT
LAKEHEAD PIPE LINE COMPANY, LIMITED PARTNERSHIP
LOCAL TARIFF APPLYING ON CRUDE PETROLEUM AND NATURAL GAS LIQUIDS
From
THE INTERNATIONAL BOUNDARIES NEAR NECHE, NORTH DAKOTA, AND
GRAND ISLAND, NEW YORK, AND POINTS IN THE STATES
OF ILLINOIS, INDIANA, MICHIGAN, AND MINNESOTA
to
POINTS IN THE STATES OF ILLINOIS, INDIANA, MICHIGAN, MINNESOTA,
NEW YORK, WISCONSIN AND
THE INTERNATIONAL BOUNDARY NEAR MARYSVILLE, MICHIGAN
ISSUED UNDER AUTHORITY OF 18 CFR 341.4(A). THIS SUPPLEMENT IS ISSUED PURSUANT
TO F.E.R.C. ORDER NO. APPROVING THE SETTLEMENT AGREEMENT BETWEEN LAKEHEAD PIPE
LINE COMPANY, LIMITED PARTNERSHIP, ON THE ONE HAND, AND THE CANADIAN
ASSOCIATION OF PETROLEUM PRODUCERS AND THE ALBERTA DEPARTMENT OF ENERGY ON THE
OTHER. AS PROVIDED IN F.E.R.C. ORDER NO. , ALL RATES IN FERC NO. 20,
SUPPLEMENTS THERETO AND REISSUES THEREOF ARE SUBJECT TO A 10% SURCREDIT
REDUCTION UNTIL SUCH TIME AS THE TOTAL SURCREDIT AMOUNT PLUS INTEREST IS
EXHAUSTED, AT WHICH TIME THE SURCREDIT WILL BE SUBJECT TO CANCELLATION AS
PROVIDED IN THE SETTLEMENT AGREEMENT.
THIS SUPPLEMENT IS ISSUED ON DAYS NOTICE UNDER AUTHORITY OF 18 CFR 341.14.
THIS PUBLICATION IS CONDITIONALLY ACCEPTED SUBJECT TO REFUND PENDING A 30 DAY
REVIEW PERIOD.
THE PROVISIONS PUBLISHED HEREIN WILL, IF EFFECTIVE, NOT RESULT IN AN EFFECT ON
THE QUALITY OF THE HUMAN ENVIRONMENT.
ISSUED EFFECTIVE
ISSUED BY
P.D. DANIEL
PRESIDENT AND CHIEF OPERATING OFFICER
LAKEHEAD PIPE LINE COMPANY, INC.
GENERAL PARTNER
21 WEST SUPERIOR STREET
DULUTH, MINNESOTA 55802-2067
TEL. (218) 725-0100
<PAGE> 47
Schedule of Calculating the Remaining Refund Surcredit
to be Applied to Transportation Revenue invoices in
Accordance with the Negotiated Settlement with CAPP
<TABLE>
<CAPTION>
Assuming Interest
Compounded
Monthly
------------------
<S> <C>
Negotiated Settlement Contingent Rate Refund and Interest
Amount as of October 1,1996 $ 120,000,000
Less the Payment of Phase I of the Contingent Rate Refund
and Interest Amount on October 1, 1996 ($37,144,124)
-------------
Remaining Balance of the Contingent Rate Refund and Interest
to be Repaid by a Surcredit Over the Next Three Years $ 82,855,876
Plus Estimated Interest Calculated on the Remaining Balances of the Rate
Refund over the 3 Year Pay Back Period (See Attached Schedule) $ 7,702,581
-------------
Total Amount of Rate Refund and Estimated Interest to be Paid Over
the Next Three Years $ 90,558,457
Divided by the Long Range Plan Planned Case Total Transportation
Revenue Over the Next Three Years From January 1, 1997
Through December 31, 1999 (See Attached Schedule) $ 899,780,028
-------------
Surcredit as a Percentage of Invoiced Revenue to be Applied to
Each Transportation Revenue Invoice 10%
=============
</TABLE>
N:\Fercdec\Repayment Summary of Refund over next three years monthly
compounding
<PAGE> 48
Lakehead Pipe Line Company, Limited Partnership
Example of Calculation of Interest on Refund Balance Going Forward
(Compounded Monthly)
Included as Part of the Settlement Agreement
<TABLE>
<CAPTION>
Longe Range Plan
90 Day Interest Accrued
BEGINNING T-BILL on Remaining REFUND ENDING Estimated
DESCRIPTION BALANCE RATE BALANCE PAYMENT BALANCE PERIOD REVENUE
(a) (b) ( c) (d) (e) (f) (g)
<S> <C> <C> <C> <C> <C> <C> <C>
10/1/96 120,000,000 (37,144,124) 82,855,876 Jan - 97 24,994
12/31/96 82,855,876 5% 1,035,698 83,891,574 Feb - 97 24,994
1/31/97 83,891,574 5% 349,548 (2,499,400) 81,741,722 Mar - 97 24,994
2/28/97 81,741,722 5% 340,591 (2,499,400) 79,582,913 Apr - 97 24,994
3/31/97 79,582,913 5% 331,595 (2,499,400) 77,415,108 May - 97 24,994
4/30/97 77,415,108 5% 322,563 (2,499,400) 75,238,271 Jun - 97 24,994
5/31/97 75,238,271 5% 313,493 (2,499,400) 73,052,364 Jul - 97 24,994
6/30/97 73,052,364 5% 304,385 (2,499.400) 70,857,349 Aug - 97 24,994
7/31/97 70,857,349 5% 295,239 (2,499,400) 68,653,188 Sep - 97 24,994
8/31/97 68,653,188 5% 286,055 (2,499,400) 66,439,843 Oct - 97 24,994
9/30/97 66,439,843 5% 276,833 (2,499,400) 64,217,277 Nov - 97 24,994
10/31/97 64,217,277 5% 267,572 (2,499,400) 61,985,449 Dec - 97 24,994
11/30/97 61,985,449 5% 258,273 (2,499,400) 59,744,322 Jan - 98 24,994
12/31/97 59,744,322 5% 248,935 (2,499,400) 57,493,857 Feb - 98 24,994
1/31/98 57,493,857 5% 239,558 (2,499,400) 55,234,015 Mar - 98 24,994
2/28/98 55,234,015 5% 230,142 (2,499,400) 52,964,757 Apr - 98 24,994
3/31/98 52,964,757 5% 220,686 (2,499,400) 50,686,043 May - 98 24,994
4/30/98 50,686,043 5% 211,192 (2,499,400) 48,397,835 Jun - 98 24,994
5/31/98 48,397,835 5% 201,658 (2,499,400) 46,100,093 Jul - 98 24,994
</TABLE>
<PAGE> 49
Lakehead Pipe Line Company, Limited Partnership
Example of Calculation of Interest on Refund Balance Going Forward
(Compounded Monthly)
Included as Part of the Settlement Agreement
<TABLE>
<CAPTION>
Longe Range Plan
90 Day Interest Accrued
BEGINNING T-BILL on Remaining REFUND ENDING Estimated
DESCRIPTION BALANCE RATE BALANCE PAYMENT BALANCE PERIOD REVENUE
(a) (b) ( c) (d) (e) (f) (g)
<S> <C> <C> <C> <C> <C> <C> <C>
6/30/98 46,100,093 5% 192,084 (2,499,400) 43,792,777 Aug - 98 24,994
7/31/98 43,792,777 5% 182,470 (2,499,400) 41,475,847 Sep - 98 24,994
8/31/98 41,475,847 5% 172,816 (2,499,400) 39,149,263 Oct - 98 24,994
9/30/98 39,149,263 5% 163,122 (2,499,400) 36,812,985 Nov - 98 24,994
10/31/98 36,812,985 5% 153,387 (2,499,400) 34,466,972 Dec - 98 24,994
11/30/98 34,466,972 5% 143,612 (2,499,400) 32,111,184 Jan - 99 24,994
12/31/98 32,111,184 5% 133,797 (2,499,400) 29,745,581 Feb - 99 24,994
1/31/99 29,745,581 5% 123,940 (2,499,400) 27,370,121 Mar - 99 24,994
2/28/99 27,370,121 5% 114,042 (2,499,400) 24,984,763 Apr - 99 24,994
3/31/99 24,984,763 5% 104,103 (2,499,400) 22,589,466 May - 99 24,994
4/30/99 22,589,466 5% 94,123 (2,499,400) 20,184,189 Jun - 99 24,994
5/31/99 20,184,189 5% 84,101 (2,499,400) 17,768,890 Jul - 99 24,994
6/30/99 17,768,890 5% 74,037 (2,499,400) 15,343,528 Aug - 99 24,994
7/31/99 15,343,528 5% 63,931 (2,499,400) 12,908,059 Sep - 99 24,994
8/31/99 12,908,059 5% 53,784 (2,499,400) 10,462,443 Oct - 99 24,994
9/30/99 10,462,443 5% 43,594 (2,499,400) 8,006,637 Nov - 99 24,994
10/31/99 8,006,637 5% 33,361 (2,499,400) 5,540,598 Dec - 99 24,994
</TABLE>
<PAGE> 50
Lakehead Pipe Line Company, Limited Partnership
Example of Calculation of Interest on Refund Balance Going Forward
(Compounded Monthly)
Included as Part of the Settlement Agreement
<TABLE>
<CAPTION>
Longe Range Plan
90 Day Interest Accrued
BEGINNING T-BILL on Remaining REFUND ENDING Estimated
DESCRIPTION BALANCE RATE BALANCE PAYMENT BALANCE PERIOD REVENUE
(a) (b) ( c) (d) (e) (f) (g)
<S> <C> <C> <C> <C> <C> <C> <C>
11/30/99 5,540,598 5% 23,086 (2,499,400) 3,064,284
12/31/99 3,064,284 5% 12,768 (2,499,400) 577,652
1/31/00 577,652 5% 2,407 (580,059) (0)
7,702,581
================
</TABLE>
(a) = Previous Ending Balance Carried Forward
(b) = 90 Day T-Bill Rater per Settlement Agreement
(c) = Beginning Balance x (b) x 1/12
(d) = Monthly Estimated Revenue x 10%
(e) = Beginning Balance + Interest Accrued - Refund Payments
(f) = Long Range Plan Estimated Revenue
N:\Rates\Refund Interest Calculation Going Forward 2
<PAGE> 51
APPENDIX D
Attached is a copy of the terms and conditions of the Risk Sharing Agreement
which were previously agreed upon by CAPP, Lakehead and IPL.
<PAGE> 52
IPL/LPL and CAPP
SEP Il
Risk Sharing Agreement
<TABLE>
<S> <C>
o Agreement relates to both IPL and Lakehead in respect to the System Expansion Program Phase II facilities and is subject to
National Energy Board and Federal Energy Regulatory Commission approvals.
o At 75% utilization of facilities or 90,000 b/d, the return on deemed expansion equity will be the annual multi-pipeline rate as
determined by the National Energy Board.
o Up to 50% facilities utilization or 60,000 b/d, the return on deemed expansion equity capital would be the multi-pipeline rate
less 3.00%, subject to a minimum rate of return of 7.50% in years 1 through 10 and 8.50% in years 11 through 15.
o Rate of return on deemed expansion equity increases with facilities utilization on a straight line basis, to multi-pipeline
rate plus 3.00% at 100% utilization, subject to a maximum rate of return of 15% during the term of the agreement
o Drag reducing agent costs flow through as a surcharge if appropriate.
o All costs including operating, interest and depreciation costs flow through to tariffs.
o Volume "at risk" would have incremental capacity expansions "stacked" on top.
o Total tolls will be charged in a manner and amount consistent with existing toll design for Lakehead and IPL. Point to point
tolls will reflect a volume-distance allocation of costs. Distribution of revenue and costs between IPL and Lakehead will be at
IPI/LPL's discretion, subject to regulatory approval.
o The agreement is subject to approval of IPL and LPL Boards of Directors.
o The term of the agreement is for 15 years commencing on the date of completion.
o This agreement is without prejudice to any other discussions or negotiations, and does not necessarily reflect the views of any
of the parties as to appropriate costs of capital in either Canada or the United States.
</TABLE>
<PAGE> 53
APPENDIX E
Attached is the applicable section of the Incentive Toll Settlement Agreement
dated February 16, 1995, between Interprovincial Pipe Line Company and the
Canadian Association of Petroleum Producers.
<PAGE> 54
INCENTIVE TOLL PRINCIPLES OF SETTLEMENT
Between
Interprovincial Pipe Line Inc.
And
Canadian Association of Petroleum Producers
7.0 NON-ROUTINE ADJUSTMENTS TO ANNUAL REVENUE REQUIREMENTS
7.1 Circumstances may arise which necessitate adjustments to the annual
Revenue Requirement and resulting tolls. Evens resulting in Non-Routine
Adjustments shall be:
(d) Changes in costs resulting from legislation, regulations,
orders or directions by any government authority which result in
changes to safety or environmental requirements, practices, or
procedures for IPL.
(e) The cost of distinct and new programs necessary to address
new or unanticipated failure mechanisms and significant increases in
the rates of cracking and/or corrosion in the pipeline or other
existing failure mechanisms experienced by IPL.
<PAGE> 55
Exhibit No. 1 - Attachment B
TERRACE TOLL AGREEMENT
STATEMENT OF PRINCIPLES
Enbridge Pipelines Inc. (Enbridge) and the Canadian Association of Petroleum
Producers (CAPP) have agreed that they wish to implement a negotiated toll
structure for the Terrace expansion project.
The Statement of Principles which follows sets forth the principles which the
parties intend to govern the establishment of tolls for all phases of the
Terrace expansion.
Enbridge and CAPP have entered into the negotiated settlement in respect of
Terrace with an appreciation that the Incentive Toll Settlement (ITS) entered
into and approved in 1995 is the subject of renegotiations in respect of
extending the term of the ITS beyond 1999. CAPP and Enbridge have entered into
the Terrace toll agreement on the understanding that the ITS will be
renegotiated consistent with the ITS, and will exclude the matters set out in
Article 8 of the ITS.
The following Schedules are appended to and form a part of these Principles of
Settlement:
"A" Description of Terrace Facilities
"B" Adjustments to the 5 Cents Per Barrel Increment
"C" Adjustments for LPL Phase III Trigger
"D" Fluid Properties Of Liquid Hydrocarbons in Enbridge System: Terrace
Phase I
"E" Forecast Deliveries at Base Capacity (259,100 m3/day)
"F" Forecast Property Taxes
"G" Arbitration Process
"H" Power Calculation
"I" Forecast Operating Costs
1 Negotiated tolls for the Enbridge/LPL Terrace program will recover costs
associated with all facilities associated with all phases of Terrace
Expansion Program. The Terrace Expansion Program is expected to be a phased
capacity addition program intended to add capacity in the years 1999 and
following.
2 The Terrace facilities, the expected capacity increases associated with the
facilities, and the in-service timing are appended as Schedule A. Enbridge
and LPL commit to deliver the additional annual capacity on or before the
dates set out in these Principles. The dates upon which the facilities are
expected to come into service are:
i) January 15, 1999 first in-service of Phase I facilities, providing
15,100 m3/d of incremental capacity from a base system capacity (which
is defined as including SEP II and SEP III 350 Centistoke facilities)
of 259,100 m3/d. The incremental capacity to be provided includes
incremental heavy crude oil capacity on the 24 inch line.
ii) September 30, 1999 second tranche of Phase I capacity in-service,
totaling 26,500 m3/d of incremental from the base.
<PAGE> 56
STATEMENT OF PRINCIPLES
OCTOBER 21, 1998
iii) Hardisty to Kerrobert extension in service September 30,2000 [Phase II]
providing 33,400 m3/d of incremental capacity from the base.
iv) Clearbrook to Superior extension and associated pumping in service
September 30, 2001 [Phase III] providing 56,900 m3/d of incremental
capacity from the base.
v) Mokena to Griffith extension, Line 14 stations in service, Line 14
heater in service between 2002 and 2007 [Future Terrace Phase(s)].
Under the Terrace design, it is anticipated that all Enbridge Western
Canadian pipelines will operate with an annual capacity at ninety percent of
design capacity. Throughput losses due to regular internal inspections are
reflected in the ten percent operating margin. Historically, the reduction
in throughput capacity in months of internal inspections has been 10 percent
on a system basis and 20 percent for heavy crude. Additional throughput
losses have been experienced in the 1990-1996 period due to increased
internal inspection activities. As a consequence of the Terrace design, the
extraordinary throughput losses associated with increased internal
inspections of approximately 1,600 m3/day are expected to be eliminated.
3. The in service commitments made by Enbridge/LPL are subject to CAPP
providing written notice to Enbridge/LPL requesting construction in advance
of the proposed in-service dates. The notice periods in respect of Phase II,
III, and Future Terrace Phases described above are 18 months, 24 months and
36 months respectively; provided that notice given prior to March 31, 1999
in respect of Phase II may be deemed by Enbridge/LPL to have been given on
March 31, 1999. Upon Enbridge giving notice to CAPP of a requirement by
Enbridge/LPL to undertake material commitments in order to meet in-service
dates, CAPP will confirm its continuing service request prior to Enbridge/
LPL being required to make those commitments.
4. For the purpose of determining "in service" the date which shall be used for
Enbridge is the date upon which the last leave to open order is granted by
the National Energy Board for the completion of pipeline facilities in Phase
I (excluding pump stations) and for LPL, the availability of the facilities
for service.
5. The delivery by Enbridge/LPL of the capacities associated with Phase I is
subject to shipper approval for commingling crude in the 24 inch line to be
transported in laminar flow.
6. Cost recovery on the Terrace facilities and related operating costs will be
effected by application of a fixed toll increment applicable to all base
(259,100 m3/d) and Terrace volume transported on the Enbridge/LPL systems.
2
<PAGE> 57
STATEMENT OF PRINCIPLES
OCTOBER 21, 1998
7 The toll increment shall be five cents (Cdn) per barrel for light crude
transportation from the Edmonton, Alberta receipt point to the Griffith,
Indiana delivery point and shall be adjusted on a distance basis and for
commodity credits or surcharges, consistent with Enbridge and LPL's then
existing toll design.
8 The fixed toll increment charge will become effective upon the in-service
of the first of the Terrace facilities, as "in service" is defined in
paragraph 4, and shall terminate December 31, 2013.
9 The fixed toll increment shall be allocated between Enbridge and LPL as
determined by Enbridge and LPL, provided that no less than one cent shall
ever be allocated to either of the Enbridge or LPL systems. The exchange
rate which shall apply to the LPL component of the fixed toll increment for
all purposes in these Principles unless otherwise stated shall be the
average exchange rate for the period commencing October 1, 1998 and ending
December 31, 1998 as published in the Bank of Canada Review, Statistical
Supplement.
10 The fixed toll increment shall be subject to a transportation revenue
variance (TRV) in Enbridge which operates in the same fashion as the
then-existing TRV in Enbridge. In the event there is no TRV mechanism in
place for IPL, the fixed toll increment shall be subject to a TRV which
operates in the same fashion as the TRV operated in Enbridge in 1997.
11 The base toll upon which the fixed increment will be added assumes the
filling of the Enbridge/LPL systems at the quoted SEP II capacity of
259,100 m3/day, in accordance with the receipt and delivery schedule
attached as Schedule E.
12 Enbridge and LPL will assume one hundred percent of operating cost variance
risk, excluding changes to property tax expense which exceeds or falls
below the forecast by twenty percent or more. The forecast operating costs
are appended as Schedule I, and the audit rights in respect of those costs
are set out in Paragraph 25. The forecast property taxes are attached as
Schedule F. Property tax variances exceeding twenty percent from forecast
shall result in an increase or decrease to the fixed toll increment by way
of a surcharge or surcredit in accordance with Schedule B.
13 Enbridge and LPL will assume five percent of the capital cost variance risk
and fifty percent of the capital cost variance risk thereafter on quoted
target costs, as inflated, set out below. Capital cost variance for Terrace
will be calculated on a cumulative basis and variances will be carried from
one phase to the next. Target costs for the purpose of capital cost
variance for facilities to be constructed after 1999 will be inflated from
December 31, 1997 using the Canadian and US Gross Domestic Product
deflators Published by Statistics Canada (Publication Number D15162) and
the Bureau of Economic Analysis (U.S. Department of Commerce Publication
Number P1D GDP) for facilities in Enbridge and LPL respectively.
3
<PAGE> 58
STATEMENT OF PRINCIPLES
OCTOBER 21, 1998
<TABLE>
<CAPTION>
ENBRIDGE LPL
Cdn $ US$
<C> <C> <C>
$575mm $117mm Jan 1999
Phase I
$35mm $17mm Sept. 1999
Phase I
$227mm $178mm Phases II & III
2000 and 2001
$70mm Other Phases
2002-2007
</TABLE>
14 In the event CAPP does not provide notice to Enbridge on or before July 1,
2001 requesting Enbridge/LPL to proceed with both Phases II and III, costs
for the Terrace project, including revenue variance between the
application of the fixed toll increment and the cost of service model,
will be calculated, and prospective tolls will be collected on a cost of
service basis. In respect of LPL, the Terrace related costs will be
collected via a cost of service surcharge layered onto the indexed base.
Capital and operating cost sharing risk will revert to cost of service
recovery.
15 In the event of a reversion to a cost of service model in accordance with
the preceding paragraphs, and in the event the parties are unable to agree
upon the appropriate cost of service parameters which shall be applied,
the parties agree that the matters of capital structure, return on equity
and tax allowance in respect of the LPL portion of the Terrace investment
will be resolved through an arbitration process, the details of which are
set forth in Schedule G. The cost of service parameters which will apply
in respect of the Enbridge portion of the Terrace investment will be
determined under then-existing Incentive Toll arrangement if agreed to by
the parties or the then prevailing NEB methodology.
16 Until such time as both Phases II and III are placed into service, Phase I
will be considered to be a Non Routine Adjustment (NRA) in both Enbridge
and LPL as NRA is defined and treated in the 1995 Enbridge Incentive Toll
Settlement. However, tolls will continued to be charged at the five cent
negotiated rate subject to the TRV in Enbridge. Any revenue variance will
be amortized and collected over the remaining term of the Principles
(effective January 1, 2002) plus carrying costs based on the year average
Bank of Canada rate plus 50 basis points if Phases II and III are not
committed to by July 1, 2001.
4
<PAGE> 59
STATEMENT OF PRINCIPLES
OCTOBER 21, 1998
17 a) Subject to the following paragraphs, Enbridge/LPL have committed to
deliver the agreed capacity set out in Schedule A. If quoted forecast
capacities are not achieved as scheduled, Enbridge/LPL will be subject
to a capacity shortfall penalty whereby for each 5,500 m3 per day
capacity shortfall Enbridge/LPL will refund to shippers an amount
equal to one cent per barrel (Cdn) via a toll reduction to be made in
the following year. The penalty will be calculated over the period set
out in subparagraph 17 e) and will be applied in fractions pro rata
for capacity shortfalls which are proportions of 5,500 m3 per day.
b) In order to determine if the capacity shortfall penalty will be in
effect, CAPP has the right to request in writing that all or a portion
of the Terrace facilities be placed on test. Enbridge will provide
written notification to CAPP within 60 days upon completion of each
Phase. CAPP will have the right at any time within the following 9
months to request that Enbridge undertake a test. Enbridge will be
required to conduct the test within 2 months of receipt of notice from
CAPP that it wishes to have a test undertaken or other date as
mutually agreed upon.
c) Subject to the force majeure exception in subparagraph 17 d), the
test will consist of flowing tests of any of Lines 2, 3 and 4, tested
individually over a 72 hour period. Over the 72 hour period the
line(s) subject to test must achieve 105.5% of the annual capacity in
aggregate, adjusted for seasonal temperatures. If the quoted forecast
capacities cannot be achieved for the test period and it has been
determined that the capacities are not achievable the penalty shall be
levied on Enbridge/LPL.
d) If during a test period, an event of force majeure occurs and is
disruptive to the test, for the duration of the event, the test
results will not be relied upon to determine the success of the test.
An event of force majeure shall be an event not within the control of
Enbridge/LPL and which by the exercise of due diligence it is not able
to avoid or overcome, limited to: acts of God, fires, flooding,
earthquakes, or other extreme weather conditions.
e) In the event Enbridge/LPL does not complete the test successfully, the
penalty shall be calculated commencing the first month after the
scheduled completion of the relevant Phase of the Terrace program in
which Enbridge/LPL announces apportionment and shall remain in effect
until such time as the quoted capacity is made available, as evidenced
by a successful re test. In the event the test is successful, but
Enbridge/LPL have announced apportionment in the period between giving
notice that the relevant Phase is completed and undertaking the test,
the penalty shall be applied for those interim months in which
apportionment was announced.
5
<PAGE> 60
STATEMENT OF PRINCIPLES
OCTOBER 21, 1998
f) Enbridge and CAPP will work together to plan for the test such that an
adequate supply is available, pump schedules determined and third
party delivery facilities are arranged to allow the 72 hour test to
occur. To the extent commodities are not made available to
Enbridge/LPL in sufficient quantities to permit it to achieve the
quoted capacities during the duration of the test, Enbridge/LPL shall
not be liable to pay the capacity penalty. The parties may agree to
reduce the duration of the test should sufficient commodity supply be
unavailable for the full 72 hour test period.
g) Upon 60 days notice to CAPP Enbridge/LPL have the right to re-test any
or all of the lines which were the subject of an unsuccessful test at
any time after such test; provided that, if commodities are not made
available to Enbridge/LPL in sufficient quantities to permit it to
undertake the test, the penalty shall be suspended, pending the
outcome of the re-test.
18 In the event the quoted capacities are not achieved in respect of Phase I
as a result of the failure to obtain timely regulatory approvals from
necessary agencies including the US Corps of Engineers, the capacity
penalty shall not be levied for so long as the capacity shortfall exists
due to that cause. Enbridge and LPL commit to use best efforts to obtain
all necessary approvals in a timely fashion.
19 The fixed toll increment of five cents shall be adjusted upward or downward
as the case may be, and the increment or decrement may be allocated as
between Enbridge and LPL in the discretion of Enbridge and LPL in
accordance with Schedule B for the following:
i) Agreed upon scope changes to the project;
ii) Agreed upon timing changes to the project where such timing change
has a cost impact;
iii) Capital cost variance;
iv) Construction cost variance due to agreed upon circumstances which are
extraordinary and not within the control of Enbridge/LPL as more
particularly described in Article 20;
v) Property tax variances in excess of twenty percent from forecast;
vi) In respect of Phases other than Phase I, bond rate variation by more
than two percentage points from 1998 levels; and
vii) Multi-pipeline return on equity variation by more than two percentage
points from 1998 level.
6
<PAGE> 61
STATEMENT OF PRINCIPLES
OCTOBER 21, 1998
20 For the purposes of Article 19 iv) circumstances which are extraordinary
and not within the control of Enbridge/LPL are causes which by the exercise
of due diligence Enbridge/LPL have not been able to avoid or overcome,
including: acts of God, acts of public enemies, wars, insurrections, riots,
epidemics, landslides, earthquakes, fires, storms, floods, washouts,
abnormal weather conditions affecting construction, orders, restraints or
prohibitions by any competent court or Government, government department,
agency or tribunal having jurisdiction over Enbridge or LPL or over parties
supplying labour, material or items necessary for the Terrace expansion.
21 Subsequent to LPL completing Phase III, in the event annual actual average
pumpings ex-Clearbrook are less than 215,000m3 per day, 220,000m3 per day
and 225,000m3 per day from in-service to year-end 2002, 2003, and 2004
through 2013 inclusive, respectively, an adjustment to the fixed toll
increment allocated to LPL shall be made in accordance with Schedule C.
22 Energy costs attributable to Terrace will be calculated using a base power
costs for an agreed upon delivery forecast assuming pre-Terrace at a
capacity of 259,100 m3/day. The calculation of the power allowance for the
purpose of calculating the TRV will be based on the difference in the
total forecast fuel and power requirements and the actual fuel and power,
using the average annual cost of fuel and power for the TRV year.
Illustrative samples of the power and TRV calculations and the delivery
forecasts for the 259,100m3/d base and the year 1999 are appended in
Schedule H.
23 The implementation of the toll method contemplated in these Principles is
subject to National Energy Board and Federal Energy Regulatory Commission
approval of the settlement for Enbridge and LPL respectively.
24 The parties acknowledge that the calculation of the fixed toll increment
assumes the Terrace facilities are depreciated on a straight line basis
using a truncation date of 2024.
25 CAPP and Enbridge/LPL agree that the operating costs allocable to the
Terrace program shall be direct incremental costs of the program for the
cost classified in Schedule I. Upon completion of each Phase of the Terrace
program, Enbridge/LPL shall provide to CAPP an enumeration of the
facilities installed and the costs thereof. Maintenance and direct
operating costs associated with the enumerated facilities shall be tracked
and charged separately over the term of the Statement of Principles. Any
variances from Schedule I costs shall be for Enbridge's account. CAPP has
the right to audit Enbridge/LPL records and accounts to ensure Enbridge's
and LPL's treatment of costs are in accordance with the Terrace Statement
of Principles. Audits will be conducted by a firm of independent Chartered
Accountants. An audit shall be conducted not more than once every two years
and no later than the immediate twenty-four month period beyond the expiry
of the Terrace Toll Agreement. All fees, costs and expenses of
7
<PAGE> 62
STATEMENTS OF PRINCIPLES
OCTOBER 21, 1998
the external auditors with respect to the Terrace Toll Agreement audit
will be paid by CAPP, on behalf of industry. CAPP may elect to have the
external audit fees and expenses paid through Enbridge as a non-routine
adjustment under Clause 7 of the Incentive Toll Settlement.
In the event Enbridge seeks to recover additional revenue from shippers
for additional facilities CAPP has the right to undertake an engineering
audit of the facilities within six months of Enbridge notifying CAPP that
such facilities are available for service. Enbridge agrees to retain, and
make available for audit purposes the original Terrace hydraulic studies.
8
<PAGE> 63
STATEMENT OF PRINCIPLES
OCTOBER 21, 1998
SCHEDULE A
Description of Terrace Facilities
PHASE I FACILITIES
<TABLE>
<CAPTION>
PROPOSED FACILITIES ITEMS CONSIDERED TO BE SCOPE CHANGES TO TERRACE NOT IN TERRACE SCOPE
- -----------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C>
Pipe
- - 619 km of 914 mm line pipe between - Changes totaling more than 5 miles of pipe
Kerrobert and Gretna stations in 15 combined in Enbridge & LPL
sections in Enbridge along with associated
valving, tie-in piping and scraper facilities - Changes in pipe diameter
- - 100 miles of 36 inch line pipe in 4 sections
between Gretna and Clearbrook stations in
LPL along with associated valving and tie-
in piping
- - additional wall thickness beyond the SEP
II design on discharge of five existing
stations above 3.28 inches and valving at
intermediate station sites for future stations
</TABLE>
9
<PAGE> 64
STATEMENT OF PRINCIPLES
OCTOBER 21, 1998
<TABLE>
<S> <C> <C>
Pump Stations
- - Sufficient pumping equipment and power Additional pumping power or DRA to achieve Capacity increases on Lines not
to provide 26,500 m3/d of incremental capacities greater than 285,600 m3/d in affected by terrace including in Western
capacity assuming that the 24" total as follows: Canada:
pipeline between Kerrobert and - Line 1 18"/20"/26" 49,500 m3/day - Changes resulting from the SEP II
Clearbrook operates in laminar flow - Line 3 21"/34" 66,000 m3/day facilities as filed with the NEB and
and that crudes are pumped in the 24" - Line 3 24"/26"/34" 81,200 m3/day as agreed to with industry which
pipeline in sufficient quantities for - Line 2 24" heavy line 25,000 m3/day impact quoted Line capacities
the line to operate at 25,000 m3/d at - Line 4 36"/48" heavy line 102,100 m3/day
its bottleneck point. Facilities will - Line 13 16"/18"/20" 27,800 m3/day - Changes in facilities required to
provide 370,000 BHP pumping power to or as otherwise agreed to with industry accommodate crude characteristics
pump at annual capacity rate between other than as referenced in Schedule
Edmonton and Superior in Q4 1999. No Annual capacities noted are 90% of design D.
more than 2 pipelines in Enbridge and capacity for all pipelines capacities noted.
LPL will handle heavy and Bow River
commodities. Changes in deliveries that negatively impact
Lakehead's ability to inject crude into Lines
2 and 4 at Clearbrook in Phase I
</TABLE>
10
<PAGE> 65
STATEMENT OF PRINCIPLES
OCTOBER 21, 1998
Breakout and Terminalling Facilities
<TABLE>
<S> <C> <C>
- - 2 breakout tanks at Superior - Additional breakout tankage - Additional tankage, receipt,
delivery, terminalling or connecting
facilities at any location
in Canada or USA
- Requested commodity segregation
over and above that provided in
January 1999 which result in the
need for additional tankage,
metering, or terminalling
facilities
- Changes in facilities required
to accommodate crude characteristics
other than referenced in
Schedule D.
</TABLE>
11
<PAGE> 66
STATEMENT OF PRINCIPLES
OCTOBER 21, 1998
PHASE II FACILITIES
<TABLE>
<CAPTION>
ITEMS CONSIDERED TO BE SCOPE
PROPOSED FACILITIES CHANGES TO TERRACE NOTE IN TERRACE SCOPE
- ----------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C>
Pipe
123 km of 914 mm line pipe in 3 sections Changes totaling more than 5 miles of pipe
between Hardisty and Kerrobert pump stations
in Enbridge with associated valving and Changes in pipe diameter
tie-in facilities
- ----------------------------------------------------------------------------------------------------------------------------------
Pump Stations
Additional pumping power or DRA to achieve - Additional pumping power or DRA
Sufficient pumping equipment and power to capacities greater than 292,500 m3/d in to achieve capacities greater than
provide 6,900 m3/d of incremental capacity total determined as follows: that quoted in Phase I facilities:
beyond Phase I facilities, assuming that the - Line 1 18"/20"/26" 49,500 m3/day - Changes in facilities required to
24" pipeline between Hardisty and Clearbook - Line 3 24"/34" 66,000 m3/day accommodate crude characteristics
operates in laminar flow and that crudes are - Line 3 24"/26"/34" 81,200 m3/day other than references in
pumped in the 24" pipeline in sufficient - Line 2 24" heavy line 27,000 m3/day Schedule D
quantities to operate at 27,000 m3/d at its - Line 4 36"/48" heavy line 107,000 m3/day
bottleneck point. - Line 13 16"/18"/20" 27,800 m3/day
Facilities will provide 384,000 BHP in or capacities as otherwise agreed to by
pumping power to pump at annual capacity Enbridge/LPL and industry
rate between Edmonton and Superior in Q4
2000. No more than 2 pipelines in Enbridge Annual capacities noted are 90% of design
and LPL will handle heavy and Bow River capacity for all pipeline capacities
commodities. noted.
- -----------------------------------------------------------------------------------------------------------------------------------
</TABLE>
12
<PAGE> 67
STATEMENT OF PRINCIPLES
OCTOBER 21, 1998
<TABLE>
<S> <C> <C>
Breakout and Terminating Facilities - Breakout tankage - additional tankage, receipt,
delivery, terminalling or connecting
facilities at any location in Canada
or USA
- Requested commodity segregation
which results in additional tankage,
metering, or terminating facilities
over and above and not provided in
January 1999.
</TABLE>
13
<PAGE> 68
STATEMENT OF PRINCIPLES
OCTOBER 21, 1998
PHASE III FACILITIES
<TABLE>
<CAPTION>
PROPOSED FACILITIES ITEMS CONSIDERED TO BE SCOPE NOT IN TERRACE SCOPE
CHANGES TO TERRACE
<S> <C> <C>
- ----------------------------------------------------------------------------------------------------------------------------------
Pipe
Changes totaling more than 5 miles of pipe
120 miles of 36 inch line pipe in 5 sections
between Clearbrook and Superior pump Changes in pipe diameter
stations with associated valving and tie-in
facilities
- ----------------------------------------------------------------------------------------------------------------------------------
Pump Stations
Sufficient power to provide 23,500 m3/d of Additional pumping power or DRA to
incremental capacity above Terrace Phase II achieve capacities greater than
facilities. Facilities will provide 409,000 BHP 315,200 m3/d in total as determined
in pumping power to pump at annual capacity as follows:
rate between Edmonton and Superior in Q4 - Line 1 18"/20"/25" 41,400 m3/day
2001. - Line 3 24"/34" 54,000 m3/day
No more than 2 pipelines in Enbridge and LPL - Line 3 24"/26"/34" 65,000 m3/day
will handle heavy and Bow River commodities. - Line 2 heavy line 74,000 m3/day
- Line 4 heavy line 107,800 m3/day
- Line 13 16"/18"/20" 27,800 m3/day
or as otherwise agreed to with
industry
Annual capacities noted are 90% of
design capacity for all pipelines
noted.
- Changes in facilities required to
accommodate crude characteristics
other than referenced in Schedule
D.
</TABLE>
14
<PAGE> 69
STATEMENT OF PRINCIPLES
OCTOBER 21, 1998
<TABLE>
<S> <C> <C>
Breakout and Terminalling Facilities
- - 2 breakout tanks at Superior - additional breakout tankage - additional tankage, receipt,
delivery, terminalling or connecting
facilities at any location in Canada
or USA
- Requested commodity segregation
which results in additional tankage,
metering, or terminalling facilities.
</TABLE>
15
<PAGE> 70
STATEMENT OF PRINCIPLES
OCTOBER 21, 1998
FUTURE PHASES OF TERRACE FACILITIES
<TABLE>
- -----------------------------------------------------------------------------------------------------------------------------------
PROPOSED FACILITIES ITEMS CONSIDERED TO BE SCOPE CHANGES TO TERRACE NOT IN TERRACE SCOPE
<S> <C> <C>
- -----------------------------------------------------------------------------------------------------------------------------------
Pipe
$US 27 million in pipeline facilities - Any additional pipeline extensions or connections
between Mokena and Griffith by the end over $US 27 million
of 2002 if needed
- -----------------------------------------------------------------------------------------------------------------------------------
Pump Stations
$US 40 million in station additions - Any incremental pump unit additions after the
and modifications on Line 14 by the intermediate stations are installed over $US 40
end of 2003 if needed million
- -----------------------------------------------------------------------------------------------------------------------------------
Crude Oil Heater
$US 3 MM in heating facilities to - Any other heating facilities over $US 3 million
increase Line 14 capacity by the end
of 2007 if needed
- -----------------------------------------------------------------------------------------------------------------------------------
Total Costs Total costs in excess of $US 70 million
- -----------------------------------------------------------------------------------------------------------------------------------
</TABLE>
A pipeline system schematic is shown on the following page.
16
<PAGE> 71
Statement of Principles
October 21, 1998
PIPELINE SYSTEM CONFIGURATION
(TERRACE PHASE 1 REVISED)
(as of February 1999)
[diagram showing pipeline configuration between U.S. and Canadian cities]
<TABLE>
<CAPTION>
Line 21
-----------
<S> <C>
/Light Crudes
</TABLE>
<TABLE>
<CAPTION>
Line 1 Line 2 Line 3 Line 4 Line 5 Line 6 Line 7
----------- ----------- ----------- ----------- ----------- ----------- -----------
<S> <C> <C> <C> <C> <C> <C> <C>
/NGL /Heavy Crudes /Light Crudes /Heavy Crudes /NGL /Light Crudes /Light Crudes
/Light Crudes /Medium Crudes /Medium Crudes /Light Crudes /Medium Crudes /Medium Crudes
/Synthetics /Synthetics /Synthetics /Heavy Crudes /Heavy Crudes
/Condensates /Condensate /Synthetics /Synthetics
</TABLE>
<TABLE>
<CAPTION>
Line 8 Line 9 Line 10 Line 11 Line 12 Line 13 Line 14
----------- ----------- ----------- ----------- ----------- ----------- -----------
<S> <C> <C> <C> <C> <C> <C> <C>
/Refined products /Light Crudes /Light Crudes /Light Crudes /Light Crudes /Synthetics /Light Crudes
/Medium Crudes /Medium Crudes /Condensate /Medium Crudes /Refined products /Condensates
/Condensate /Heavy Crudes /Synthetics /Heavy Crudes /Synthetics
/Condensate /Synthetics /Medium Crudes
/Synthetics /Heavy Crudes
</TABLE>
[Enbridge Logo]
15
<PAGE> 72
STATEMENT OF PRINCIPLES
OCTOBER 21, 1998
SCHEDULE B
ADJUSTMENTS TO THE 5 CENTS PER BARREL INCREMENT*
(CDN DOLLARS)
<TABLE>
Adjusting Event Adjustment
--------------- ------------------------------------------------------------------------
Phase I Phase II
------- --------
<S> <C> <C>
1 Aggregate Scope Changes resulting in 0.18 cents per barrel per $10 million 0.14 cents per barrel per $10
Capital cost changes greater than change in capital costs million change in capital
+/-$10 million from original estimate costs
provided in Paragraph 13 of the
Principles of Settlement
- ----------------------------------------------------------------------------------------------------------------------------------
2 Capital Cost Variance outside +/-5% of 0.09 cents per barrel per $10 million 0.07 cents per barrel per $10
estimate provided in Schedule A and change in capital costs million change in capital
construction cost variance agreed upon costs
as falling under Paragraph 19 iv) of
the Statement of Principles
- ----------------------------------------------------------------------------------------------------------------------------------
3 Changes in Multi-pipeline cost of For 1999-2007 and for 2008-2013 .3 cents per barrel and .15 cents per
equity beyond current rate plus 200 barrel respectively for each 25 basis point change in the multi-pipeline
basis points rate of return which exceeds the 1998 multi-pipeline rate of return
plus or minus 200 basis points.
- ----------------------------------------------------------------------------------------------------------------------------------
4 Variances in Cost of Debt over 200 basis For Phases II and following, .1 cent per barrel change for every 50 basis
points above or below current Long Canada point change in debt cost above the 200 basis point variance. The toll
(5.28%) and US (5.65%) 10 year bonds change for debt cost variances shall apply to Enbridge and LPL
independently.
- ----------------------------------------------------------------------------------------------------------------------------------
5 Property Tax variances on Terrace Treated as a surcharge or surcredit to be recovered over a period of
Facilities greater than +/-20% estimate approximately one year and applied to all volumes until such time as the
applicable property tax variance plus carrying costs at the year average
Bank of Canada rate plus 50 basis points has been fully recovered or
refunded.
- ----------------------------------------------------------------------------------------------------------------------------------
6 Capacity Penalty 1 cent decrease per barrel per 5,500 1 cent decrease per barrel per
m3 per day below stated capacity until 5,500 m3 per day below stated
capacity is provided capacity until capacity is
provided
- ----------------------------------------------------------------------------------------------------------------------------------
</TABLE>
* All values in Schedule B will be applied in fractions pro rata and the
exchange rate (where applicable) shall be that set out in Paragraph 9 of
the Statement of Principles
16
<PAGE> 73
STATEMENT OF PRINCIPLES
OCTOBER 21, 1998
17
<PAGE> 74
STATEMENT OF PRINCIPLES
OCTOBER 21, 1998
SCHEDULE C
ADJUSTMENT FOR LPL PHASE III TRIGGER*
INCREMENT INCREASE IN YEAR FOLLOWING PUMPINGS BELOW SPECIFIED TARGET
(Cdn Currency)
<TABLE>
<CAPTION>
PRIOR YEAR'S ACTUAL AVERAGE PUMPINGS EX-CLEARBROOK TOLL ADJUSTMENT FOR YEAR
- -------------------------------------------------- -----------------------------------------------------
2002 2003 2004-2013
-----------------------------------------------------
<S> <C> <C> <C>
Greater than 225,000 m3/day 0 cents/barrel 0 cents/barrel 0 cents/barrel
220,000 m3/day to 224,999 m3/day 0 cents/barrel 0 cents/barrel 1 cents/barrel
215,000 m3/day to 219,999 m3/day 0 cents/barrel 1 cents/barrel 2 cents/barrel
210,000 m3/day to 214,999 m3/day 1 cents/barrel 2 cents/barrel 3 cents/barrel
205,000 m3/day to 209,000 m3/day 2 cents/barrel 3 cents/barrel 4 cents/barrel
200,000 m3/day to 204,999 m3/day 3 cents/barrel 4 cents/barrel 5 cents/barrel
</TABLE>
- - The toll adjustment set out in
Schedule C will be collected via a
surcharge, based on an exchange rate
fixed on the previous 12 month average
and all adjustments will be applied in
fractions pro rata.
- - For any year in which the Phase III
facilities are in operation for a less
than a full year, the actual average
pumpings will be calculated on that
portion of the year the facilities
were available for service.
18
<PAGE> 75
STATEMENT OF PRINCIPLES
OCTOBER 21, 1998
SCHEDULE D
FLUID PROPERTIES OF LIQUID HYDROCARBONS IN ENBRIDGE SYSTEM
TERRACE PHASE I EXPANSION PROGRAM
<TABLE>
<CAPTION>
COMMODITY VISCOSITY @ DENSITY @ NOTES
TYPE 15 deg C 15 deg C
(CENTISTOKES)
<S> <C> <C>
Synthetic Crude 5.8 864
NGL 0.26 555
Condensate 1.1 732
Gasoline 0.65 722
Distillate 3.1 839
Mixed Blend Sweet 6.8 883
Light Sour 21 877
Medium 56 902
Heavy 350 1 9401
Bow River 225 1 9251 Increased viscosity commences
January 1999
</TABLE>
- -----------
1 Viscosity and density at Line 3 and 4 reference temperature.
19
<PAGE> 76
STATEMENT OF PRINCIPLES
OCTOBER 21, 1998
SCHEDULE E
RECEIPT/DELIVERY FORECAST
Forecast Deliveries at Base Capacity
259,100m3/day
ENBRIDGE PIPELINES INC.
FORECAST DELIVERIES AT BASE CAPACITY (259 199 m3/d)
m3/d
<TABLE>
<CAPTION>
Line Delivery Commodity Commodity Service Year
No. Location Source Type Category(1) Average
- ---- -------- --------- --------- ----------- -------
(a) (b) (c) (d) (e) (f)
<S> <C> <C> <C> <C> <C>
1 Edmonton Edmonton Cnd 1 3,000
2 Hardisty Edmonton Cnd 1 9,800
3 Edmonton Lgt 1 4,400
4 Edmonton Hvy 1 5,900
------
5 Subtotal 20,100
6 Kerrobert Edmonton Cnd 1 5,000
7 Milden Edmonton Dst 2 1,100
8 Edmonton Gsl 2 1,500
------
9 Subtotal 2,600
10 Regina Edmonton Dst 2 1,700
11 Edmonton Gsl 2 1,300
12 Edmonton Cnd 1 300
13 Edmonton Lgt 1 2,400
14 Edmonton Nap 1 500
15 Edmonton Hvy 4 700
16 Kerrobert Hvy 1 5,100
------
17 Subtotal 12,000
18 Gretna Edmonton Dst 2 2,400
19 Edmonton Dst 3 1,700
20 Edmonton Gsl 2 2,900
21 Edmonton Gsl 3 1,500
22 Regina Dst 2 400
23 Regina Gsl 2 500
------
24 Subtotal 9,400
</TABLE>
20
<PAGE> 77
STATEMENT OF PRINCIPLES
OCTOBER 21, 1998
<TABLE>
<S> <C> <C> <C> <C>
25 U.S. Points Edmonton Cnd 1 100
26 Edmonton Lgt 1 55,400
27 Edmonton Med 1 1,700
28 Edmonton Hvy 1 9,300
29 Edmonton NGL 2 600
30 Hardisty Lgt 1 8,100
31 Hardisty Med 2 13,600
32 Hardisty Hvy 1 15,800
33 Hardisty Hvy 2 28,100
34 Kerrobert Lgt 2 1,300
35 Kerrobert Hvy 1 11,800
36 Kerrobert Hvy 2 4,400
37 Kerrobert NGL 2 4,900
38 Regina Lgt 1 0
39 Regina Hvy 1 6,700
40 Cromer Lgt 1 9,500
41 Cromer Med 1 2,100
42 Cromer NGL 1 500
-------
43 Subtotal 173,900
44 Sarnia Edmonton Lgt 1 16,200
45 Edmonton Hvy 1 3,300
46 Edmonton Cnd 1 0
47 Edmonton NGL 2 11,600
48 Hardisty Lgt 1 800
49 Hardisty Hvy 2 2,900
50 Kerrobert NGL 2 7,900
51 Regina Lgt 1 600
52 Cromer Lgt 1 4,500
53 Cromer Med 1 4,100
54 U.S. Points USL 2 700
55 Montreal Cnd 2 1,600
56 Montreal Lgt 2 13,600
-------
57 Subtotal 67,800
58 Toronto Edmonton Lgt 1 0
59 Hardisty Med 2 2,500
60 Hardisty Hvy 2 800
61 Kerrobert Hvy 1 500
62 Toronto Med 2 500
63 Montreal Lgt 2 10,300
-------
64 Subtotal 14,600
65 Nanticoke Edmonton Lgt 1 500
66 Hardisty Med 1 0
67 Hardisty Lgt 1 1,800
68 Hardisty Hvy 2 1,300
69 Regina Lgt 1 0
70 Montreal Lgt 2 12,700
-------
71 Subtotal 16,300
72 Buffalo Edmonton Lgt 1 4,700
</TABLE>
21
<PAGE> 78
STATEMENT OF PRINCIPLES
OCTOBER 21, 1998
<TABLE>
<S> <C> <C> <C> <C>
73 Edmonton Hvy 1 300
74 Hardisty Lgt 1 0
75 Hardisty Med 2 1,400
76 Hardisty Hvy 2 2,200
77 Kerrobert Hvy 1 1,300
78 Cromer Lgt 1 400
79 Cromer Med 1 800
80 U.S. Points Med 1 0
81 U.S. Points USL 2 0
82 Sarnia Cnd 1 300
-------
83 Subtotal 11,400
84 TOTAL DELIVERIES -- 336,100
Enbridge --------
85 Subtotal Cdn 20,100
86 Lgt 147,200
87 Med 26,700
88 Hvy 100,400
89 NGL 25,500
90 Other 16,200
91 TOTAL DELIVERIES -- 336,100
Enbridge --------
92 less Deliveries Upstream of Capacity 36,400
Points*
93 less Receipts Downstream of Capacity 40,600
Points*
94 TOTAL PUMPING AT CAPACITY POINTS* 259,100
* Capacity Points are Cromer for Line 1 and Line 2, Regina
for Line 3 and Hardisty for Line 13. Capacities are
49,500 m3/d on Line 1, 79,500 m3/d on Line 2,
99,100 m3/d on Line 3 and 31,000 m3/d on Line 13.
</TABLE>
LEGEND
Dst - Distillate Med - Medium Crude Oil
Gsl - Gasoline Hvy - Heavy Crude Oil
Nap - Naptha NLG - Natural Gas Liquids
Cdn - Condensate USL - U.S. & Offshore Light Crude Oil
Lgt - Light Crude Oil m3/d - Cubic meters per day
NOTE (1) SERVICE CATEGORY:
(a) Use of receipt and delivery tankage is identified as follows:
1 - Uses receipt tankage but not delivery tankage.
2 - Uses neither receipt nor delivery tankage.
3 - Uses delivery tankage but not receipt tankage.
4 - Uses both receipt and delivery tankage.
22
<PAGE> 79
STATEMENT OF PRINCIPLES
OCTOBER 21, 1998
(b) No receipt terminalling charge will be assessed on commodities received
by Enbridge at the International Boundary near Sarnia, Ontario and no
delivery terminalling charge will be assessed on the commodities delivered
by Enbridge at the International Boundaries near Gretna, Manitoba and
Chippewa, Ontario.
23
<PAGE> 80
STATEMENT OF PRINCIPLES
OCTOBER 21, 1998
SCHEDULE F
FORECAST
PROPERTY TAXES
(000)
<TABLE>
1999 2000 2001 2002 2003 2004 2005 2006 2007
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
LPL $US 1908 2307 1996 5984 6508 7112 7332 7323 6901
Enbridge 2758 3069 3372 3932 4010 4090 4172 4256 4341
$C
2008 2009 2010 2011 2012 2013 2014
<S> <C> <C> <C> <C> <C> <C> <C>
LPL $US 6705 6925 7029 7134 7241 7350 7460
Enbridge 4428 4516 4607 4699 4793 4888 4986
$C
</TABLE>
24
<PAGE> 81
STATEMENT OF PRINCIPLES
OCTOBER 21, 1998
SCHEDULE G
Arbitration Procedure
1. REFERRAL TO ARBITRATION; RULES. In the event of any dispute, controversy or
claim (a "Dispute") arising out of setting the parameters for or relating
to the reversion to cost of service toll approach set forth in the
Principles of Settlement such Dispute shall be referred to arbitration in
accordance with the provisions of this Schedule. The arbitration shall be
conducted under the Arbitration Act (Alberta) and any amendments thereto
except to the extent that the Arbitration Act is inconsistent with or in
conflict with any terms of this Schedule, in which event such terms of this
Schedule shall prevail. Any other statute which applies to a Dispute shall
apply only to the extent that it is not inconsistent with this Schedule.
2. THE ARBITRATORS. The Party or Parties commencing the Arbitration
proceedings ("Claimant") may at any time serve a notice on the other Party
or Parties ("Respondent") to the Dispute of its intention to arbitrate.
Within ten (10) days (all references to "days" in this Schedule G are to
business days) or Respondent's receipt of a Notice of Arbitration (as
defined in subparagraph 3(a)), the Claimant and Respondent shall meet and
attempt to appoint a single arbitrator. Should all of the Parties to the
Dispute ("Arbitrating Parties") be unable to agree upon a single
arbitrator, then either Arbitrating Party may select its own arbitrator and
may serve notice upon the other Arbitrating Party to select an arbitrator.
Upon receipt of such notice, the other Arbitrating Party shall have ten
(10) days in which to appoint an arbitrator. The two arbitrators thus
selected shall appoint a third arbitrator within ten (10) days of the
appointment of the second arbitrator; and the three arbitrators shall
constitute a board of arbitrators which shall determine the matter in
dispute. If either Arbitrating Party shall fail to name an arbitrator
within ten (10) days of receipt of a notice to do so, the second arbitrator
shall be appointed by any Justice of the Court of Queen's Bench of Alberta
(the "Specified Court"). If the two arbitrators shall fail to appoint the
third arbitrator, then upon written application by any Arbitrating Party
such third arbitrator shall be appointed by any Justice of the Specified
Court. For the purposes of selection of arbitrators, the Claimants shall be
treated as one Arbitrating Party, and the Respondents shall be treated as
one Arbitrating Party.
3. COMMENCEMENT OF ARBITRATION PROCEDURES.
(a) The Party commencing arbitration proceedings (the "Claimant") shall
serve upon the other party (the "Respondent") a notice of arbitration
(the "Notice of Arbitration"). No more than five (5) days after the
selection of the Arbitrator, the Claimant shall serve the Notice of
Arbitration upon the Arbitrator. Arbitration proceedings are deemed to
commence on the date on which the Notice of Arbitration is served upon
the Respondent.
(b) Notice of Arbitration shall include the following, set out in plain,
concise and summary language:
25
<PAGE> 82
STATEMENT OF PRINCIPLES
OCTOBER 21, 1998
(i) a demand that the Dispute be referred to arbitration;
(ii) the names and addresses of the Arbitrating Parties;
(iii) a reference to the provisions of the Agreement out of or in
relation to which the Dispute arises;
(iv) the general nature of the claim;
(v) a statement of the facts supporting the claim;
(vi) the points at issue;
(vii) the name and address of the Claimant's counsel;
(viii) the relief or remedy sought; and
(ix) a proposal as to the identity of the Arbitrator and three
alternative proposals;
Within fifteen (15) days of service of the Notice of Arbitration, the
Respondent shall also make a proposal of the type provided for in Section
3(b)(ix) above.
(c) Within thirty (30) days of receiving the Notice of Arbitration or such
longer period of time as the Arbitrating Parties may agree or the
Arbitrator may permit the Respondent shall serve as its response (the
"Response") in writing upon the Claimant. Within five (5) days of the
selection of the Arbitrator, the Respondent shall serve its Response upon
the Arbitrator.
(d) A Response shall reply in plain, concise and summary language to the
particulars in subparagraphs 3(b)(v), 3(b)(vi) and 3(b)(viii) above and
shall specify information of the type provided for in subparagraph
3(b)(vii) above.
(e) The documents filed pursuant to this paragraph 3 shall be referred to as
the "Written Evidence" and may only be supplemented with leave of the
Arbitrator.
(f) Both the Claimant and the Respondent shall each fully disclose and
completely append to its Notice of Arbitration Response a summary of all
material facts and evidence upon which it intends to rely, including the
following:
(i) a copy of the agreements and all amendments thereto out of which the
Dispute arises including the Agreement and all Schedules thereto;
(ii) a list of all relevant documents, including adverse documents,
identified by the parties thereto, the date and subject matter
thereof;
(iii) copies of any expert reports intended to be relied upon; and
(iv) a list of any and all witnesses intended to be relied upon, including
names, addresses, employment, a summary of the material testimony
26
<PAGE> 83
of each such witness and, where appropriate, the qualifications of the
witnesses.
4. FAILURE TO DELIVER A RESPONSE. If an Arbitrating Party does not deliver a
response within five days of written notice by the Arbitrator to do so
and the Arbitrator determines that there is no sufficient explanation for
such failure to deliver, the Arbitrator may make such an Award as is
considered appropriate in the circumstances, including an Award
terminating the arbitration.
5. CHALLENGES OF ARBITRATOR.
(a) An Arbitrating Party who intends to challenge the Arbitrator
shall send a written statement of the reasons for the challenge
to the other Arbitrating Parties and to the Arbitrator.
(b) Any challenge of the Arbitrator shall be based upon the actual or
potential bias of the Arbitrator, the Arbitrator's conflict of
interest or other ground that is related to the impartiality of
the Arbitrator. The challenge shall be made to the Specified
Court.
(c) Where the mandate of an Arbitrator terminates for any reason, a
substitute Arbitrator shall be appointed pursuant to the rules
and procedures set forth in paragraph 2 above.
6. PRELIMINARY CONFERENCE. No later than seven (10) days after the last item
of Written Evidence has been filed, the Arbitrating Parties and their
counsel shall meet, either in person or by telephone conference call with
the Arbitrator for a preliminary conference that determines the issues
upon which the Arbitrating Parties are truly in disagreement, the
granting of any interim orders of relief that may have been applied for
in the Written Evidence and the scheduling of the balance of the
arbitration including any oral hearing. The Arbitrating Parties shall use
their best efforts to reach agreement on as many matters as possible in
order to reduce the amount of time required to resolve the matters in
dispute. The Arbitrating Parties shall also provide the Arbitrator with
an agreed statement of facts and an agreed list of exhibits to be filed
within ten (10) days after the conclusion of the conference provided in
this paragraph 6, to the extent that the Arbitrating Parties have been
able to agree upon such matters.
7. EVIDENCE GATHERING.
(a) Where an Arbitrating Party on notice to the Arbitrator and the
Arbitrating Parties alleges that relevant evidence is or may be
in the possession of another Arbitrating Party, and can satisfy
the Arbitrator that there is a conflict, disagreement or
uncertainty on important evidentiary matters, such Arbitrating
Party may demand (a "Demand") that the Arbitrator require the
other Arbitrating Parties to do any or all of the following:
27
<PAGE> 84
STATEMENT OF PRINCIPLES
OCTOBER 21, 1998
(i) respond in writing to information requests under oath or
affirmation;
(ii) produce further documents (including documents that are
either adverse in interest to the producing party or
confidential) but not documents in respect of which such
Arbitrating Party may validly claim privilege or
confidentiality pursuant to paragraph 14 below); and
(iii) produce witnesses including experts for attendance at a
pre-hearing oral examination under oath or affirmation.
(b) Where an Arbitrating Party on notice to the Arbitrator and the
other Arbitrating Parties alleges that a third party has
relevant and important evidence, the Arbitrator may demand
production of that evidence in such form and on such terms as
the Arbitrator may prescribe which shall fairly protect the
interests of the Arbitrating Parties.
(c) All procedures commenced pursuant to subparagraphs 7(a) and (b)
shall be completed within thirty (30) days of the initial
Demand.
(d) Any evidence obtained by an Arbitrating Party adverse in
interest in response to a Demand or request under this
paragraph 7 may be submitted to and relied upon by the
Arbitrator as prima facie proof of the truth of its contents,
unless the opposing party raises a reasonable doubt about the
reliability of such evidence, in which case the Arbitrator may
determine the admissibility, relevance and materiality of such
evidence.
(e) Only if there is a conflict in the expert reports or in the
evidence on an important matter in the Dispute may the
Arbitrator retain a neutral, independent and impartial expert
(the "Expert") qualified in the subject matter provided the
Arbitrating Parties agree to such an appointment. The Expert
shall be appointed after the Arbitrator has had due regard to
the submissions of the Arbitrating Parties on the selection of,
qualifications of, and issues to be submitted to the Expert.
The Arbitrating Parties shall receive all documents submitted to
the Arbitrator by the Expert, and shall have an opportunity to
examine, and to offer written or oral rebuttal of any evidence
presented to the Arbitrator by the Expert. Costs associated with
the Expert are payable by the Arbitrating Parties, and the
Arbitrating Parties shall be entitled to stipulate that the
Expert's fees shall not exceed an amount agreed to by the
Arbitrating Parties.
(f) The Arbitrator may determine the admissibility, relevancy and
materiality of any evidence. Unless otherwise provided in this
Schedule, the Arbitrator's decision on all procedural matters is
final and binding upon the Arbitrating Parties.
28
<PAGE> 85
STATEMENT OF PRINCIPLES
OCTOBER 21, 1998
8. HEARINGS
(a) Where there is a conflict, disagreement or uncertainty on evidentiary
matters an Arbitrating Party may demand, or the Arbitrator upon its
own initiative may order, a hearing at which oral evidence on the
evidentiary matters so identified will be tendered with each other
Arbitrating Party entitled to call rebuttal evidence (if previously
disclosed to the other party) and to cross-examine. The Arbitrator
must advise the Arbitrating Parties of the date, time and place of the
arbitration hearing, and must decide such matters after consulting the
Arbitrating Parties.
(b) Any oral hearing shall be held in camera and unless otherwise agreed
by all Arbitrating Parties, only their representatives, their counsel,
the Arbitrator and those persons called as witnesses may attend. Each
witness must be excluded from the hearing until that person is called
to give evidence, unless all Arbitrating Parties agree that the
witness need not be excluded.
(c) A hearing shall proceed in the following manner:
(i) each Arbitrating Party may make an introductory statement;
(ii) each Arbitrating Party may present its evidence through a panel
or panels of witnesses or otherwise as it sees fit;
(iii) the testimony of any and all witnesses shall be under oath,
declaration of affirmation and the Arbitrator may administer
such oaths, declarations and affirmations;
(iv) the order of presentation of evidence shall be: Claimant;
Respondent and Claimant (rebuttal evidence only);
(v) surrebuttal evidence may be presented only with leave of the
Arbitrator;
(vi) the order of examination of witnesses shall be:
examination-in-chief by counsel for the Arbitrating Party
presenting such evidence; cross-examination by counsel for each
other Arbitrating Party; re-examination by the first
Arbitrating Party's own counsel; and, if the Arbitrator
chooses, examination by the Arbitrator; and
(vii) the Arbitrator may require any person to give evidence and
attend an oral hearing and such orders are enforceable in the
same manner as and have the same effect as a notice to attend
in court proceedings, and shall be served in the same manner.
(d) Following conclusion of the procedures specified in subparagraph 8(c)
above, the Claimant shall present its oral argument, followed by the
oral
29
<PAGE> 86
STATEMENT OF PRINCIPLES
OCTOBER 21, 1998
argument of the Respondent, the Claimant's replies and the Respondent's
replies to the Claimant's replies. If the Arbitrator deems it advisable
to do so, it may order the Arbitrating Parties to submit written briefs
of argument, prior to and in addition to or in lieu of their oral
arguments. In no event may such briefs exceed 10 pages.
9. THE AWARD. Not later than 10 days following the conclusion of the hearing,
the Arbitrator shall furnish to each Arbitrating Party a written statement
of the Award. The Award shall be final and binding on the Arbitrating
Parties as to the questions submitted to arbitration in the Notice of
Arbitration. There shall be no appeal from or judicial review of the Award.
10. APPLICABLE LAW. The Arbitrator shall apply the laws of the Province of
Alberta. All matters of procedure shall be resolved in accordance with the
laws of the Province of Alberta.
11. CLAIMS GIVING RISE TO OTHER PROCEEDINGS. Unless the Arbitrating Parties
agree otherwise, the application of the arbitration provisions of this
Schedule to the Dispute shall terminate if an Arbitrating Party advances or
is required to respond to any other legitimate claim not covered by this
Schedule, providing that such other claim arises out of substantially the
same facts or subject matter as the Dispute governed by this Schedule and
could reasonably give rise to contribution, indemnity, duplicative or
inconsistent remedies or relief. The Arbitrator shall be empowered to
determine whether any such claim falls within the contemplation of this
paragraph 11.
12. NON-ARBITRABLE MATTERS. Any matter expressed in the Agreement to be a
matter for agreement by the Arbitrating Parties shall not constitute a
Dispute to be referred to or settled by arbitration proceedings pursuant to
this Schedule or otherwise.
13. ATTORNMENT; ENFORCEMENT. The Arbitrating Parties hereby submit to the
exclusive jurisdiction of the Specified Court in any action, suit or
proceedings with respect to the enforcement of the provisions of this
Schedule and the non-exclusive jurisdiction of the Specified Court with
respect to the enforcement of any Award. For greater certainty, the Parties
confirm that the agreement to submit matters to arbitration is intended
solely to bind the parties hereto and is not intended in a any way to
fetter or restrict the exercise of jurisdiction of any regulatory authority
having jurisdiction over the matters which are subject to arbitration. The
Arbitrating Parties agree to take any and all action as may be necessary to
designate and maintain such designation of agents for service of notices
under this Schedule for the duration of the Agreement and to promptly
advise the other Parties in writing of any unavoidable change of agent or
address of agent along with the identity and address of its new agent as
required.
30
<PAGE> 87
STATEMENT OF PRINCIPLES
OCTOBER 21, 1998
14. CONFIDENTIALITY OF INFORMATION.
(a) Each Arbitrating Party and the Arbitrator shall retain in
confidence the reasons for decision for the Award, all
documents and other materials and all information obtained
from any of the Arbitrating Parties in the arbitration and
further, shall not use the same, or allow the same to be
used, for any purpose collateral to the arbitration. The
Arbitrating Parties shall be responsible for ensuring that
their officers, employees, witnesses, representatives and
consultants comply with the obligation of confidentiality
herein.
(b) No Arbitrating Party shall refuse to produce any relevant
documents on grounds of confidentiality alone, provided that
a party may withhold documents if the conditions set forth
in Section 16.1 of the National Energy Board Act apply, or
if the rules of privilege applied by the laws of the Province
of Alberta would result in such document being privileged in
legal proceedings conducted in the Province of Alberta.
15. COSTS. Each Arbitrating Party shall bear its own costs associated
with the Arbitration and shall bear 50 percent of all third party
costs
16 PLACE OF ARBITRATION. The arbitration shall be conducted in Calgary,
Alberta, Canada.
31
<PAGE> 88
Statement of Principles
October 21, 1998
SCHEDULE H
Power Calculation
Following is an explanatory of the allocation of power costs and benefits to the
Terrace Project and the calculation of the TRV power.
PROCEDURE FOR ALLOCATION OF POWER COST/BENEFITS TO TERRACE AND TRV
A. Calculate the energy requirements to transport the post SEP II base
capacity at 259,000 m3/d using the crude slate and receipt and delivery
schedule found in Schedule E.
B. Multiply the power requirements determined in (A) by the previous year's
average unit cost of energy plus fuel and DRA.
C. Forecast the energy requirements annually to transport the post Terrace
volumes at annual capacity using the forecast of crude type mix for each
year as found in the example for 1999 in Table H below.
D. Multiply the power requirements determined in (C) by the previous year's
average unit cost of energy plus fuel and DRA.
E. The Difference between Power at base capacity (B) less the power associated
with the current forecast at annual capacity (D) will be deemed Terrace
Power attributable to Enbridge. In the example shown below, Terrace Power
is shown as $122 million - $98 million = $24 million.
F. The difference between the Actual Power Cost and the Terrace Power at
capacity determined in (D) will represent the TRV power allowance, which
will be deducted from the TRV revenue.
Below is a graphical illustration of the treatment of power costs.
[Graph]
32
<PAGE> 89
STATEMENT OF PRINCIPLES
OCTOBER 21, 1998
POWER CALCULATION EXAMPLE
<TABLE>
<CAPTION>
LINE $ TOTAL
NO. DESCRIPTION GWh $97 AVG MILLIONS
<S> <C> <C> <C> <C>
A,B ENERGY REQUIREMENTS FOR BASE CAPACITY (259 100 m3/d):
1 Power 2800 40.55 114
2 Fuel 1
3 DRA 6
---
4 Total Energy Requirements for Base Capacity 122
C,D ENERGY REQUIREMENTS AT CAPACITY (259 100 m3/d) JANUARY 1999
5 Power 233 40.55 9
6 Fuel 0
7 DRA 1
---
8 Total Energy Requirements at Capacity Jan 1999 10
C,D ENERGY REQUIREMENTS AT CAPACITY (274 200 m3/d) FEBRUARY - SEPTEMBER 1999
9 Power 1459 40.55 59
10 Fuel 1
11 DRA 3
---
12 Total Energy Requirements at Capacity Feb - Sept 1999 63
C,D ENERGY REQUIREMENTS AT CAPACITY (285 600 m3/d) OCTOBER - DECEMBER 1999
13 Power 583 40.55 24
14 Fuel 0
15 DRA 1
---
16 Total Energy Requirements at Capacity Oct - Dec 1999 25
C,D ENERGY REQUIREMENTS FOR 1999 CAPACITY
17 Power 2275 40.55 92
18 Fuel 1
19 DRA 5
---
20 Total Energy Requirements for 1999 at Capacity 98
</TABLE>
* The energy requirements shown in the table above are for the partial year
period with its corresponding aggregate system capacity forecast for that
period.
33
<PAGE> 90
STATEMENT OF PRINCIPLES
OCTOBER 21, 1998
ENBRIDGE PIPELINES INC.
TABLE H
FORECAST DELIVERIES FOR 1999 AT CAPACITY
m3/d
<TABLE>
<CAPTION>
Line Delivery Commodity Commodity Service Year
No. Location Source Type Category(1) Average
- ---- -------- --------- --------- ----------- -------
(a) (b) (c) (d) (e) (f)
<S> <C> <C> <C> <C> <C>
1 Edmonton Edmonton Cnd 1 1,200
2 Hardisty Edmonton Cnd 1 10,400
3 Edmonton Lgt 1 8,400
4 Edmonton Hvy 1 1,000
------
5 Subtotal 19,800
6 Kerrobert Edmonton Cnd 1 4,900
7 Milden Edmonton Dst 2 1,000
8 Edmonton Gsl 2 1,400
------
9 Subtotal 2,400
10 Regina Edmonton Dst 2 1,700
11 Edmonton Gsl 2 1,400
12 Edmonton Cnd 1 300
13 Edmonton Lgt 1 800
14 Edmonton Nap 1 500
15 Edmonton Hvy 4 600
16 Kerrobert Hvy 1 5,000
------
17 Subtotal 10,300
18 Gretna Edmonton Dst 2 2,300
19 Edmonton Dst 3 1,700
20 Edmonton Gsl 2 2,900
21 Edmonton Gsl 3 1,500
22 Regina Dst 2 400
23 Regina Gsl 2 500
------
24 Subtotal 9,300
25 U.S. Points Edmonton Cnd 1 2,400
26 Edmonton Lgt 1 57,300
27 Edmonton Med 1 2,300
28 Edmonton Hvy 1 33,300
29 Edmonton NGL 2 600
30 Hardisty Lgt 1 1,800
31 Hardisty Med 2 14,500
32 Hardisty Hvy 1 7,200
33 Hardisty Hvy 2 38,700
34 Kerrobert Lgt 2 1,500
35 Kerrobert Hvy 1 5,600
36 Kerrobert Hvy 2 5,500
37 Kerrobert NGL 2 4,900
38 Regina Lgt 1 900
39 Regina Hvy 1 7,100
40 Cromer Lgt 1 11,900
</TABLE>
34
<PAGE> 91
STATEMENT OF PRINCIPLES
OCTOBER 21, 1998
<TABLE>
<S> <C> <C> <C> <C> <C>
41 Cromer Med 1 1,500
42 Cromer NGL 2 500
-------
43 Subtotal 197,500
44 Sarnia Edmonton Lgt 1 16,000
45 Edmonton Hvy 1 5,900
46 Edmonton Cnd 1 700
47 Edmonton NGL 2 11,500
48 Hardisty Lgt 1 900
49 Hardisty Hvy 2 0
50 Kerrobert NGL 2 7,600
51 Regina Lgt 1 900
52 Cromer Lgt 1 3,600
53 Cromer Med 1 3,900
54 U.S. Points USL 2 1,100
55 Montreal Cnd 2 1,300
56 Montreal Lgt 2 13,900
-------
57 Subtotal 67,300
58 Toronto Edmonton Lgt 1 300
59 Hardisty Med 2 1,600
60 Hardisty Hvy 2 300
61 Kerrobert Hvy 1 500
62 Toronto Med 2 500
63 Montreal Lgt 2 10,300
-------
64 Subtotal 13,500
65 Nanticoke Edmonton Lgt 1 0
66 Hardisty Med 1 300
67 Hardisty Lgt 1 1,500
68 Hardisty Hvy 2 1,000
69 Regina Lgt 1 400
70 Montreal Lgt 2 12,700
-------
71 Subtotal 15,900
72 Buffalo Edmonton Lgt 1 2,700
73 Edmonton Hvy 1 300
74 Hardisty Lgt 1 1,400
75 Hardisty Med 2 2,000
76 Hardisty Hvy 2 2,000
77 Kerrobert Hvy 1 1,300
78 Cromer Lgt 1 400
79 Cromer Med 1 0
80 U.S. Points Med 1 800
81 U.S. Points USL 2 200
82 Sarnia Cnd 1 300
-------
83 Subtotal 11,400
84 TOTAL DELIVERIES -- ENBRIDGE 353,500
-------
85 Subtotal Cnd 21,500
86 Lgt 147,600
87 Med 27,400
88 Hvy 115,300
89 NGL 25,100
90 Other 16,600
</TABLE>
35
<PAGE> 92
STATEMENT OF PRINCIPLES
OCTOBER 21, 1998
<TABLE>
<S> <C>
91 TOTAL DELIVERIES -- ENBRIDGE 353,500
</TABLE>
LEGEND
Dst - Distillate Med - Medium Crude Oil
Gsl - Gasoline Hvy - Heavy Crude Oil
Nap - Naptha NLG - Natural Gas Liquids
Cdn - Condensate USL - U.S. & Offshore Light Crude Oil
Lgt - Light Crude Oil m3/d - Cubic meters per day
NOTE (1) SERVICE CATEGORY:
(a) Use of receipt and delivery tankage is identified as follows:
1 - Uses receipt tankage but not delivery tankage.
2 - Uses neither receipt nor delivery tankage.
3 - Uses delivery tankage but not receipt tankage.
4 - Uses both receipt and delivery tankage.
(b) No receipt terminalling charge will be assessed on commodities received by
Enbridge at the International Boundary near Sarnia, Ontario and no delivery
terminalling charge will be assessed on the commodities delivered by
Enbridge at the International Boundaries near Gretna, Manitoba and
Chippewa, Ontario.
Enbridge and CAPP agree that twelve months after the completion of Terrace,
Phase I Enbridge will conduct a recalibration of the model used to calculate
power consumption based on the actual twelve month operating experience.
In the event of recalibration demonstrates a forecast to actual variance
which exceeds two percent, Enbridge/LPL will reset both the base power
consumption and the forecast Terrace power consumption pro rata to reflect the
results of the recalibration, and shall refund or collect the revenue variance
associated with the recalibration via a surcharge or surcredit to be collected
or refunded in the subsequent year.
36
<PAGE> 93
STATEMENT OF PRINCIPLES
OCTOBER 21, 1998
SCHEDULE I
Operating Costs
<TABLE>
ENBRIDGE C$
-----------------------------------------
PHASE I PHASE II PHASE III 2009
------- -------- --------- -----
<S> <C> <C> <C> <C>
Personnel 0 930 930 930
Pump Maintenance 0 230 330 330
Mainline Maintenance 0 90 110 110
Mainline Inhibitor 1 320 330 330 330
In-Line Inspection 2 450
Tank Maintenance
Insurance 70 100 100 100
----- ----- ----- -----
Total 1 390 1 680 1 800 4 250
Inflation @ 2% 56 103 148 1 140
----- ----- ----- -----
Revised Estimate 1 446 1 783 1 948 5 390
===== ===== ===== =====
</TABLE>
<TABLE>
LPL US$ 000
-----------------------------------------
PHASE I PHASE II PHASE III 2009
------- -------- --------- -----
<S> <C> <C> <C> <C>
Personnel 0 0 250 250
Pump Maintenance 100 100 170 170
Mainline Maintenance 30 30 100 100
Mainline Inhibitor 225 225 225 225
In-Line Inspection 204
Tank Maintenance 30 30 130 130
Insurance 21 21 70 70
----- ----- ----- -----
Total 406 406 945 1 149
Inflation @ 2% 12 19 58 225
----- ----- ----- -----
Revised Estimate 418 425 1 003 1 374
===== ===== ===== =====
</TABLE>
37
<PAGE> 94
Exhibit No. 1 - Attachment C
IPL
Interprovincial Pipe Line Inc.
IPL Tower 10201 Jasper Avenue
P.0. Box 398
Edmonton, Alberta T5J 2J9
Robert L. Nichols 0ffice: (403) 420-5210
Vice-President, Accounting & Regulatory Affairs Direct: (403) 420-8274
Fax: (403) 420-5389
File No DDP96-08-07
April 22,1997
Mr. Michel L. Mantha
Acting Secretary
The National Energy Board
9th Floor, 311 - 6 Avenue S. W.
Calgary, AB T2P 3H2
Dear Mr. Mantha:
RE: 350 Centistoke Project
Application of Interprovincial Pipe Line Inc. for Orders
Pursuant to Section 58 and Part IV of the National Energy Board Act
Please find enclosed for filing twenty (20) copies of an Application made by
Interprovincial Pipe Line Inc. ("IPL") pursuant to Section 58 and Part IV of
the National Energy Board Act.
The program is intended to provide facilities necessary to allow IPL to raise
the density and viscosity limits of heavy crude accepted for transportation on
the IPL system and reduce the amount of condensate required for blending, while
maintaining current system capacity. The Application seeks an order
authorizing construction of line heaters and associated pump facilities and
modifications on the IPL system as well as associated toll orders implementing
an increase to the heavy crude oil surcharge to reflect the provision of
service for more viscous and dense commodities.
The capital cost of the facilities is approximately $9 million, and the planned
in service date is December 31, 1997.
The 350 Centistoke Program was developed between IPL and an industry task force
represented by heavy oil interests.1 The two objectives of the task force were
to provide service for more viscous and dense material while leaving other
classes of shippers unaffected. The project was developed in close cooperation
with the task force and IPL is unaware of any opposition among shippers to
either the construction or the 2 percentage point heavy crude surcharge
increase associated with the acceptance of 350 centistoke material. The
program has received the formal support of the Canadian
- ----------
1 The task force included Amoco Canada Petroleum Company Ltd., CAPP, Gibson
Petroleum Company Inc., Husky Oil Operations Ltd., Imperial Oil Resources
Limited, Murphy Oil Company Ltd., PanCanadian Petroleum Limited, Renaissance
Energy Ltd., Shell Canada Limited, Koch Oil Co. Ltd. and Talisman Energy Inc.
<PAGE> 95
350 Centistoke Project
Association of Petroleum Producers ("CAPP"). CAPP's letter supporting the
program is attached as Appendix I to this transmittal letter.
In the light of the cooperative efforts between IPL, the heavy crude producing
and shipping interests, and CAPP, IPL is of the view that there are no
unresolved industry issues surrounding the 350 Centistoke Project and notes
that the implementation of this program will have minimal toll impact on other
than heavy crude shippers when SEP II facilities are in-service.
The 350 Centistoke heater facilities will be ready for service before SEP II
facilities are in-service and IPL proposes constructing the 350 Centistoke
facilities but implementing the higher density and viscosity limits only upon a
request being made by CAPP. The 350 Centistoke facilities will provide a
benefit to IPL shippers prior to the implementation of increased density and
viscosity limits as their operation will have the effect of increasing
capacity, assuming the existing viscosity and density limits remain in place
until the Line 14 portion of the SEP II program is in-service
The facilities for which approval is sought pursuant to Section 58 are wholly
situated on IPL property, and there has been minimal landowner or other
stakeholder concerns identified through IPL's Early Public Notification
process. The Environmental Impact Assessment ("EIA") which forms part of the
Application has identified potential adverse environmental and socio-economic
effects and mitigative measures in respect of those potential effects. IPL has
undertaken to implement the recommended mitigative measures.
Based on the nature of the facilities applied for, the level of support in
respect of toll and facilities issues associated with the project, and no
identification of landowner or environmental or socio-economic concerns which
IPL believes cannot be mitigated, IPL requests that the Board consider this
Application by means of a written proceeding. In the light of the nature of
the issues raised by the Application, IPL is of the view that a written process
will allow a full and fair consideration of the issues while providing the most
efficient means of considering the project.
A copy of this Application is concurrently being served upon IPL's Interested
Parties list.
Yours very truly,
INTERPROVINCIAL PIPE LlNE INC.
R.L. Nichols
Vice-President,
Accounting & Regulatory Affairs
Enclosure
cc: Interested Parties
April 22, 1997
2
<PAGE> 96
Canadian Association Appendix I
of Petroleum Producers CAPP Letter of Support
CAPP
April 22, 1997
Mr. Robert L. Nichols
Vice President, Accounting & Regulatory Affairs
Interprovincial Pipe Line Inc.
10201 Jasper Avenue
Edmonton, Alberta T5J 2J9
Dear Mr. Nichols:
RE: INTERPROVINCIAL PIPE LINE INC. - 350 CENTISTOKE PROJECT APPLICATION
With respect to the above-noted application by Interprovincial Pipe Line (IPL)
to the National Energy Board, the Canadian Association of Petroleum Producers
(CAPP) supports the changes presented in the application.
On behalf of its members, CAPP has worked with IPL and the industry task force
to review the project and has concluded that the requested changes provide
overall benefit to the industry. The proposed changes will reduce the
requirement for diluent blending of heavy crude oils for shipment on the
Interprovincial pipeline system, which represents a significant saving to
producers. In addition, shortages in the supply of condensate used as diluent
have hampered producers' ability to bring their products to market.
Consequently, any reduction in the reliance on diluent will impact positively
on producers.
Prior to the completion of SEP 11, in 1998, there is uncertainty as to the
ability to implement the proposed changes without a negative impact on
non-heavy shippers. In the period before the completion of SEP II, the surplus
capacity needed on the Lakehead system to implement the 350 centistoke project
will be dependent on supply growth, market development and the utilization of
alternative pipelines. Interprovincial has committed to implementing the
proposed service changes in a timely manner, consistent with the needs of the
market place. Thus, implementation will be responsive to signals from the
market. As agreed, the necessary signal for IPL to proceed with the
implementation of the 350 centistoke change will be provided by CAPP, as a
representative of industry.
Yours truly,
Onno DeVries
Manager, Crude Oil and Fiscal Policy
2100, 350-7 Avenue S.W. Calgary, Alberta, Canada T2P 3N9
telephone (403) 267-1100 facsimile (403) 261-4622
<PAGE> 97
Exhibit No. 2
{LOGO}
NATIONAL ENERGY BOARD
- --------------------------------------------------------------------------------
Reasons for Decision
INTERPROVINCIAL PIPE LINE INC.
OH-1-96
July 1996
- --------------------------------------------------------------------------------
Facilities and Toll Methodology
<PAGE> 98
TABLE OF CONTENTS
<TABLE>
<S> <C>
LIST OF TABLES..................................................................ii
LIST OF FIGURES.................................................................ii
LIST OF APPENDICES..............................................................ii
RECITAL AND APPEARANCES........................................................iii
1. INTRODUCTION.................................................................1
1.1 The Application........................................................1
1.2 Environmental Screening................................................1
2. FACILITIES...................................................................3
2.1 Expansion Facilities...................................................3
2.1.1 Pipeline........................................................4
2.1.2 Pumps...........................................................4
2.1.3 Line 2B Heater..................................................5
2.1.4 Drag Reducing Agent.............................................5
2.2 Alternatives to the Proposed Expansion.................................6
3. LAND AND ENVIRONMENTAL MATTERS...............................................8
3.1 Route and Site Selection and Land Requirements.........................8
3.2 Environmental Matters..................................................9
4. FINANCIAL MATTERS AND TOLLING TREATMENT.....................................10
4.1 Financial Matters.....................................................10
4.1.1 Tolling Methodology.............................................10
4.1.2 Treatment of Costs..............................................10
4.2 Requested Exemption from the Guidelines for Filing Requirements.......10
4.3 Risk Sharing Agreement................................................11
5. SUPPLY AND MARKETS.....................................................omitted
5.1 Supply...........................................................omitted
5.2 Markets..........................................................omitted
5.2.1 Demand for Western Canadian Crude Oil and Equivalent......omitted
5.2.2 Western Canadian Crude Oil Available to IPL...............omitted
5.2.3 Markets for Incremental Crude Oil and NGL Sales...........omitted
5.2.4 Adequacy of Downstream Capacity...........................omitted
5.2.5 Tolls, Netbacks, and Producer Revenues....................omitted
6. DISPOSITION.................................................................15
</TABLE>
(i)
<PAGE> 99
LIST OF TABLES
<TABLE>
<S> <C> <C>
2-1 Comparison of Selected Expansion Alternatives.........................7
4-1 Summary of SEP II Toll Impact Incremental Tolls......................12
5-1 Forecast of Western Canadian Crude Oil Production Available to IPL.....
</TABLE>
LIST OF FIGURES
<TABLE>
<S> <C> <C>
1-1 IPL System Expansion Program Phase II..................................2
5-1 IPL Forecast of Western Canadian Crude Oil Production............omitted
5-2 IPL Forecast of Western Canadian Crude Oil Disposition...........omitted
5-3 Pipeline Capacity to Address Western Canadian Supply.............omitted
</TABLE>
LIST OF APPENDICES
<TABLE>
<S> <C> <C>
I Schedule of Facilities................................................16
II Certificate Conditions................................................19
</TABLE>
(ii)
<PAGE> 100
Recital and Appearances
IN THE MATTER OF the National Energy Board Act and the regulations made
thereunder;
AND IN THE MATTER OF an application dated 12 January 1996 by Interprovincial
Pipe Line Inc. for a Certificate of public convenience and necessity under Part
Ill of the Act, authorizing a capacity expansion of its pipeline system, and
for an Order under Part IV of the Act, respecting toll design and tariffs;
AND IN THE MATTER OF Hearing Order OH-l-96;
HEARD at Calgary, Alberta on 3, 4, 5 and 7 June 1996.
BEFORE:
R.L. Andrew Presiding Member
A. Cote-Verhaaf Member
J.A. Snider Member
APPEARANCES:
C.K. Yates Interprovincial Pipe Line Inc.
R.A. Neufeld
N.J. Schultz Canadian Association of Petroleum Producers
R.W. Laidlaw Alberta Energy Company Ltd.
F.R. Foran Amoco Canada Petroleum Company Ltd.
L.G. Keough Express Pipeline Ltd.
H.R. Huber Imperial Oil Limited, Mobil Natural Gas Canada Ltd.,
Petro-Canada, Shell Canada Limited
K.F. Miller Koch Oil Co. Ltd.
H.R. Huber Murphy Oil Company Ltd.
A. Reid Alberta Department of Energy
B. de Jonge National Energy Board Counsel
(iii)
<PAGE> 101
Chapter 1
INTRODUCTION
- --------------------------------------------------------------------------------
1.1 The Application
On 12 January 1996, Interprovincial Pipe Line Inc. ("IPL" or "the Company")
applied pursuant to Part III of the National Energy Board Act ("the Act") for a
certificate of public convenience and necessity to authorize the construction
of additional facilities on its pipeline system in western Canada and, pursuant
to Part IV of the Act, for an Order respecting toll design and tariffs.
The applied-for System Expansion Program Phase II ("SEP II") would consist of
pipeline, pump unit additions, pump modifications, pump replacements, motor
replacements, and drag reducing agent ("DRA") injection connections. The
proposed facilities, at an estimated cost of $140 million, would increase
delivery capability of the existing IPL system to Chicago by 19 600 m3/d
(120,000 b/d). A map of the IPL system is shown in Figure 1-1.
In a letter dated 31 May 1996, IPL filed with the National Energy Board ("the
Board") details of a Risk Sharing Agreement ("RSA") which it, together with
Lakehead Pipe Line Company ("Lakehead"), had negotiated with the Canadian
Association of Petroleum Producers ("CAPP"). The RSA modified the applied-for
toll treatment of the SEP II facilities to share the risk of underutilization
of these facilities. IPL sought to have the RSA approved as a Non-Routine
Adjustment pursuant to its Incentive Tolling Agreement.
1.2 Environmental Screening
The National Energy Board ("the Board") conducted an environmental screening of
the applied-for facilities in compliance with the Canadian Environmental
Assessment Act ("CEAA"). The Board ensured there was no duplication in
requirements under the CEAA and the Board's own regulatory process.
The Board determined that, taking into account the implementation of IPL's
proposed mitigative measures and those set out in the attached conditions, the
project is not likely to cause significant adverse environmental effects. This
represents a decision pursuant to paragraph 20(1 )(a) of the CEAA.
1
<PAGE> 102
{MAP - Figure 1-1 - IPL System Expansion Program Phase II}
2
<PAGE> 103
Chapter 2
FACILITIES
- --------------------------------------------------------------------------------
2.1 Expansion Facilities
IPL' s applied-for expansion includes the following:
Line 1 & construction of 148 km of 508 mm outside diameter ("O.D.")
pipeline from kilometre post ("kp") 22.1 near Edmonton to kp
170 near Hardisty, Alberta;
- replacement of four pipeline sections totaling 12 km of
508 mm O.D. pipeline between Hardisty and Herschel stations;
- replacement of 30 motors, replacement of 30 pumps,
modification of 11 pumps, addition of 11 pumping units and the
construction of 12 DRA injection skids at various stations
between Edmonton, Alberta and Gretna, Manitoba; and
- construction of a new pump station, NGL prover, booster
pumps and associated piping at the Edmonton Terminal.
Line 2B & construction of a 21 600 MJ (6 000 kWh) line heater at Cromer
station;
- replacement of 4 pump units; and
- the addition of 3 pump units.
Line 13 & reactivation of 22.1 km of 508 mm O.D. pipeline between the
Edmonton Terminal and kp 22.1;
- connection of five pump stations at Edmonton, Kingman,
Metiskow, Herschel and Craik from Line 1 to Line 13 service;
- connection of the refined products manifold, booster
pumps and associated piping at the Edmonton Terminal to
accommodate injections of refined products into Line 13;
- construction of eight mainline connections between kp
22.1 and kp 687.4 (near Regina) to accommodate the transfer of
501.2 km of 508 mm pipeline from Line 1 to Line 13 service; and
- construction of five DRA injection skids.
The proposed expansion will increase the capacity of Line 1 from 36 600 m3/d
(230,000 b/d) to 49 500 m3/d (311,000 b/d) and of Line 2B from 76 300 m3/d
(480,000 b/d) to 79 500 m3/d (500,000 b/d). The capacity of Line 13 of 31 000
m3/d (195,000 b/d) will not change. Upon completion of the SEP II expansion,
Line 1 will be used to transport crudes such as lube light, sweet light,
Synthetic and NGLs; Line 2 will transport condensate, Caroline Condensate, and
crudes such as sweet light, sour light, Synthetic, Sarnia Special, and OSE;
Line 3 will ship Bow River, heavy and sour light crudes and Line 13 will ship
Synthetic crude and refined products.
3
<PAGE> 104
The proposed Line 13 facilities are intended to facilitate the reallocation of
refined products from Line 1. A schedule summarizing the applied-for
facilities is included as Appendix 1.
2.1.1 Pipeline
IPL applied to construct a new 508 mm O.D. pipeline between kp 22.1 and
Hardisty, Alberta. This line would be used as a new Line 1 segment, and the
existing Line 1 pipeline between the Edmonton Terminal and Hardisty (including
the reactivated segment described below) would be transferred to Line 13
service. This would allow Line 13 to be operated as a continuous line from
Edmonton to Clearbrook, Minnesota. IPL submitted that the new pipeline would
be needed to facilitate the transfer of refined products from Line 1 to Line
13, as Line 1 is expected to become oversubscribed due to the forecast increase
in NGL shipments on Line 1 of 3 200 m3/d (20,000 b/d). IPL further explained
that in order to accommodate the increase in NGL shipments, either Line 1 had
to be expanded or refined products had to be moved into a different line. IPL
chose to move refined products into Line 13. IPL noted that the existing
capacity on Lines 2 and 3 between the Edmonton Terminal and Hardisty could not
be effectively utilized for refined products shipments without building a tank
farm at Hardisty and moving the refined products through this tankage to be
re-injected into Line 13 at Hardisty.
IPL also applied to reactivate a section of pipeline between Edmonton and kp
22.1. This segment was originally part of Line 1, but was taken out of service
in 1987 as the result of a capacity expansion program. In its application, IPL
requested exemption from retesting this section, pursuant to the requirements
of Part V of the Onshore Pipeline Regulations ("the Regulations"). The pipe
section was hydrotested in 1993 in preparation for IPL's 1994 capacity
expansion program but subsequently was not returned to service. Although this
section was internally inspected in 1972, 1980, and 1987, and corrosion
excavations of select locations were conducted between 1985 and 1989, no
inspection or further maintenance, beyond IPL's annual cathodic protection
survey, has been conducted on this line segment since 1993.
No parties expressed concerns with IPL's proposed pipeline construction.
2.1.2 Pumps
SEP II includes the construction of a new pump station (including four pumps)
on Line 1 at the Edmonton Terminal, the addition of pump units at Strome,
Hardisty, Cactus Lake, Loreburn (2 units), Bethune, Odessa, Cromer, West
Souris, Glenboro, and Manitou stations, and the replacement of 30 motors and
pumps and the modification of 11 pumps at various locations on Line 1. On Line
2B, new pump units would be installed at Souris, Glenboro, and Gretna stations,
while one pump and motor replacement would occur at Glenboro and three at
Manitou station.
No parties commented on IPL's proposed addition of pumping capacity.
4
<PAGE> 105
2.1.3 Line 2B Heater
IPL proposed the installation of a line heater on Line 2B at Cromer, Manitoba.
Heating the oil at Cromer would have the effect of reducing the viscosity of
the oil, thereby increasing the throughput at that location. IPL had not
undertaken the detailed design of the line heater prior to the start of the
OH-1-96 hearing. However, IPL indicated that detailed design information would
be provided to the board when it became available.
Express Pipeline Ltd. ("Express") questioned the estimated operating costs of
the proposed line heater, as compared to the line heater currently used by
Lakehead on Line 6 at Superior, Wisconsin. IPL agreed that the annual fuel
costs for the line heater would be in the range of $750,000 to $1,000,000,
although fuel contracts had not yet been obtained.
2.1.4 Drag Reducing Agent
IPL applied to install 12 Drag Reducing Agent ("DRA") injection skids at
Edmonton, Hardisty, Kerrobert, Milden, Loreburn, Bethune, Glenavon, Langbank,
Cromer, West Souris, Glenboro, and Manitou stations on Line 1, and five DRA
injection skids on Line 13 at Edmonton, Kingman, Metiskow, Herschel, and Craik
stations. DRA is a chemical additive that reduces the pressure gradient in the
section of pipe in which it has been injected. As part of the System Expansion
Program Phase I (approved by the Board under Order XO-J1-1-96). IPL installed
14 DRA skids on Line 2A and 6 skids on Line 13. Together, the SEP I and SEP II
applications represent a significant increase in the use of DRA on the IPL
system. In response to a question by the Board, IPL confirmed that it may now
be close to reaching the maximum economic limit for the use of DRA on Lines 1
and 2, although the exact economic limit had not been determined. IPL also
noted that while current DRA technology does not work effectively with heavy
oil, different products are being developed that may increase the application
of DRA. In addition, decreases in the cost of the drag reducing material could
change the economic cut-off point for its use.
VIEWS OF THE BOARD
With respect to the construction of 148 km of new 508 mm O.D. pipeline
between kp 22.1 and Hardisty, the Board agrees that IPL's proposed
construction is an appropriate method of accommodating the forecast
increase in natural gas liquids ("NGL") shipments from Edmonton.
With respect to the 22.1 km section of pipeline for which IPL requested
an exemption from pressure testing prior to reactivation, the Board notes
that section 54(I) of the Regulations requires that a pipeline be
retested in accordance with Part V of the Regulations prior to
reactivation, if the pipeline has been deactivated for 12 months or more.
In addition, the Board notes that IPL did not apply for a deactivation
of this line section as required by section 53(1) of the Regulations and
that the line section has been out of service for nine years. Absent a
retesting of the pipe section, the Board is not persuaded that the
reactivation would provide for a level of safety at least equivalent to
5
<PAGE> 106
that generally provided for by Canadian Standards Association ("CSA")
standards. Therefore, the Board will not exempt IPL from the requirement
to retest this line section prior to reactivation.
DECISION
IPL is directed to retest the line section between Edmonton and kp 22.1
in accordance with the requirements of Part V of the Regulations. Upon
successful completion of the retesting, IPL is further directed to notify
the Board of the results of the test (including the test pressures) and
the desired maximum operating pressure of the line.
2.2 Alternatives to the Proposed Expansion
As part of its application, IPL provided an evaluation of three alternatives to
its proposed design. Briefly, the alternatives consisted of: the addition of
84 km of 1219 mm O.D. looping on Line 3; increasing the operating pressure of
Line 1; or expanding the Westspur and Portal pipeline systems (including
extending Line 13 from Clearbrook to Superior). IPL noted that none of these
alternatives provided the required capacity increase of 19 600 m3/d (120,000
b/d). The alternatives were compared on the basis of capital expenditure per
unit of capacity increase.
At the request of the Board, IPL provided an assessment of the incremental
annual operating costs associated with each of the design alternatives, plus
the annual operating costs of its proposed expansion. IPL also provided an
assessment of an additional expansion alternative, consisting of sufficient
1219 mm O.D. looping on Line 3 to achieve the desired capacity increase. The
incremental toll impact of each option at 100% capacity utilization (no risk
sharing), and of Alternatives 4 (the sum of Alternatives 2 and 3) and 5 (the
Line 3 looping) at various utilization levels with the risk sharing agreement
were also provided. These comparisons are illustrated in Table 2.1.
IPL submitted that the principal drive for expanded pipeline capacity from
western Canada is the forecast increase in Canadian heavy crude oil production,
underpinned by a slower than anticipated decline in conventional light crude
oil production. IPL noted that its design intent was to create additional
space on Line 3 for the forecast heavy crude growth by moving sour and lighter
crudes off Line 3 and onto other lines. Although IPL's application originally
indicated that SEP Il would eliminate apportionment, IPL subsequently suggested
that the removal of market constraints for heavy crude (as described in section
5.2.1) would result in SEP II not being able to supply sufficient take away
capacity and that further expansions of the IPL system would be necessary.
6
<PAGE> 107
TABLE 2-1
COMPARISON OF SELECTED EXPANSION ALTERNATIVES
<TABLE>
<CAPTION>
SEP II Design Alternatives 2&3 Line 3 Looping
<S> <C> <C> <C>
Capital Cost (C$) 140,000,000 340,000,000 490,000,000
Capacity increase (m3/d) 19600 18600 19600
Incremental Annual Power Cost 19,400,000 18,500,000 8,400,000
Incremental Annual DRA Cost 3,700,000 2,600,000 0
Unit Cost ($/m3/d increase) 7,143 18,300 25,000
Toll Increase (No Risk Sharing) 2c. 5c. 5c.
Toll Increase @ 100% Utilization 3c. 6c. 6c.
(Risk Sharing)
Toll Increase @ 75% Utilization 2c. 4c. 5c.
(Risk Sharing)
</TABLE>
Express argued that the applied-for facilities would not do the job that they
were intended to do. It noted that IPL's evidence suggested that by 1999 there
would be almost no spare capacity on Line 3 to accommodate the forecast
increase in heavy oil supply and that an additional expansion of IPL's system
would be necessary to address the apportionment issue. Express also argued
that IPL had failed to provide any meaningful comparison of alternatives which
would address the true demand for additional capacity on its system.
VIEWS OF THE BOARD
The Board finds a comparison of viable alternatives to be germane to its
assessment of the appropriateness of a proposed design. The Board notes
that the proposed design is the most cost-effective of the various
alternatives presented, and that the design provides some flexibility to
minimize the cost of transportation if throughput were to fluctuate in
the future. The Board also notes that IPL's proposed design does not
appear to fully resolve the issue of capacity constraint for heavy crude
shipments. However, the Board appreciates the high level of support
accorded to the proposed expansion and, therefore, the Board accepts
IPL's applied-for design.
7
<PAGE> 108
Chapter 3
LAND AND ENVIRONMENTAL MATTERS
- --------------------------------------------------------------------------------
3.1 Route and Site Selection and Land Requirements
IPL stated that its proposed expansion was designed to follow its existing
pipeline corridor while at the same time avoiding or minimizing new surface
disturbance and attendant negative impacts to the biophysical and
socio-economic environments. IPL determined that these needs could best be met
by constructing additional pipeline parallel to its pipeline corridor, by
modifying its existing pipeline tie-ins, and by increasing pumping capacity at
several IPL stations between Edmonton, Alberta and Gretna, Manitoba.
Two alternative pipeline routes were considered by IPL. The first alternative
involved paralleling their pipelines between Edmonton and Hardisty along the
north side of their existing pipeline corridor. The second alternative
involved crossing over their pipeline from the north side near Kingman Pump
station (kp 51.1), paralleling the corridor along the south side to kp 152.1
near Lougheed, Alberta and then crossing back to the north side for the
remainder of the segment to kp 170.0 near Hardisty, Alberta. IPL chose the
second alternative as it would involve acquisition of less new permanent
easement than the first alternative.
With respect to the location of new facilities, other than line pipe,
consideration was not given to new sites as existing sites offered the
following advantages:
- the existing facilities have been in service for up to 40
years and are well known to all parties;
- no significant environmental or socio-economic constraints
are associated with the existing facilities sites;
- impacts associated with new facilities on new sites would
increase the amount of land disturbed by IPL operations; and
- terminal and pump station operations can be completed more
efficiently from existing facilities rather than from additional
facilities that are geographically separated.
IPL indicated that it would require 18.3 m of new permanent right-of-way and
between 5 and 17 m of temporary working rights. IPL provided six different
configurations for the various loop segments proposed as well as a summary of
the new land requirements on a station by station
8
<PAGE> 109
basis.
No parties objected to the proposed routing/siting or the requirements for new
land rights.
VIEWS OF THE BOARD
The Board agrees with IPL's rationale for installing the proposed
pipeline facilities
either within existing easements or adjacent to its existing easement.
The Board further finds that the general routes proposed are acceptable
and that IPL's anticipated requirements for permanent easements and
temporary work space are reasonable.
3.2 Environmental Matters
The Board completed an Environmental Screening Report pursuant to the CEAA and
the Board's own regulatory process. In accordance with Hearing Order OH-1-96,
the Environmental Screening Report was released to IPL, those parties who
requested a copy from the Board, and federal agencies that had provided
specialist advice on the proposed facilities.
The comments received, and the Board's views, have been added to the
Environmental Screening Report as Appendices I and II respectively. Copies of
the Board's Environmental Screening Report are available upon request from the
Board's Regulatory Support Office.
VIEWS OF THE BOARD
The Board has considered the Environmental Screening Report, and the
comments received on the report, and is of the view that the SEP II
project is not likely to cause significant adverse environmental effects,
when considered with the implementation of IPL's proposed mitigative
measures and those set out in the attached conditions. This represents a
decision pursuant to paragraph 20(l)(a) of the CEAA.
The Board is satisfied with the environmental and socio-economic
information provided by IPL with regard to the potential adverse
environmental effects which may result from the construction and
operation of the proposed facilities and with IPL's proposed monitoring
and mitigation measures.
9
<PAGE> 110
Chapter 4
FINANCIAL MATTERS AND TOLLING TREATMENT
- --------------------------------------------------------------------------------
4.1 Financial Matters
4.1.1 Tolling Methodology
IPL applied for approval of an integrated toll design methodology for the SEP
11 facilities. The Company considered the SEP II facilities to be a capital
program related to an extension of the existing services it provides to
shippers.
No parties expressed concerns regarding IPL's applied-for tolling methodology.
4.1.2 Treatment of Costs
IPL requested that the Board find the costs of SEP 11 to be a Non-Routine
Adjustment in accordance with the Principles of Settlement, filed in support of
its February 1995 Incentive Toll Application.
No parties were opposed to IPL's proposed treatment of the costs of SEP II as a
Non-Routine Adjustment.
VIEWS OF THE BOARD
Since SEP II is an extension of the existing services that IPL provides
to its shippers, the Board considers it appropriate that the costs of the
program be rolled-in. Furthermore, the Board agrees that these costs
constitute a Non-Routine Adjustment under the terms of IPL's February
1995 Incentive Toll Agreement.
4.2 Requested Exemption from the Guidelines for Filing Requirements
In its application, IPL requested exemption from filing proforma statements of
rate base and cost of service as well as proposed method and rates of
depreciation by plant account contemplated in the February 1995 Guidelines for
Filing Requirements ("the Guidelines"). IPL submitted that this information
was not relevant under IPL's incentive method of financial regulation approved
by the Board under Order TO-1-95.
IPL also requested exemption from filing five years of average unit
transportation costs (tolls)
10
<PAGE> 111
beyond the first year after the SEP II facilities are expected to be in
service. IPL stated its view that in light of the incentive method of
regulation which governs IPL's operations, it is not possible to forecast tolls
with reasonable reliability over a five year term. IPL further submitted that
tolls would vary from year to year based on operating results, and that
providing five year tolls based on a series of assumptions may not be
meaningful to the Board.
IPL further sought exemption from filing proforma balance sheets, proforma
financial statements, and supporting details on the proposed return on rate
base and provision for income taxes because, in IPL's view, the magnitude of
the debt component of the financing was not material to IPL's financial
position.
No parties opposed IPL's request for exemption from the Guidelines.
VIEWS OF THE BOARD
The Board considers the reasons given by IPL for not filing the above
information to be acceptable and, therefore, grants the requested
exemptions from the Guidelines.
4.3 Risk Sharing Agreement
By letter dated 31 May 1996, IPL filed the updated evidence of Brian T. Vaasjo.
In this evidence, Mr. Vaasjo stated that IPL was approached by CAPP to discuss
the possibility of reaching an agreement to share the risks relating to the
potential under-utilization of the SEP II facilities. The first meeting was
held on 17 May 1996 and an agreement was reached on 31 May 1996.
The Risk Sharing Agreement ("RSA") relates to both IPL and Lakehead in respect
of the SEP II facilities and would be subject to approval by the National
Energy Board and the Federal Energy Regulatory Commission.
Under the RSA, the rate of return on the deemed equity portion of the SEP II
facilities would vary based upon the level of utilization of the facilities.
At 75% utilization of the facilities, or 14 700 m3/d (90,000 b/d), the return
on the deemed equity component of the SEP II facilities would be the annual
multi-pipeline rate as determined by the Board. If the SEP II facilities are
utilized at between 0% and 50%, or up to 9 800 m3/d (60,000 b/d), the return on
the deemed equity of SEP II would be the multi-pipeline rate less 3.0%, subject
to a minimum rate of return of 7.5% in years 1 through 10 and 8.5% in years 11
through 15. The rate of return on SEP II deemed equity increases with
facilities utilization on a straight line basis, from the multi-pipeline rate
less 3.0% at 50% utilization to the multi-pipeline rate plus 3.0% at 100%
utilization, subject to a maximum rate of return of 15.0% during the term of
the agreement. The toll impact of the SEP II facilities is shown in Table 4-1.
The utilization level of the SEP II facilities would be calculated on a full
system basis. That is, IPL would determine the total system capacity by adding
the 19 600 m3/d (120,000 b/d) throughput related to the SEP II expansion to the
annual capacity under the Incentive Toll Agreement. The actual throughput
would then be measured and compared to this total system
11
<PAGE> 112
capacity to determine the utilization level. The percentage of the SEP II
facilities utilized would determine the return level to be received by IPL for
these facilities. To the extent that actual throughput was less than the total
system capacity there would be a volume shortfall. For example, if that
shortfall was 4 900 m3/d (30,000 b/d), the SEP II facilities would be 75%
utilized and IPL would earn the annual multi-pipeline rate.
TABLE 4-1
SUMMARY OF SEP II TOLL IMPACT
INCREMENTAL TOLLS
(c./b Canadian)1
<TABLE>
<CAPTION>
Total IPL Lakehead2
<S> <C> <C> <C>
Without Risk Sharing
--------------------
At 100% Utilization 10 2 8
At 0% Utilization 10 2 8
With Risk Sharing
--------------------
At 100% Utilization 12 3 9
At 50% Utilization 6 1 5
At 0% Utilization 6 1 5
</TABLE>
(1) Incremental light crude tolls on Edmonton to Chicago
(2) Assuming 100% tax allowance
Further expansions of the IPL system would be "stacked on top" of the SEP II
facilities. In determining the utilization rates, post-SEP II expansions would
be considered to be the "top" volumes and these expansions would have to go
totally unused for the utilization of the SEP II facilities to fall below 100%.
The return on post-SEP II expansions would be governed by IPL's Incentive Toll
Agreement.
Other stipulations of the RSA include the following:
- DRA costs would flow through as a surcharge;
- all other costs including operating, interest and
depreciation costs would flow through to the tariffs;
- the agreement would be subject to approval of the IPL and
Lakehead Boards of Directors;
12
<PAGE> 113
- the term of the agreement is for 15 years, commencing on the
date of completion of the facilities construction; and
- the existing toll design would not be affected and
point-to-point tolls would reflect a volume-distance allocation of
costs.
IPL stated that it was of the view that the RSA would result in just and
reasonable tolls, and that its terms should be approved by the Board as a
Non-Routine Adjustment in accordance with paragraph 7.1 (a)(i) of the
Principles of Settlement filed in support of IPL' s February 1995 Incentive
Toll Application approved by Board Order TO-l-95.
No parties were opposed to the RSA. The RSA was supported by parties including
Amoco and the Shippers Group1, as well as Koch Oil on its own, behalf. The
Shippers Group noted that the RSA is an innovative and appropriate method of
ensuring that some of the risk associated with potential under-utilization of
expansion capacity would be borne by the pipeline, rather than by the shippers.
Koch submitted that the RSA is a highly significant benefit for shippers on
IPL is consistent with the spirit, intent, and provisions of the February 1995
Incentive Toll settlement between IPL and CAPP and, therefore, should be
approved by the Board.
The Board questioned whether the variable rate of return feature of the RSA
could be accommodated as a Non-Routine Adjustment within the terms of the
Principles of Settlement. Section 7.3 of the Principles of Settlement defines a
Non-Routine Adjustment as the sum of three components: operating cost, capital
cost, and annual income taxes. The capital cost component is itself defined in
subsection 7.3(b) to include depreciation expense, annual interest expense,
and:
"Annual earnings based on the common equity rate of return in effect
resulting from the National Energy Board Multi-Pipeline Proceeding
(RH-2-94) as adjusted from time-to-time, and applied to the applicable
negotiated equity ratio set out in Article 7.3(b)(ii)."
IPL argued that this paragraph did not mean that the annual earnings component
must be calculated using a rate of return equal to the multi-pipeline rate of
return. Rather, it argued that the agreement provided that annual earnings
would be "based on" the multi-pipeline rate of return. Since the variable rate
of return provided for in the RSA is either the same as the multi-pipeline rate
of return or is calculated upward or downward from the multi-pipeline rate of
return, IPL argued that it was "based on" the multi-pipeline rate of return
within the meaning of the Principles of Settlement. Accordingly, IPL argued
that the RSA did not amount to an amendment to the Principles of Settlement,
nor was an amendment to Order TO-1-95 required.
VIEWS OF THE BOARD
Without deciding whether the interpretation put forward by IPL is a
correct interpretation of section 7.3 of the Principles of Settlement,
the Board is of the view that it can approve the terms of the RSA in this
proceeding. The public notice of the hearing,
- ---------------
1 The Shippers Group was comprised at Imperial Oil Limited, Koch Oil Co. Ltd.,
Mobil Natural Gas Canada Ltd., Petro-Canada, Shell Canada Limited, and Murphy
Oil Company Ltd.
13
<PAGE> 114
attached as Appendix I to the Hearing Order, stated that the application
sought Orders from the Board pursuant to Part IV of the Act respecting
toll design and tariffs; and the preliminary list of issues attached as
Appendix III to the Hearing Order included, as item #9. "The design and
elements of the tolls applied for by IPL." Even though the RSA was not
originally part of the application, the Board is of the view that the
public notice of the hearing, together with the preliminary list of
issues attached to the Hearing Order, was sufficiently broad to put
interested persons on notice that toll design in respect of the
applied-for facilities would be considered in this proceeding. The Board
is further of the view that in disposing of that issue, it is not
necessarily limited to dealing with the proposal originally made by IPL
in its application. The Board therefore finds that it has jurisdiction
to approve the RSA in this proceeding, even if this would effectively
amount to an amendment to the Principles of Settlement or Order TO-1-95.
The Board notes that the RSA has broad shipper support and is satisfied
that the settlement represented by the RSA is just and reasonable in the
circumstances. The terms of the RSA are therefore approved.
- ---------------
1 The Shippers Group was comprised at Imperial Oil Limited, Koch Oil Co. Ltd.,
Mobil Natural Gas Canada Ltd., Petro-Canada, Shell Canada Limited, and Murphy
Oil Company Ltd.
14
<PAGE> 115
Chapter 6
DISPOSITION
- --------------------------------------------------------------------------------
The foregoing constitutes our Decision and Reasons for Decision in respect of
the application heard by the Board in the OH-1-96 proceeding. The Board
accepts the supply and markets information provided by IPL as reasonable. In
addition, the Board finds that the design of the System Expansion Program Phase
II is acceptable to fulfil the demand for additional capacity on the IPL
system.
With regard to Part IV matters, the Board approves a rolled-in tolling
methodology for the System Expansion Program Phase II. The Board finds that the
capital and operating costs relating to SEP II constitute a Non-Routine
Adjustment in accordance with paragraph 7.1 (a)(i) of the principles of
settlement, filed in support of IPL's February 1995 Incentive Toll Application
approved by NEB order TO-1-95. The Board also approves the terms of the Risk
Sharing Agreement.
The Board is satisfied that the evidence indicates a strong likelihood that the
facilities will be used at a reasonable level and are required by the present
and future public convenience and necessity. Therefore, the Board will
recommend to the Governor-in-Council that a certificate be issued. The
certificate will be subject to the conditions outlined in Appendix II.
R.L. Andrew
Presiding Member
A. Cote-Verhaaf
Member
J.A. Snider
Member
Calgary, Alberta
July, 1996
15
<PAGE> 116
Appendix I
SCHEDULE OF FACILITIES
- --------------------------------------------------------------------------------
FIGURE A1-1
<TABLE>
<CAPTION>
Station Units Description
- ------- ----- -----------
<S> <C> <C>
Edmonton to Hardisty Line 1 508 mm O.D. pipeline
- --------------------------------------------------------------------------------
Edmonton 1.1, 1.2, 1.3, 1.4 Unit addition
Line 1 DRA skid
13.1. 13.2, 13.3 Existing station transferred
Line 13 DRA skid
- --------------------------------------------------------------------------------
Kingman 13.1. 13.2 Existing station transferred
Line 13 DRA skid
- --------------------------------------------------------------------------------
Strome 1.1 Modify pump, replace motor
1.2 Replace pump and motor
1.3 Unit addition
- --------------------------------------------------------------------------------
Hardisty 1.1, 1.2, 1.3 Replace pump and motor
1.4 Unit addition
Line 1 DRA skid
- --------------------------------------------------------------------------------
Metiskow 13.1, 13.2 Existing station transferred
Line 13 DRA skid
- --------------------------------------------------------------------------------
Cactus Lake 1.1 Modify pump, replace motor
1.2 Replace pump and motor
1.3 Unit addition
- --------------------------------------------------------------------------------
Kerrobert 1.1, 1.2, 1.3 Replace pump and motor
1.4 Modify pump, replace motor
Line 1 DRA skid
- --------------------------------------------------------------------------------
Hershel 13.1, 13.2 Existing station transferred
Line 13 DRA skid
- --------------------------------------------------------------------------------
Milden 1.1 Replace pump and motor
1.2, 1.3 Modify pump, replace motor DRA skid
Line 1
- --------------------------------------------------------------------------------
</TABLE>
16
<PAGE> 117
<TABLE>
<S> <C> <C>
- --------------------------------------------------------------------------------
Loreburn 1.1, 1.2 Replace pump and motor
1.3, 1.4 Unit additions
Line 1 DRA skid
- --------------------------------------------------------------------------------
Craik 13.1., 13.2 Existing station transferred DRA skid
Line 13
- --------------------------------------------------------------------------------
Bethune 1.1 Modify pump, replace motor
1.2 Replace pump and motor
1.3 Unit addition
Line 1 DRA skid
- --------------------------------------------------------------------------------
Regina 1 .1. 1.2 Replace pump and motor
- --------------------------------------------------------------------------------
White City 1.1 Replace pump, transfer meter
1.2 Replace pump and motor
- --------------------------------------------------------------------------------
Odessa 1.1 Replace pump, transfer motor
1.2 Replace pump and motor
1.3 Unit addition
- --------------------------------------------------------------------------------
Glenavon 1.1 Replace pump, transfer motor
1.2, 1.3 Replace pump and motor
Line 1 DRA skid
- --------------------------------------------------------------------------------
Langbank 1.1 Replace pump, transfer motor
1.2. 1.3 Modify pump, replace motor
Line 1 DRA skid
- --------------------------------------------------------------------------------
Cromer 1.1 Replace pump
1.2 Replace pump and motor
1.3 Unit addition
Line 1 DRA skid
Line 2 Line heater
- --------------------------------------------------------------------------------
West Souris 1.1 Replace pump, transfer motor
1.2 Replace pump and motor
1.3 Unit addition
Line 1 DRA skid
- --------------------------------------------------------------------------------
Souris 2.3 Modify pump
2.5 Unit addition
- --------------------------------------------------------------------------------
Glenboro 1.1 Modify pump
1.2 Modify pump, replace motor
1.3, 2.6 Unit addition
2,1 Replace pump and motor
Line 1 DRA skid
- --------------------------------------------------------------------------------
Manitou 1.1 Replace pump, transfer motor
1.2, 2.1, 2.2, 2.3 Replace pump and motor
1.3 Unit addition
Line 1 DRA skid
- --------------------------------------------------------------------------------
</TABLE>
17
<PAGE> 118
<TABLE>
<S> <C> <C>
- --------------------------------------------------------------------------------
Gretna 1.1 Replace pump, trans. Motor
1.2 Replace pump
1.3 Modify pump
2.4 Unit addition
- --------------------------------------------------------------------------------
</TABLE>
18
<PAGE> 119
Appendix II
CERTIFICATE CONDITIONS
- --------------------------------------------------------------------------------
Unless the Board otherwise directs;
1. IPL shall implement or cause to be implemented all of the
policies, practices, recommendations and procedures for the
protection of the environment included in or referred to in its
application with the exception of minor adjustments or changes to
these practices, procedures and recommendations which may be
required as a result of site conditions at the time at construction.
These minor amendments to practices, procedures and recommendations
will be reviewed by IPL's on-site Environmental Inspector and,
providing the same standard of environmental protection is achieved,
may be implemented without prior Board approval, federal, provincial
and/or the local authorities shall be consulted, where appropriate.
2. IPL shall, 15 days prior to the commencement to construction
to the Eagle Creek crossing, advise the Board of the results of the
Company's consultations with provincial authorities and with the
Department of Fisheries and Oceans.
3. IPL shall, 15 days prior to the commencement of the
hydrostatic test program, file with the Board copies of permits for
the withdrawal and discharge of the hydrostatic test water.
4. IPL shall, 30 days after the in-service date, conduct noise
emission surveys at each pump station where the addition of extra
pumping units has occurred and file such reports with the Board.
The noise emission surveys shall include actual noise level
measurements at intervals along the station fence line and within 15
m of the nearest residence.
5. IPL shall, pursuant to section 58 of the National Energy
Board Onshore Pipeline Regulations ("the Regulations"), file with
the Board a post-construction environmental report within six months
of the date that the construction is completed. The
post-construction environmental report shall set out the
environmental issues that have arisen up to the date on which the
report is filed and shall:
(a) indicate the issues resolved and those unresolved; and
(b) describe the measures IPL proposes to take in respect
of the unresolved environmental issues.
6. IPL shall, pursuant to section 58 of the Regulations, file
with the Board, on or before the 31 December following each of the
first two complete growing seasons after the post-construction
environmental report referred to in condition 5 has been filed, a
19
<PAGE> 120
report containing:
(a) a list of the environmental issues indicated as
unresolved in the previous report and any that have arisen since
that report was filed; and
(b) a description of the measures IPL proposes to take in
respect of any unresolved environmental issues.
7. IPL shall, at least 10 days prior to the commencement of
construction of the approved pipeline facilities between Edmonton
and Hardisty, file with the Board the results of the heritage
resource surveys referred to in the application, including any
corresponding avoidance or mitigative measures.
8. IPL shall, prior to the commencement of construction:
(a) serve the heritage resource surveys on Alberta
Community Development and the Saskatchewan Heritage Branch;
(b) seek the opinion of each provincial agency described in
subsection (a) above, concerning the acceptability or
non-acceptance of the heritage resource surveys and
(c) advise the Board of the respective opinions of each
provincial agency described in subsection (a) above, or of IPL's
inability to obtain an oral or written opinion of one or more of
the provincial agencies described in subsection (a) above.
9. IPL shall file with the Board detailed design information
concerning the Line 2B heater at least 10 days prior to the
scheduled in-service date of the heater.
10. This certificate shall expire on 1 July 1999 unless the
construction and installation of the proposed facilities has
commenced by that date.
20
<PAGE> 121
EXHIBIT NO. 3
EXPLANATORY STATEMENT
SEP II RISK SHARING AGREEMENT
This Explanatory Statement briefly summarizes the primary provisions of
the SEP II Risk Sharing Agreement (Exhibit 1, Attachment A, Appendix D).
1. The SEP II Risk Sharing Agreement ("RSA") applies to both Enbridge and
Lakehead with respect to the System Expansion Project Phase II facilities. It
was entered into subject to Commission approval, and was contained in the FERC
Settlement that was approved by the Commission on October 18, 1996.
2. The general intent of the RSA as applied to Lakehead is to treat as a
floor the rates established by the original FERC Settlement (subject to
indexing adjustments since the date on which that settlement was approved). The
costs of the SEP II project are to be recovered as a separate surcharge on top
of the settlement rates, calculated on the basis of Lakehead's cost of service
for the SEP II facilities viewed as a separate project.
3. For purposes of the SEP II cost-of-service calculation, Lakehead will
apply the same cost-of-service model as was applied to calculate the settlement
rates (i.e., one based on Opinion No. 154-B as interpreted in Opinion Nos. 397
and 397-A), with certain specified adjustments described below. The additional
revenues realized as a result of the expanded throughput made possible by SEP
II will be treated as a credit against the SEP II cost of service. In this
way, only the net costs of the project will be included in the surcharge.
4. The surcharge will be designed to recover the SEP II costs during a
period of 15 years. Because of the impacts on the SEP II rate base from
depreciation and trending, as well as changes in operating costs and projected
throughput from year to year, Lakehead will
<PAGE> 122
recalculate and refile the SEP II surcharge to be effective as of January 1
each year. Both the initial surcharge filing and the yearly recalculated
filings will be accompanied by a cost-of-service showing based on the terms of
the FERC Settlement and the RSA. The surcharge will expire automatically after
15 years.
5. The rate of return to be used each year in the surcharge calculation is
to be based on the so-called multi-pipeline rate of return ("MPR") as
determined annually by the National Energy Board of Canada. The MPR was
initially set at 12.25% as of 1995 at the conclusion of a generic proceeding on
rate of return conducted by the NEB. The MPR is adjusted annually by the NEB
based on changes in interest rates. The actual rate of return in the surcharge
calculation in any given year may vary upwards or downwards from the MPR
depending on the degree of utilization of the SEP II facilities. If the
facilities are 50 percent utilized or less, the rate of return will be the MPR
less 3.00%, subject to a minimum rate of return of 7.50% in years 1 through 10
and 8.50% in years 11 through 15. If the facilities are 75 percent utilized,
the rate of return will be equivalent to the MPR. If the facilities are 100%
utilized, the rate of return will be the MPR plus 3.00%, subject to a maximum
rate of return of no more than 15 percent at a time. At utilizations between
50 percent and 100 percent, the rate of return will vary proportionately
between the levels stated above.
6. In accordance with paragraph 13.A. of the FERC Settlement, the tax
allowance in the surcharge calculation is to be computed using 30 percent of the
amount that would be allowed if Lakehead were a corporation rather than a master
limited partnership. This agreement reflects the ruling in Opinion Nos. 397 and
397-A that master limited partnership pipelines are not entitled to a tax
allowance on their net income attributable to individual unitholders. E.g.,
Opinion No. 397-A, 75 FERC paragraph 61,181, at 61,593-99 (1996). The 30
percent
2
<PAGE> 123
figure takes into account the ownership of Lakehead units by Lakehead and other
corporations and similar entities, as well as the attribution of book net
income to Lakehead for management incentives and other purposes.
7. The surcharge will be calculated in accordance with the existing
Lakehead rate design, with point-to-point rates reflecting a volume-distance
allocation of costs.
8. As a settlement, the SEP II provisions regarding rate of return, tax
allowance and other matters are the product of compromise and are not intended
to reflect the individual views of Lakehead, Enbridge or CAPP on any
substantive ratemaking issue.
3
<PAGE> 124
Exhibit No. 4
National Energy Board
- --------------------------------------------------------------------------------
Reasons for Decision
INTERPROVINCIAL PIPE LINE INC.
OH-1-98
June 1998
- --------------------------------------------------------------------------------
Facilities and Toll Methodology
<PAGE> 125
National Energy Board
- --------------------------------------------------------------------------------
REASONS FOR DECISION
In the Matter of
Interprovincial Pipe Line Inc.
Application dated 2 December 1997,
as amended, for the Terrace Phase I
Expansion Program
OH-1-98
JUNE 1998
<PAGE> 126
<TABLE>
<S> <C>
(C) Her Majesty the Queen in Right of Canada 1998 as (C) Sa Majeste La Reine du Chef du Canada 1998
represented by the National Energy Board represente par l'Office national de l'energie
Cat. No. NE22-l/1998-3E No de cat. NE22-1/1998-3F
ISBN 0-662-26864-4 ISBN 0-662-82943-3
This report is published separately in both official Ce rapport est publie separement dans les deux
languages. langues officielles.
COPIES ARE AVAILABLE ON REQUEST FROM: EXEMPLAIRES DISPONIBLES SUR DEMANDE AUPRES DU:
The Publications Office Bureau des publications
National Energy Board Office national de l'energie
311 Sixth Avenue S.W. 311, sixieme avenue s.-o.
Calgary, Alberta, T2P 3H2 Calgary (Alberta), T2P 3H2
E-Mail: orders @ neb.gc.ca Courrier electronique: orders @ neb.gc.ca
Fax: (403) 292-5503 Telecopieur: (403) 292-5503
Phone: (403) 292-3562 Telephone: (403) 292-3562
1-800-899-1265 1-800-899-1265
For pick-up at the NEB office: En personne, au bureau de l'Office:
Library Bibliotheque
Ground Floor Rez-de-chaussee
Printed in Canada Imprime au Canada
</TABLE>
<PAGE> 127
TABLE OF CONTENTS
List of Tables..........................................................ii
List of Figures.........................................................ii
List of Appendices......................................................ii
Abbreviations and Definitions...........................................iii
Recital and Appearances.................................................v
1. Introduction.......................................................1
1.1 The Application...............................................1
1.2 Environmental Screening.......................................2
2. Facilities.........................................................4
2.1 Current and Proposed Operation................................4
2.2 Applied-for Facilities........................................5
2.3 Integrity.....................................................7
2.3.1 Line 4 - Internal Inspection Capability...............7
2.3.2 Line 13- Idle Pipe Sections...........................7
2.3.3 Line 2-Laminar Flow...................................7
2.4 Alternatives to the Proposed Expansion .......................8
2.5 Adequacy of Downstream Capacity...............................9
3. Environment and Land Matters.......................................10
3.1 Route and Facility Site Selection.............................10
3.1.1 Pipeline Route Selection..............................10
3.1.2 Permanent Facility Site Selection ....................10
3.2 Land Requirements and Acquisition.............................11
3.3 Environmental Matters.........................................11
4. Supply, Markets and Economic Matters...............................12
4.1 Supply........................................................12
4.2 Markets.......................................................14
4.2.1 Demand................................................14
4.2.2 Western Canadian Crude Oil Available to IPL ..........14
4.2.3 Throughput............................................16
4.3 Economic Feasibility..........................................16
4.3.1 Support for Project...................................17
5. Tolls and Financial Matters........................................18
6. Disposition ....................................................19
(i)
<PAGE> 128
LIST OF TABLES
2-1 Allocation of Commodity Types by Line...............................4
2-2 Annual Throughput Capacities........................................5
2-3 Alternatives to the Proposed Expansion..............................8
4-1 Forecast of Western Canadian Crude Oil Production Available to IPL..15
LIST OF FIGURES
1-1 IPL Terrace Phase I System Map......................................3
4-1 IPL Forecast of Western Canadian Crude Oil Production...............13
LIST OF APPENDICES
I List of Issues..................................................20
II Terrace Toll Agreement..........................................21
III IPL's System Operation..........................................32
IV Certificate Conditions..........................................33
V Order XO-JI-16-98...............................................37
VI Order AO-l-XO-JI-10-98..........................................40
(ii)
<PAGE> 129
ABBREVIATIONS AND DEFINITIONS
<TABLE>
<S> <C>
Act National Energy Board Act
apportionment The method of allocating the difference between the total nominated volume and the
available pipeline operating capacity, where the latter is smaller.
barrel One barrel is approximately equal to 0.16 m3.
b/d barrels per day
Board National Energy Board
CAPP Canadian Association of Petroleum Producers
CEAA Canadian Environmental Assessment Act
crude oil and equivalent A collective term used to refer to all grades of crude oil, including conventional light
and heavy crude oil, pentanes and heavier hydrocarbons, synthetic crude oil and bitumen.
Express Express Pipeline Ltd.
Guidelines for Negotiated Settlements The Board's 1994 Guidelines for Negotiated Settlements of Traffic, Tolls and Tariffs
heavy crude oil A collective term which includes conventional heavy crude oil and bitumen.
IPL Interprovincial Pipe Line Inc.
km kilometre
KP kilometre post
Lakehead Lakehead Pipe Line Partners, L.P.
laminar flow A flow regime where fluid molecules in a pipe move in a parallel manner and the fluid
exhibits a parabolic velocity profile (i.e., velocity at the pipe wall is zero while
velocity at the centre of the pipe is the maximum).
Line 9 IPL's pipeline that extends from Sarnia, Ontario to Montreal, Quebec.
</TABLE>
(iii)
<PAGE> 130
<TABLE>
<S> <C>
Line 14 A pipeline currently under construction by Lakehead which will extend from Superior,
Wisconsin to the Chicago, Illinois area.
m3/d cubic metres per day
mm millimetre
netback The per unit price received by a producer from the sale of crude oil, less applicable
costs. These typically include transportation and marketing fees.
OD outside diameter
OH-1-96 Interprovincial Pipe Line Inc., Application for System Expansion Program Phase II, Reasons
for Decision dated July 1996.
OH-2-97 Interprovincial Pipe Line Inc., Application for the Line 9 Reversal Project, Reasons for
Decision dated December 1997.
OSE A light sour synthetic crude oil that is produced at the Suncor Inc. oil sands plant in
Fort McMurray, Alberta.
PADD U.S. Petroleum Administration for Defence Districts
SEP II Interprovincial Pipe Line Inc.'s System Expansion Program Phase II, approved by the Board
in OH-l-96.
Terrace Phase I Interprovincial Pipe Line Inc.'s Terrace Phase I Expansion Program.
WTI West Texas Intermediate crude oil - a light sweet crude oil, produced in the United States,
which is the benchmark grade of crude oil for North American price quotations.
</TABLE>
(iv)
<PAGE> 131
RECITAL AND APPEARANCES
IN THE MATTER OF the National Energy Board Act ("the Act") and the regulations
made thereunder;
IN THE MATTER OF an application by Interprovincial Pipe Line Inc. dated 2
December 1997, as amended on 31 March 1998, for a Certificate of Public
Convenience and Necessity pursuant to section 52 of the Act; an order pursuant
to section 58 of the Act for other related facilities; an order pursuant to
section 21 of the Act varying Board Order XO-JI-l0-98; and an order under Part
IV of the Act respecting toll design methodology; and
IN THE MATTER OF the National Energy Board Hearing Order OH-1-98.
HEARD at Calgary, Alberta, 15 and 16 April 1998.
BEFORE:
R.J. Harrison Presiding Member
J.A. Snider Member
D. Valiela Member
APPEARANCES:
G.M. Nettleton Interprovincial Pipe Line Inc.
K.F. Miller Canadian Association of Petroleum Producers
S.H. Castonguay Amoco Canada Petroleum Company Ltd.
L.G. Keough Express Pipeline Ltd.
D. Armstrong Imperial Oil Limited
P. Kahler PanCanadian Petroleum Limited
J. Ellis Shell Canada Limited
B. Netzel Alberta Department of Energy
M.A. Fowke Board Counsel
G. Delisle
(v)
<PAGE> 132
Chapter 1
INTRODUCTION
1.1 THE APPLICATION
By letter dated 2 December 1997 and as amended on 31 March 1998, Interprovincial
Pipe Line Inc. ("IPL") applied to the National Energy Board ("Board"):
(a) pursuant to section 52 of the National Energy Board Act1 ("Act"), for a
Certificate of Public Convenience and Necessity for new line pipe
facilities;
(b) pursuant to section 58 of the Act, for an order exempting all
applied-for pump unit additions, replacements and modifications and
related station facilities and piping from the provisions of sections
30, 31 and 47 of the Act;
(c) pursuant to section 21 of the Act, for an amending order varying Board
Order XO-J 1-10-98 to allow for the relocation of certain scraper trap
facilities; and
(d) pursuant to Part IV of the Act, for an order approving a toll design
methodology.
IPL' s Terrace Phase I Expansion Program ("Terrace Phase I") involves the
construction of 15 new sections of 914 millimetre ("mm") (36 inch) outside
diameter ("OD") pipeline to connect to existing 1219 mm (48 inch) OD pipe
sections to create a fifth pipeline ("Line 4") between Kerrobert, Saskatchewan
and the international border near IPL's Gretna pump station in Manitoba. The
applied-for facilities include 619 kilometres ("km") (385 miles) of pipeline, 19
pumping unit additions, 15 tie-in facilities and related station facility
equipment. Approximately 373 km (232 miles) of pipeline would be constructed
within existing IPL easements, while 246 km (153 miles) would be constructed on
new easements to be acquired adjacent to existing IPL easements.
The estimated capital cost of the Terrace Phase I facilities is $610 million.
The new line pipe is expected to be in service by 31 January 1999, while all
pumping facilities are expected to be in service by 1 September 1999. The
applied-for facilities would increase the throughput capability of the existing
IPL system by approximately 27 000 cubic metres per day ("m3 /d") (170,000
barrels per day ("b/d")).
IPL noted in its original filing that, at the request of the Canadian
Association of Petroleum Producers ("CAPP"), it would be entering into
discussions concerning the potential implementation of alternate tolling
methodologies for Terrace Phase I. In the interim, IPL requested that Terrace
Phase I be tolled on a rolled-in basis and treated as a Non-Routine Adjustment
within the meaning of paragraph 7.1 (a)(i) of the Principles of Settlement filed
in support of IPL's 1995 Incentive Toll Application, which was approved by the
Board pursuant to Order TO- 1-95.
- ------------
1 R.S.C. 1985, C.N-7.
1
<PAGE> 133
1 On 15 April 1998, IPL filed with the Board a tolling agreement (dated
14 April 1998) that it had negotiated with CAPP. IPL submitted that the tolling
agreement would result in just and reasonable tolls and that its terms should be
approved by the Board pursuant to Part IV of the Act and in accordance with the
Board's 1994 Guidelines for Negotiated Settlements of Traffic, Tolls and Tariffs
("Guidelines for Negotiated Settlements"). By letter dated 15 April 1998, the
Board sought comments on the agreement from parties to the hearing and shippers
on the IPL system. No comments were received by the Board. A copy of the
agreement is attached as Appendix II1.
1.2 ENVIRONMENTAL SCREENING
The Board conducted an environmental screening of the applied-for facilities in
compliance with the Canadian Environmental Assessment Act ("CEAA"). The Board
ensured that there was no duplication in the requirements under its regulatory
process and the CEEA.
The Board determined that, taking into account the implementation of IPL's
proposed mitigative measures and those set out in the attached conditions, the
project is not likely to cause significant adverse environmental effects. This
represents a decision pursuant to paragraph 20(1)(a) of the CEAA.
1 Please note that the text of the agreement as shown in Appendix II has
been incorporated electronically into these Reasons from a file
provided by IPL and, therefore, the Board cannot be certain that there
are no discrepancies between this text and the actual text of the
agreement. If any discrepancies exist, the Board directs readers to
refer to the original document which constitutes the official version.
2
<PAGE> 134
(MAP)
3
<PAGE> 135
Chapter 2
FACILITIES
2.1 CURRENT AND PROPOSED OPERATION
The current and proposed operation of the IPL system is illustrated graphically
in Appendix III and is briefly summarized below. Currently, much of the IPL
system between Edmonton, Alberta and Gretna operates in a "looped" manner, where
the product flow crosses over to a larger diameter pipeline upstream of each
pump station, thereby increasing the capacity of each line. At the discharge
side of each pump station, the product flows back into the "original" diameter
pipe for that line.
Under Terrace Phase I, the present looped configuration would be replaced by
straight-through operation for Lines 2, 13 and part of Line 3. This "de-looping"
would result in capacity reductions on these lines. The proposed
straight-through operation would allow the existing 1219 mm (48 inch) OD pipe
sections currently used by Line 3 to be combined with the applied-for
construction of 15 sections of 914 mm (36 inch) OD pipe to form the new Line 4.
This would result in Lines 3 and 4 being operated in a partially looped manner
between Edmonton and Kerrobert and in a straight-through manner downstream of
Kerrobert. Line 2 would originate at the Kerrobert station.
In addition, IPL proposed that the commodities be switched between Lines 2 and
3. Line 2 would operate in heavy crude service (in laminar flow), which would
have the effect of further reducing capacity on this line. Line 3 would operate
in light and medium service. The proposed Line 4 would operate in heavy crude
oil service. Table 2-1 lists the current and proposed post Terrace Phase I
commodities that would be transported in each line.
TABLE 2-1
ALLOCATION OF COMMODITY TYPES BY LINE
<TABLE>
<CAPTION>
LINE WITHOUT TERRACE PHASE I WITH TERRACE PHASE I
<S> <C> <C>
1 Natural gas liquids, Synthetics, Lube light, Natural gas liquids, Synthetics, Lube light,
Light sweet. Light sweet.
2 Light sweet, Light sour, Condensate, Heavy.
OSE, Midale, Sarnia Special, Light sour blend.
3 Heavy, Bow River, Light sweet, Light sour. Light sweet, Light sour, Condensate,
Midale, Light synthetics, Sarnia Special,
Light sour blend.
4 Not applicable. Heavy, Bow River, Light sour, Midale,
Heavy synthetics.
13 Refined products, Synthetics. Refined products, Synthetics.
</TABLE>
4
<PAGE> 136
The combination of de-looping, creation of Line 4 and switching of commodities
would result in system capacity changes as shown in Table 2-2.
TABLE 2-2
ANNUAL THROUGHPUT CAPACITIES
(103 m3/d)
<TABLE>
<CAPTION>
POST-TERRACE
LINE CURRENT PHASE I CHANGE
<S> <C> <C> <C>
1 49.5 49.5 0
13 31.0 27.8 (3.2)
2 79.5 25.0 (54.5)
3 99.1 81.2 (17.9)
4 0 102.1 102.1
TOTAL 259.1 285.6 26.5
</TABLE>
2.2 APPLIED-FOR FACILITIES
A summary of the facility additions and modifications by line number is provided
below:
- Line 1 - no changes;
- Line 2 - pump and motor additions at two stations with associated
building additions, pump and motor relocations at five stations,
and delivery and injection piping modifications at two stations;
- Line 3 - piping modifications at six Line 2 stations, and delivery
and injection piping modifications at three stations;
- Line 4 - construction of approximately 619 km of 914 mm OD pipe
sections with associated sectionalizing valves, 15 tie-in
facilities, pump unit additions at three stations (three new pumps
at each station) and required building additions, piping and unit
modifications at 15 stations, pump and motor replacements at four
stations, and delivery and injection piping modifications at two
stations.
With respect to the station facilities, IPL applied pursuant to section 58 of
the Act for an order exempting all applied-for pump unit additions, replacements
and modifications and related facilities and station piping (as detailed in
Schedule A of Appendix V) from the requirements of sections 30, 31 and 47 of the
Act.
5
<PAGE> 137
IPL also applied for an amending order pursuant to section 21 of the Act for the
relocation of previously approved1 1219 mm OD scraper trap facilities. IPL now
intends to use these facilities as part of the Terrace Phase I program. Three
receiving scraper traps will be installed as originally proposed at the
Herschel, Glenboro and Glenavon stations and the remaining three sending scraper
traps would be installed at the Loreburn, Craik and Odessa stations. In
addition, seven existing 1219 mm OD sending traps would be dismantled and stored
for future use, with the exception of one sending unit which would be relocated
and used at the Souris station.
The operation of Lines 2, 13 and part of Line 3 in a straight-through manner
would result in currently used crossover piping being taken out of service. IPL
stated during the hearing that it intends to remove essentially all of the
crossover piping and confirmed that it would file an application with the Board
for the piping removal.
With respect to river crossings, IPL submitted that it is evaluating the
feasibility of directionally drilling the South Saskatchewan, Qu'Appelle and
Souris Rivers before making a final determination of the type of crossing
methodology to be used at each of these locations. IPL stated that it would
consider geotechnical feasibility, constructability, environmental concerns and
cost constraints in order to determine the preferred crossing methodology for
each of these rivers.
IPL submitted that the design and construction of Terrace Phase I would be in
accordance with the Board's Onshore Pipeline Regulations2 and would meet or
exceed the requirements of the 1996 edition of the Canadian Standards
Association standard Z662, Oil and Gas Pipeline Systems. IPL also indicated that
the capital cost of the Terrace Phase I facilities, estimated to be $610
million, is based on a combination of estimated and actual material quotations
and historical construction costs.
VIEWS OF THE BOARD
While the Board would be concerned about the ongoing integrity of the
unused crossover piping once IPL's system is de-looped, the Board
understands that IPL will apply for the removal of this piping within a
reasonable time frame. If IPL chooses not to remove these crossovers,
it is reminded that, pursuant to subsection 53(1) of the Onshore
Pipeline Regulations, an application will be required for the
deactivation of the crossover piping if IPL proposes to deactivate the
piping for 12 months or more.
In the Board's view, directionally drilling the South Saskatchewan,
Qu'Appelle and Souris Rivers would be the preferred crossing method
from an environmental perspective. While the Board recognizes the
constraints associated with this crossing methodology, such as
geotechnical concerns and cost, it is not prepared to provide blanket
approval for IPL's proposed alternative crossing methodologies in the
absence of information on the technical feasibility of directional
drilling. Therefore, the Board will require IPL to file a report on the
feasibility of directionally drilling these rivers and obtain approval
of the Board for the crossing methodology of each river prior to
construction at each location.
- -------------
1 Board Order XO-J1-10-98.
2 SOR 89-303.
6
<PAGE> 138
The Board is satisfied that the proposed Terrace Phase I facilities are
appropriate for the purposes of the proposed service and that all
design and construction activities will meet the applicable standards
and regulatory requirements. As well, the Board considers the costs
associated with the facilities to be reasonable.
2.3 INTEGRITY
2.3.1 LINE 4 - INTERNAL INSPECTION CAPABILITY
To ensure that Line 4 would be 100 percent capable of internal inspection, IPL
had originally intended to use separate internal inspection tools for the
proposed 914 mm OD and existing 1219 mm OD pipe sections. To facilitate this,
IPL applied for the installation of scraper trap facilities at each location
where connections between the two pipeline diameters would occur. Subsequently,
IPL determined that advances in internal inspection tool technology would allow
the development of one tool to inspect line pipe of different diameters and,
therefore, modified its application to make use of previously approved scraper
trap facilities as described in Section 2.2.
2.3.2 LINE 13 - IDLE PIPE SECTIONS
During the hearing, the Board questioned IPL regarding the current status of the
406 mm (16 inch) OD mainline on Line 13 and the 610 mm (24 inch) OD loop
sections on Line 2 between Regina, Saskatchewan and Gretna. IPL submitted that,
from late 1994 to May 1997, Line 13 had operated in a parallel flow
configuration using both the 406 mm OD mainline and the 610 mm OD loops. In May
1997, Line 13 was placed in a looped operation which resulted in the 406 mm OD
pipe sections becoming idle. Between May 1997 and the present, the idle sections
have been filled with light crude oil and have been utilized to facilitate loop
swings associated with the internal inspection of adjacent pipelines. IPL
submitted that, once the Terrace Phase I facilities are in service, Line 13
would be in straight-through operation using the 406 mm OD mainline and the 610
mm OD loops would be used by Line 2 in straight-through operation. IPL also
indicated that a high-resolution internal inspection of Line 13 was conducted in
1995. Based on this inspection, Line 13 was subsequently examined and repaired,
and a follow-up internal inspection is scheduled for 2001. Additionally, Line 13
was hydrostatically tested between Regina and Cromer, Manitoba in 1993 and
between Cromer and Gretna in 1994.
2.3.3 LINE 2- LAMINAR FLOW
IPL indicated that it intends to operate Line 2 in laminar flow and that it is
aware of the potential for increased internal corrosion associated with this
slower flow rate. IPL submitted that it intends to increase its internal
inspection frequency and to utilize inhibitors to control internal corrosion.
Views of the Board
The Board understands that an internal inspection tool capable of
inspecting dual diameter pipelines of the sizes required by IPL (914
mm/1219 mm OD) does not currently exist. However, given that IPL is
presently working to develop a tool for the required pipe sizes and may
not need to internally inspect Line 4 for several years, the Board is
reasonably confident that the required inspection equipment will be
available when required.
7
<PAGE> 139
As a result of IPL's ongoing integrity management program, including
periodic in-line inspection and hydrostatic testing, the Board is of
the view that IPL has adequately addressed the potential integrity
issues associated with the idle 406 mm OD pipe sections on Line 13.
IPL agreed with the Board's understanding that the proposed laminar
flow operation of Line 2 could increase the possibility of internal
corrosion. However, the Board is of the view that the information IPL
has provided to date with respect to internal corrosion mitigation on
Line 2 is incomplete. Therefore, IPL is directed to re-evaluate its
existing Line 2 internal corrosion control program, addressing
potential corrosion issues associated with laminar flow, and to file
the results with the Board.
2.4 ALTERNATIVES TO THE PROPOSED EXPANSION
As part of its application, IPL provided an evaluation of eight alternatives for
the Terrace Phase I design, as outlined in Table 2-3.
TABLE 2-3
ALTERNATIVES TO THE PROPOSED EXPANSION
CANADIAN PIPELINE FACILITIES
<TABLE>
<CAPTION>
ALTERNATIVE REQUIRED CONFIGURATION
NO. DESCRIPTION
<S> <C> <C> <C>
1 Do nothing None N/A
2 9l4mmOD/ 744km of 914mm OD pipe Line 3 and new 9l4mm
1219 mm OD (619 km - Phase I) OD/1219 mm OD would provide
Phased light/medium and heavy capacity
3 660mmOD 1066km of 660mm OD pipe Line 3 and the new 660mm OD
Phased would provide heavy crude
capacity
4 762mm OD/ 740km of 762mm OD pipe Line 3 and new 762mm
1219 mm OD OD/1219mm OD would provide
light/medium and heavy capacity
5 6l0mm OD 1066km of 406.4mm OD pipe Line 3 and the new 6l0mm OD
Single Phase would provide heavy crude capacity
6 Extend 1219 mm 743 km of 1219 mm OD pipe No change
OD Loops on
Line 3
7 Two 508 mm OD 2138 km of 508 mm OD pipe Line 3 and the two new 508 mm
Lines OD lines would provide medium
and heavy capacity
8 1067 mm 744 km of 1219 mm OD pipe Line 3 and new 1067 mm OD/
OD/1219 mm OD 1219 mm OD line would provide
light/medium and heavy capacity
</TABLE>
8
<PAGE> 140
IPL consulted with industry representatives and conducted quantitative and
qualitative comparisons of these alternatives in order to determine the best
design solution. IPL considered the following criteria in its assessment:
- ability to meet long-term and short-term capacity demands;
- expansion capability and system flexibility;
- system reliability;
- system operability; and
- economics including the present value of capital costs, operating
costs and operating savings to both IPL and industry.
IPL selected Alternative No. 2 (914 mm OD/1219 mm OD) because it would meet the
short-, medium- and long-term needs of IPL' s operation, it represents a
flexible and reliable design, and it would result in the lowest overall cost to
the industry.
VIEWS OF THE BOARD
The Board finds a comparison of viable alternatives relevant to its
assessment of the appropriateness of a proposed design. The Board is of
the view that IPL has satisfactorily assessed the merits of each design
alternative.
2.5 ADEQUACY OF DOWNSTREAM CAPACITY
In its application, IPL noted that Lakehead Pipe Line Partners, L.P.
("Lakehead") proposes to undertake a concurrent expansion program to complement
IPL' s Terrace Phase I expansion. Approximately 155 km (97 miles) of new 914 mm
OD pipeline is planned to be in service by January 1999. Two additional tanks at
Lakehead's Superior, Wisconsin tank farm would also be constructed with a
planned in-service date of September 1999. IPL submitted that its Line 4
operations would not be affected by possible delays of the Lakehead expansion,
but that Line 2 would not be available for service until the pipeline component
of the Lakehead expansion is complete. A delay in the pipeline portion of the
Lakehead construction could potentially cause a reduction in capacity of 25 000
m3/d (157,000 b/d) of heavy crude oil. IPL also confirmed that capacity
downstream of Superior would be constrained by 36 000 m3/d (226,000 b/d) until
Lakehead's Line 14 is placed in service. Line 14 is presently under construction
and has a scheduled in-service date of December 1998.
VIEWS OF THE BOARD
The Board is satisfied that IPL is taking reasonable steps to ensure
that the required downstream facilities will be available as required.
9
<PAGE> 141
Chapter 3
ENVIRONMENT AND LAND MATTERS
3.1 ROUTE AND FACILITY SITE SELECTION
3.1.1 PIPELINE ROUTE SELECTION
Routing of the proposed pipeline was influenced by IPL' s desire to minimize,
where feasible, the number of lands newly affected and the amount of land
disturbance. Consequently, consideration was generally not given to alternative
routes and the existing pipeline right of way was chosen as the preferred route
because:
- the existing route has been in service for approximately 40 years
and is well known to all parties;
- adequate workspace is generally available along the route;
- no environmental or socio-economic constraints are encountered
along the existing right of way that cannot be effectively
mitigated or compensated;
- effects associated with a widening of an existing pipeline right of
way would be incremental, while a new route would affect additional
lands and increase the amount of land disturbance; and
- pipeline surveillance and maintenance activities can be conducted
more efficiently for pipelines located within a common right of way
than for two rights of way that are geographically separated.
Where new facilities could not be located on the existing right of way due to
width constraints, IPL proposed that the facilities be located adjacent to it.
As a result, all proposed pipe sections would be either within or adjacent to
the existing IPL right of way, with the exception of two minor deviations. The
first occurs at the South Saskatchewan River between kilometre post ("KP") 504.5
and KP 506.7. This deviation was necessary because of the locations of the
pipelines in the existing right of way. The second deviation occurs between KP
907.8 and KP 929.1. That deviation was made as a result of the presence of
highway and railway rights of way adjacent to IPL's existing right of way. This
precluded IPL from simply expanding its existing right of way. The proposed new
right of way would now abut the railway right of way.
3.1.2 PERMANENT FACILITY SITE SELECTION
Siting of new facilities was also influenced by LPL's desire to limit the amount
of new land disturbance, where practical, as well as to optimize maintenance
activities and the use of existing infrastructure (e.g., access roads, power
lines, fenced site boundaries, etc.) associated with IPL's facilities.
Consequently, new permanent facilities, including pump units, scraper traps and
valves, would be located within existing IPL lands.
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VIEWS OF THE BOARD
The Board agrees with IPL's rationale for locating the proposed
facilities and associated temporary work space either within or
adjacent to the existing IPL right of way. The general route proposed
by IPL for the new pipeline, including the two deviations, is accepted
by the Board. The Board notes that no new fee simple lands would be
acquired to accommodate the additional facilities at existing pump
stations.
3.2 LAND REQUIREMENTS AND ACQUISITION
IPL has applied for a total of 619 km of line pipe between Kerrobert and the
international border near IPL' s Gretna station. Approximately 373 km of pipe
would be constructed within IPL's existing right of way. The remaining 246 km
would be constructed in new right of way to be acquired adjacent to IPL's
existing right of way. However, two exceptions, as noted in Section 3.1.1, would
be required.
IPL indicated that temporary work space would also be required for such
activities as:
- river, highway and road crossings;
- "shoo-flies" and temporary access roads; and
- contractor yards and pipe storage and staging areas.
VIEWS OF THE BOARD
The number of permanent easements and the amount of temporary work
space required for pipeline construction is generally of concern to the
Board because of the potential effects on landowners. In the present
application, the Board finds that IPL' s anticipated requirements for
permanent easements and temporary work space are reasonable and
justified.
3.3 ENVIRONMENTAL MATTERS
The Board, pursuant to its regulatory process and the CEAA, completed an
environmental screening of the proposed construction related to Terrace Phase I.
The Board circulated the Environmental Screening Report to the applicant, those
parties who requested a copy and federal agencies that had volunteered to
provide specialist advice.
The comments received and the Board's views form Appendices I and II,
respectively, to the Environmental Screening Report. Copies of the Environmental
Screening Report are available upon request from the Board's Regulatory Support
Office.
VIEWS OF THE BOARD
The Board has considered the Environmental Screening Report and the
comments received on the report and is of the view that, taking into
account the implementation of the proposed mitigative measures and
those set out in the attached conditions (Appendices IV and V), IPL's
Terrace Phase I is not likely to cause significant adverse
environmental effects. This represents a decision pursuant to paragraph
20(1)(a) of the CEAA and Part III of the Act.
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CHAPTER 4
SUPPLY, MARKETS AND ECONOMIC MATTERS
4.1 SUPPLY
IPL's crude oil production forecast for western Canada projected that supply
would increase from 314 100 m3/d (1,980,000 b/d) in 1996 to a maximum of 410 200
m3/d (2,580,000 b/d) in 2009 and decrease in 2010 to 406 100 m3/d (2,550,000
b/d). The forecast was based on a composite of: a survey of western Canadian
crude oil producers conducted in the fall of 1996, which was followed by
extensive consultation with industry and governments; several updating
adjustments to reflect light crude oil supply trends and the markets for heavy
crude oil; and a number of more recent announcements regarding upgrading and
synthetic oil projects. Respondents to the 1996 survey were asked to base their
supply projections on a price per barrel for West Texas Intermediate ("WTI") at
Cushing, Oklahoma that increased from a low of US$17.50 in 1998 to US$22.25 in
2010 and a price differential per barrel between WTI and Bow River crude oil at
Chicago, Illinois that rose from US$3.00 in 1996 to US$7.00 by 2010.
IPL projected that the supply of conventional light crude oil would decline from
approximately 136 700 m3/d (859,800 b/d) in 1996 to 88 400 m3/d (556,000 b/d) by
2010. Over the same period, production of pentanes plus and synthetic crude oil
from mining plants was forecast to nearly double from a total of 70 000 m3/d
(440,300 b/d) to an estimated 133 100 m3/d (837,200 b/d). As a result, IPL
forecast that total production of light crude oil and equivalent would increase
slightly from 206 700 to 218 500 m3/d (1,300,000 to 1,370,000 b/d) over the
forecast period.
IPL limited the projected growth in supply of heavy crude oil as a result of its
assessment of the projected market demand for heavy crude oil. As a result, its
forecast of heavy crude oil production was lower than was indicated in its
survey of western Canadian crude oil producers. IPL estimated that heavy crude
oil production, including both bitumen and conventional heavy crude oil, would
rise from an average of 107 400 m3/d (675,500 b/d) in 1996 to a high of 188 600
m3/d (1,190,000 b/d) by 2009, and then decrease to 187 600 m3/d (1,180,000 b/d)
in 2010. Without market constraints, IPL forecast that heavy crude oil
production could potentially increase by an additional 42 400 m3/d (266,700 b/d)
by the end of the forecast period.
Express Pipeline Ltd. ("Express") questioned IPL about the effect that current
oil prices and differentials could have on IPL's production forecast. IPL agreed
that the price assumptions used in its 1996 survey were probably higher than
current prices would indicate were appropriate. In an undertaking, IPL
subsequently provided a revised crude oil price forecast with projected prices
lower for the years 1998 to 2001, but otherwise unchanged for the remainder of
the forecast period.
Express also questioned whether IPL had updated its production forecast in
response to recent industry announcements concerning the reduction in
oil-directed drilling and the deferral of heavy oil projects. IPL acknowledged
that it was aware that some companies had switched from oil-directed to
gas-directed drilling and that several of the announced heavy oil projects were
being deferred or delayed due to low crude oil prices. However, IPL noted that
it had developed its initial supply forecast with significant industry input and
that it had since reconfirmed overall supply expectations through
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<PAGE> 144
FIGURE 4-1
LPL FORECAST OF WESTERN CANADIAN CRUDE OIL PRODUCTION
[Chart]
informal surveys and extensive consultation with industry. IPL also noted that
its production forecast for heavy crude oil was lower than the supply potential
due to downstream market constraints which were reflected in the forecast. While
there may be some variability in the overall supply potential because of
pricing, IPL believed that the overall supply available from the Western Canada
Sedimentary Basin would not change appreciably.
In a letter dated 15 April 1998, CAPP confirmed that IPL had used an industry
consensus forecast. No other supply forecasts were submitted.
VIEWS OF THE BOARD
The Board recognizes the uncertainties associated with forecasts of the
supply of crude oil and equivalent and agrees with IPL that forecast
heavy crude oil supply may be limited by market constraints. The Board
notes that IPL' s initial supply forecast was developed in consultation
with industry and governments and that ongoing extensive consultation,
including consideration of the effect of lower than expected commodity
prices in the first quarter of 1998, has supported this forecast. The
forecasts of the supply of crude oil and equivalent submitted by IPL
are accepted as reasonable by the Board.
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<PAGE> 145
4.2 MARKETS
4.2.1 DEMAND
Western Canadian crude oil supplies markets in eastern and western Canada and
export markets in PADDs'1 I, II, IV and V and offshore. IPL stated that in
1996 just over half of its volumes, including natural gas liquids and refined
products, were delivered to export markets in PADDs I, II and IV, while another
one-third was delivered to eastern Canada and the remainder to markets in
western Canada.
IPL indicated that the PADD II market provides the best netbacks for western
Canadian crude oil production. Crude oil from western Canada supplies
approximately one-third of this market. In 1996, IPL delivered 125 100 m3/d
(786,800 b/d) of the 133 500 m3/d (840,000 b/d) of western Canadian crude oil
that flowed into PADD II. IPL submitted that the capacities of refineries served
by IPL in PADD II total approximately 404 800 m3/d (2,500,000 b/d). IPL also
stated that it has had confidential discussions with some of these refiners, who
indicated that future crude oil requirements would exceed their current
capacities.
Based upon the results of its 1996 survey, IPL anticipated that total PADD II
demand for western Canadian crude oil would grow to 229 500 m3/d (1,444,000 b/d)
by 2002, an increase of 96 000 m3/d (604,000 b/d) or 72 percent over 1996
levels. This increase includes refinery expansions to process heavy crude oil in
PADD II totaling up to 26 900 m3/d (173,000 b/d). Even with this increase in
heavy demand in PADD II, IPL noted that it had limited its estimate of the
growth in Canadian heavy crude oil production to anticipated demand; In IPL's
view, western Canadian crude oil supply would be sufficient to accommodate
increased demand in PADD II, including volumes that would be redirected into
PADD II as a result of the anticipated reversal of IPL's Line 9 2.
4.2.2 WESTERN CANADIAN CRUDE OIL AVAILABLE TO LPL
IPL calculated production available to its system as the difference between
western Canadian crude oil production and non-IPL disposition of western
Canadian crude oil. Production volumes were adjusted for the blending of heavy
crude oil with diluent, the addition of recycled and manufactured diluent and
the upgrading of certain heavy blend volumes to synthetic light crude oil.
Using 1999 as a reference point, IPL expected that crude oil produced in western
Canada would be distributed as follows:
- local western Canadian market (23%);
- Trans Mountain Pipe Line Company Ltd. (5%);
- ------------------
1 PADD refers to the U.S. Petroleum Administration for Defense Districts.
These are geographic aggregations of the 50 states and District of Columbia
into five districts defined by the Petroleum Administration for Defense in
1950. These districts were originally defined during World War II for the
purposes of administering oil allocation. Geographically, the five
districts are East Coast (I), Midwest (II), Gulf Coast (III). Rocky
Mountain (IV) and West Coast (V).
2 Interprovincial Pipe Line Inc.. OH-2-97, Reasons for Decision dated
December 1997.
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- Rangeland Pipe Line Company and Wascana Pipe Line Ltd.'s Milk River
pipeline (6%);
- Express (6%); and
- IPL (60%).
Express challenged IPL's estimate of non-IPL disposition. In its letter of 2
December 1997. Express asserted that IPL had underestimated throughput on the
Express system. Although it did not oppose IPL's proposed expansion, Express
argued that IPL had underestimated growth in demand for western Canadian crude
oil in markets served by Express. This growth was being created by a decline in
indigenous PADD IV supply, refinery expansions and improved access to PADDs IV
and II through pipelines connected to the Express pipeline. Moreover, Express
was concerned that IPL had understated netbacks available in PADD II via the
Express and Platte Pipeline Company ("Platte") systems, the effect of which was
to make this route appear less attractive. However, Express presented no
evidence to support its position.
In reply to Express, IPL agreed that if more volumes of western Canadian crude
oil were delivered into PADD IV via other pipelines, then supply available to
IPL would decrease. However, IPL stated that it had considered and rejected
Express' input. IPL had prepared its forecast in consultation with industry,
including shippers on Express. In IPL's view, it had not understated the volumes
that would move to PADD IV.
The forecast of the crude oil production available to IPL is summarized in Table
4-1 below.
TABLE 4-1
FORECAST OF WESTERN CANADIAN CRUDE OIL PRODUCTION AVAILABLE TO IPL
(l0 3 m3/d)
<TABLE>
<CAPTION>
1996 2000 2005 2010
<S> <C> <C> <C> <C>
Western Canada Production* 334.2 389.2 441.5 441.1
Non-IPL Demand
Western Canada 88.4 102.9 111.6 113.8
Exports
- PADD IV** 21.1 38.8 34.9 31.3
- PADD V 17.5 7.7 7.8 5.0
Total Non-IPL Demand 127.0 149.4 154.3 150.1
Net Production Available to IPL 207.2 239.8 287.2 291.0
Other IPL Receipts 56.8 106.9 113.0 116.7
TOTAL SUPPLY AVAILABLE TO IPL 264.0 346.7 400.2 407.7
</TABLE>
* Adjusted for blending of heavy crude oil, addition of recycled and
manufactured diluent and upgrading of certain heavy blend volumes
** Includes volumes transferred onto the Platte system for delivery into
PADD II.
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4.2.3 THROUGHPUT
IPL prepared forecasts of its system throughput for the years 1999 to 2010, both
with and without the Terrace Phase I expansion. Without the expansion, IPL
expected apportionment to continue for the entire period. However, with the
expansion, it is expected that apportionment would not occur between September
1999 and late 2002. In the period 1999 to 2002, IPL forecast system throughput
to be 332 900 to 360 500 m3/d (2,100,000 to 2,270,000 b/d), versus 329 000 to
322 700 m3/d (2,070,000 to 2,030,000 b/d) without the expansion. With the
expansion, the system is expected to be at capacity after 2002 and the
additional volumes would flow primarily to PADD II.
VIEWS OF THE BOARD
The Board agrees with IPL that PADD II could absorb the forecast
additional volumes of western Canadian crude oil and accepts IPL' s
evidence concerning available refinery capacity in the market and the
ability of these refiners to process additional heavy crude oil.
Although Express challenged IPL' s forecasts, it provided no evidence
to support its view. The Board notes that IPL reduced its supply
forecast for western Canadian crude oil to accord with its assessment
of the markets available for that crude. If a larger market develops
via the Express system, the Board is satisfied that additional supply
would be available to satisfy that demand with IPL's proposed expansion
in place.
The Board recognizes that the IPL system is currently under
apportionment and that it may remain so even after the SEP II(1)
facilities are in service. Further, the Board notes the extensive
consultation undertaken by IPL and the broad support of industry for
this expansion. On balance, the Board is satisfied that IPL has
provided reasonable forecasts of markets, disposition and throughput.
4.3 ECONOMIC FEASIBILITY
In its application, IPL measured the economic impact of the proposed expansion
by calculating the projected increase in total producer revenue, or the
projected increase in cash flow that would result due to additional volumes of
crude oil reaching market via the IPL pipeline system.
For the years 2000 to 2010, the projected deliveries of crude oil through
western Canadian pipeline systems were compared with the level of deliveries
through those systems assuming that the Terrace Phase I facilities would be
constructed. Transportation costs and resultant netbacks at Edmonton for each of
the markets to which western Canadian crude oil is forecast to move from 2000 to
2010 were also considered. IPL's presentation of illustrative netbacks at
Edmonton for 1997 from each of the markets that process western Canadian crude
oil indicated that its system generally provides western Canadian crude oil
producers with the highest netbacks, particularly with its connection to the
PADD II market.
- ------------------
(1) In OH-l-96, the Board approved IPL's System Expansion Program Phase II to
increase delivery capability of the existing IPL system in western Canada by
19 600 m3/d (120,000 b/d).
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With the expansion facilities, IPL calculated that producer sector revenues over
the 2000 to 2010 period are expected to increase by $5.6 billion on a net
present value basis versus the without expansion facilities case.
Express referred to IPL evidence and argued that heavy crude oil delivered via
the Platte system to the southern PADD II market would provide a somewhat more
attractive netback than an IPL delivery of heavy crude oil at Wood River.
According to IPL, Chicago is expected to remain the most attractive netback
market for western Canadian crude oil producers.
4.3.1 SUPPORT FOR PROJECT
CAPP supported the project and an accelerated timetable for obtaining regulatory
approval. At the start of the hearing, IPL filed a toll agreement negotiated
with CAPP whereby IPL's shippers have guaranteed IPL the recovery of the costs
of the expansion over a 15-year period from 1999 to 2013 (see Chapter 5 for
further details).
Further letters of support were provided by the governments of Manitoba and
Saskatchewan, which particularly welcomed the positive economic benefits for
their provinces.
VIEWS OF THE BOARD
The evidence indicates that industry and provincial governments are
strongly supportive of the proposed expansion. In the Board's view,
some of the benefits of this expansion would include the production of
crude oil that would otherwise be shut in or sold to less attractive
markets due to apportionment on IPL, as well as a potential improvement
in the competitive position of western Canadian crude oil deliveries in
PADD II as a result of increased reliability of these deliveries. The
Board finds that the benefits of the IPL expansion are likely to be
sufficient to justify the construction of the proposed facilities.
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CHAPTER 5
TOLLS AND FINANCIAL MATTERS
In its application, IPL sought approval to have the capital and operating costs
of Terrace Phase I treated as a Non-Routine Adjustment in accordance with
paragraph 7.l(a)(i) of the Principles of Settlement filed in support of IPL's
February 1995 Incentive Toll Application, approved by Board Order TO-l-95, and
to have such costs recovered through tolls using an integrated toll design. IPL
also indicated that it had been approached by CAPP to discuss the possibility of
reaching a negotiated tolling agreement relating to the total Terrace Expansion
Program facilities. On 15 April 1998, IPL filed with the Board a tolling
agreement which had been ratified by CAPP members. A copy of the agreement is
attached as Appendix II.
Upon filing the tolling agreement, IPL withdrew that portion of its application
respecting the treatment of Terrace Phase I as a Non-Routine Adjustment.
A brief summary of the negotiated agreement is set out below.
- IPL and its affiliated company, Lakehead, would collect a fixed
toll increment of a combined 5 cents (Canadian) per barrel that
would recover costs for all phases of the Terrace Expansion
Program.
- The 5 cent increment is based on the shipment of light crude oil
from Edmonton to Chicago and tolls would continue to be distance
based and subject to toll surcharges or credits for different
commodity movements.
- The fixed toll increment would apply to all IPL/Lakehead base
volumes and the Terrace incremental volume for a period commencing
with the in-service date of Terrace Phase I and ending 31 December
2013.
- There would be a sharing of risks and benefits between IPL and its
shippers.
IPL submitted that the toll arrangement would result in just and reasonable
tolls and that its terms should be approved by the Board pursuant to Part IV of
the Act and in conjunction with the Board's Guidelines for Negotiated
Settlements.
On 15 April 1998, the Board issued a letter soliciting comments from parties to
the hearing and shippers on the IPL system. No comments were received by the
Board.
VIEWS OF THE BOARD
The Board notes that the negotiated tolling agreement has broad shipper
support. The Board considers the agreement to be a negotiated
settlement within the meaning of its Guidelines for Negotiated
Settlements. The Board is of the view that the settlement represented
by the agreement will result in just and reasonable tolls. The terms of
the agreement are therefore approved.
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Chapter 6
DISPOSITION
The foregoing constitutes our Reasons for Decision in respect of the
applications heard by the Board in the OH- 1-98 proceeding. The Board is
satisfied from the evidence that the applied-for facilities are and will be
required by the present and future public convenience and necessity.
The Board approves IPL's application made pursuant to section 52 of the Act for
new line pipe facilities and will recommend to the Governor in Council that a
certificate be issued, subject to the conditions set out in Appendix IV.
The Board approves IPL's application made pursuant to section 58 of the Act
exempting all applied-for pump unit additions, replacements and modifications
and related station facilities and piping from the provisions of sections 30, 31
and 47 of the Act. Accordingly, the Board has issued Order XO-J1-16-98, as shown
in Appendix V.
The Board approves IPL's application made pursuant to section 21 of the Act
varying Board Order XO-J 1-10-98 to allow for the relocation of certain scraper
trap facilities to new locations as described in the application. Accordingly,
the Board has issued Amending Order AO-1-XO-J1- 10-98, as shown in Appendix VI.
With respect to Part IV matters, the Board approves IPL's toll arrangement.
/s/ R.J. Harrison
-----------------------------------------
R.J. Harrison
Presiding Member
/s/ Judith A. Snider
-----------------------------------------
J.A. Snider
Member
/s/ D. Valiela
-----------------------------------------
D. Valiela
Member
Calgary, Alberta
June 1998
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APPENDIX I
LIST OF ISSUES
1. The need for the expansion.
2. The economic feasibility of the proposed facilities.
3. The impact on market and supply.
4. The potential impact on existing shippers.
5. The appropriateness of the proposed method of financing the project.
6. The potentially adverse environmental and socio-economic effects of the
proposed facilities, including those factors outlined in section 16(1)
of the Canadian Environmental Assessment Act.
7. The safety of the design and operation of the proposed facilities.
8. The appropriate design and size of the applied-for facilities having regard
to:
(a) the costs of the facilities in relation to the additional capacity to
be provided; and
(b) the need for new capacity to transport oil and other liquid
hydrocarbons.
9. The adequacy of connecting pipeline capacity to accommodate the project.
10. The appropriateness of the general route proposed.
11. The appropriate terms and conditions to be included in any approval which
may be granted.
12. The determination of the appropriate toll treatment for the applied-for
facilities.
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APPENDIX II
TERRACE TOLL AGREEMENT1
STATEMENT OF PRINCIPLES
1. Negotiated tolls for the IPL/LPL Terrace program will recover costs
associated with all facilities associated with all phases of Terrace
Expansion Program. The Terrace Expansion Program is expected to be a
phased capacity addition program intended to add capacity in the years
1999 and following.
2. The Terrace facilities, the expected capacity increases associated with
the facilities, and the in-service timing are appended as Schedule A.
IPL and LPL commit to deliver the additional throughput capacity on or
before the dates set out in these Principles. The dates upon which the
facilities are expected to come into service are:
i) January 15, 1999 first in-service of Phase I facilities,
providing 95,000 bpd of incremental capacity from a base
system capacity (which includes SEP II and SEP III 350
Centistoke facilities) of 1,630,503 bpd (259,100 m3). The
incremental capacity to be provided includes incremental heavy
crude oil capacity on Line 3 (24 inch).
ii) September 30, 1999 second tranche of Phase I capacity
in-service, totaling 167,000 bpd of incremental capacity from
the base.
iii) Hardisty to Kerrobert extension IN service September 30, 2000
[Phase II] providing 210,000 bpd of incremental capacity from
the base
iv) Clearbrook to Superior extension and associated pumping in
service September 30, 2001 [Phase III] providing 348,000 bpd
of incremental capacity from the base
v) Mokena to Griffith extension, Line 14 stations in service,
Line 14 heater in service between 2002 and 2007 [later Terrace
phase(s)]
3. The in service commitments made by IPL/LPL are subject to CAPP
providing written notice to IPL/LPL requesting construction in advance
of the proposed in-service dates. The notice periods in respect of
Phase II, III and later Terrace Phases described above are 18 months,
24 months and 36 months respectively; provided that notice given prior
to March 31, 1999 in respect of Phase II may be deemed by IPL/LPL to
have been given on March 31, 1999. Upon IPL giving notice to CAPP of a
requirement by IPL/LPL to undertake material commitments in order to
meet in-service dates, CAPP will confirm its continuing service request
prior to IPL/LPL being required to make those commitments.
4. For the purpose of determining "in service" the date which shall be
used for IPL is the date upon which the last leave to open order is
granted by the National Energy Board for the completion of pipeline
facilities in Phase I (excluding pump stations) and for LPL, the
availability of the facilities for service.
- ------------------------------
1 Please note that the text of the agreement as shown in Appendix II of
these Reasons is not an official version of the agreement.
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5. The delivery by IPL/LPL of the capacities associated with Phase I is
subject to shipper approval for commingling crude in Line 3 (24 inch)
to be transported in laminar flow.
6. Cost recovery on the Terrace investment and related operating costs
will be effected by application of a fixed toll increment applicable to
all base (259,100 m3) and Terrace volume transported on the IPL/LPL
systems.
7. The toll increment shall be five cents (Cdn) per barrel for light crude
transportation from Edmonton to Chicago, and shall be adjusted on a
distance basis and for commodity credits or surcharges, consistent with
IPL and LPL's then existing toll design.
8. The fixed toll increment charge will become effective upon the
in-service of the first of the Terrace facilities, as "in service" is
defined in paragraph 4, and shall terminate December 31, 2013.
9. The fixed toll increment shall be allocated between IPL and LPL as
determined by IPL and LPL, provided that no less than one cent shall
ever be allocated to either of the IPL or LPL system.
10. The fixed toll increment shall be subject to a transportation revenue
variance (TRV) in IPL which operates in the same fashion as the
then-existing TRV in IPL. In the event there is no TRV mechanism in
place for IPL, the fixed toll increment shall be subject to a TRV which
operates in the same fashion as the TRV operated in IPL in 1997.
11. The base toll upon which the fixed increment will be added assumes the
filling of the IPL/LPL systems at the quoted SEP II capacity of
1,630,503 bpd (259,100 m3/day).
12. IPL and LPL will assume one hundred percent of operating cost variance
risk, excluding changes to property tax expense which exceeds the
forecast by twenty percent or more. Property tax variances exceeding
twenty percent from forecast shall result in an increase to the fixed
toll increment in accordance with Schedule B.
13. IPL and LPL will assume five percent of the capital cost variance risk
and fifty percent of the capital cost variance risk thereafter on
quoted target costs set out below. Target costs for the purpose of
capital cost variance for facilities to be constructed after 1999 will
be inflated from December 31, 1997 using the Canadian and US GDP
deflators for facilities in IPL and LPL respectively.
IPL LPL
Cdn $ US$
$575 mm $117 mm Jan. 1999
Phase I
$35 mm $17 mm Sept. 1999
Phase I
$227mm $178mm Phases II & III
2000 and 2001
$70 mm Other Phases
2002-2007
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14. In the event CAPP does not provide notice to IPL on or before July 1,
2001 requesting IPL/LPL to proceed with both Phases II and III, costs
for the project, including revenue variance between the application of
the fixed toll increment and the cost of service model, will be
calculated, and prospective tolls will be collected on a cost of
service basis. Capital and operating cost sharing risk will revert to
the traditional cost of service recovery.
15. Until such time as both Phases II and III are placed into service,
Phase I will be considered to be a Non Routine Adjustment (NRA) in both
IPL and LPL as NRA is defined and treated in the 1995 IPL Incentive
Toll Settlement. However, tolls will continued to be charged at the
five cent negotiated rate subject to the TRV in IPL. Any revenue
variance will be amortized and collected over the remaining term of the
Principles (effective January 1, 2002) if Phases II and III are not
committed to by July 1, 2001.
16. If quoted forecast capacities are not achieved and sustained in the
long term, for so long as a capacity shortfall exists, a refund of one
cent per bbl for each 35,000 bbl capacity shortfall shall be effected
through a reduction to the subsequent year's tolls. IPL/LPL shall not
be obligated to provide a refund in respect of any capacity shortfall
for which no volume is available to be nominated to and shipped on the
IPL/LPL systems.
17. The fixed toll increment of five cents shall be adjusted upward or
downward as the case may be in accordance with Schedule B for the
following:
i) Agreed upon scope changes to the project;
ii) Agreed upon timing changes to the project;
iii) Capital cost variance;
iv) Construction cost variance due to agreed upon circumstances
which are extraordinary and not within the control of IPL/LPL;
v) Property tax variances in excess of twenty percent from forecast;
vi) In respect of Phases other than Phase I, bond rate variation
by more than two percentage points from 1998 levels; and
vii) Multi-pipeline return on equity variation by more than two
percentage points from 1998 level.
18. Subsequent to LPL completing Phase III, in the event annual actual
average pumpings ex-Clearbrook are less than 215,000m3, 220,000m3 and
225,000m3 from in-service to year-end 2002, 2003, and 2004 through 2013
inclusive, respectively, an adjustment to the fixed toll increment
shall be made in accordance with Schedule C.
19. Energy costs attributable to Terrace will be calculated using a base
power cost for an agreed upon delivery forecast assuming pre-Terrace at
a capacity of 259,100 m3/day. The calculation of the power allowance
for the purpose of calculating the TRV will be based on the difference
in the total forecast fuel and power requirements and the actual fuel
and power, using the
23
<PAGE> 155
average annual cost of fuel and power for the TRV year. IPL and CAPP
are completing a schedule which will set out in detail the elements of
the energy calculation.
20. The implementation of the toll method contemplated in these Principles
is subject to IPL and LPL Board approval and National Energy Board and
Federal Energy Regulatory Energy Commission approval of the settlement
for IPL and LPL respectively.
20. The implementation of the toll method contemplated in these Principles
is subject to IPL and LPL Board approval.
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<PAGE> 156
SCHEDULE A
DESCRIPTION OF TERRACE FACILITIES
PHASE 1 FACILITIES
<TABLE>
<CAPTION>
PROPOSED FACILITIES ITEMS CONSIDERED TO BE SCOPE CHANGES TO NOT IN TERRACE SCOPE
TERRACE
<S> <C> <C>
Pipe
- - 619 km of 914 mm line pipe between - Changes totalling more than 5 miles
Kerrobert and Gretna stations in Canada of pipe between Canada and the USA
along with associated valving, - Changes in pipe diameter
tie-in piping and scraper facilities.
- - 100 miles of 36 inch pipe line in 4
sections between Gretna and Clearbrook
stations in the USA along with associated
valving and tie-in piping.
Pump Stations
Additional pumping power or DRA to Capacity increases on Lines not
- - Sufficient pumping Achieve capacities greater than the quoted affected by Terrace including in
equipment and power to annual capacities in the NEB application in Western Canada:
provide 26,500 m3/d of Terrace Phase 1 i.e.
incremental capacity - Line 13 27,800 m3/day
assuming that - Line 1, 49,500 m3/day
Capacity increases on - Line 2A, 66,000 m3/day - Changes resulting from the
Lines not - Line 2B, 81.200 m3/day SEP II facilities as filed with
Line 3 operates in - Line 3 24" heavy line, 25,000 m3/day the NEB and as agreed to with
laminar flow and that - Line 4 36"/48" heavy line, industry which impact quoted Line
Hardisty crudes are 102,100 m3/day capacities.
pumped in Line 3 in
sufficient quantities to Changes in deliveries that negatively impact - Changes in facilities
operate at 25,000 m3/d at Lakehead's ability to inject crude into required to accommodate crude
its bottleneck point. Lines 2 and 4 at Clearbrook in Phase I characteristics other than
referenced in Table 3.10.1 in
</TABLE>
OH-1-98 25
<PAGE> 157
Breakout and Terminalling Facilities
<TABLE>
<CAPTION>
<S> <C> <C>
- 2 breakout tanks at Superior - Additional - Additional tankage, receipt, delivery,
breakout tankage terminalling or connecting facilities at any
location in Canada or USA
- Requested commodity segregation which
results in additional tankage, metering, or
terminalling facilities
- Changes, in facilities required to accommodate
crude characteristics other than referred
in Appendix 3.10 in the NEB application
</TABLE>
26
<PAGE> 158
PHASE 2 FACILITIES
<TABLE>
<CAPTION>
PROPOSED FACILITIES ITEMS CONSIDERED TO BE SCOPE CHANGES TO TERRACE NOT IN TERRACE SCOPE
<S> <C> <C>
Pipe Changes totalling more than 5 miles of pipe
123 km of 914 mm line
pipe in 3 sections Changes in pipe diameter
between Hardisty and
Kerrobert pump stations
with associated valving
and tie-in facilities
- ------------------------------------------------------------------------------------------------------------------------------------
Pump Stations
Sufficient pumping equipment Additional pumping power or DRA to achieve - Additional pumping
and power to quoted annual capacities greater than the quoted annual power or DRA to achieve
power or DRA to provide 6,900 capacities in the NEB application in Terrace capacities greater than
m3/d of incremental capacity Phase 1 i.e. that quoted in Phase 1
beyond Phase I facilities, facilities:
assuming that Line 3 operates - Changes in
in laminar flow and that - Line 1 49,500 m3/day facilities required to
Hardistry crudes are pumped in accommodate crude
Line 3 in sufficient - Line 2A 66,000 m3/day characteristics other
quantities to operate at than referenced in
27,000 m3/day its bottleneck - Line 2B 81,200 m3/day Appendix 3.10 in the
point. NEB application
- Line 3 24" heavy line m3/day 27,000 - Changes in
facilities required to
- Line 4 36"/48" heavy line 107,000 m3/day accommodate crude
characteristics other
than referenced in
Table 3.10.1 in the NEB
application.
- ------------------------------------------------------------------------------------------------------------------------------------
Breakout and Terminalling
Facilities - breakout tankage - additional tankage,
receipt, delivery,
terminalling or
connecting facilities
at any location in
Canada or USA
- Requested commodity segregation
which results in additional tankage,
metering, or terminalling facilities.
</TABLE>
27
<PAGE> 159
PHASE 3 FACILITIES
<TABLE>
<CAPTION>
- -------------------------------------------------------------------------------------------------------------------------------
PROPOSED FACILITIES ITEMS CONSIDERED TO BE NOT IN TERRACE SCOPE
SCOPE CHANGES TO TERRACE
<S> <C> <C>
- -------------------------------------------------------------------------------------------------------------------------------
Pipe
120 miles of 36 inch line Changes totalling more than
pipe in 5 sections between 5 miles of pipe
Clearbrook and Superior pump
stations with Changes in pipe diameter
associated valving and tie-in
facilities
- -------------------------------------------------------------------------------------------------------------------------------
Pump Stations
Sufficient power to provide Facility changes on Line 14 that Additional pumping power or DRA to
23,500 m3/d of incremental exceed $US 70 MM and achieve capacities greater than:
capacity above Terrace Phase II Are other than the following items:
facilities.
- Pump unit and station additions - Line 1 41,400 m3/day
- Pump unit replacements or - Line 2A 54,000 m3/day
modifications - Line 2B 65,000 m3/day
- Crude oil heaters - Line 3 heavy line 74,000 m3/day
- Pipeline connections or - Line 4 heavy line 107,800 m3/day
extensions to Griffith. - Line 13 27,800 m3/day
Changes in facilities required to accommodate
crude characteristics other than referenced
in Appendix 3.10 in the NEB application
- -------------------------------------------------------------------------------------------------------------------------------
Breakout and Terminalling
Facilities
- - 2 breakout tanks at - additional breakout tankage - additional tankage, receipt,
Superior delivery, terminalling or connecting
facilities at any location in Canada
or USA
- Requested commodity segregation which results in
additional tankage, metering, or terminalling
facilities Requested commodity segregation
which results in additional tankage, metering
or terminalling facilities
- -------------------------------------------------------------------------------------------------------------------------------
</TABLE>
28
<PAGE> 160
FUTURE PHASES OF TERRACE FACILITIES
<TABLE>
<CAPTION>
PROPOSED FACILITIES ITEMS CONSIDERED TO BE SCOPE NOT IN TERRACE SCOPE
CHANGES TO TERRACE
<S> <C> <C>
- ----------------------------------------------------------------------------------------------------------------------------------
Pipe
$US 27 million in pipeline - Any additional pipeline
facilities between Mokena and extensions or connections
Griffith by the end of 2002 if
needed
- ----------------------------------------------------------------------------------------------------------------------------------
Pump Stations
$US 40 million in station - Any incremental pump unit
additions and modifications on additions after the intermediate
Line 14 by the end of stations are installed
2003 if needed
- ----------------------------------------------------------------------------------------------------------------------------------
Crude Oil Heater
$US 3 MM in heating facilities - Any other heating facilities
to increase Line 14 capacity by
the end of 2007 if needed
</TABLE>
29
<PAGE> 161
SCHEDULE B
ADJUSTMENTS TO THE 5 CENTS PER BARREL INCREMENT
(CDN DOLLARS)
<TABLE>
<CAPTION>
- ------- -------------------------------- ------ --------------------------------------------------------------------------
ADJUSTING EVENT ADJUSTMENT
- ------- -------------------------------- ------ --------------------------------------------------------------------------
PHASE I PHASE II
- ------- -------------------------------- ------ ---------------------------------- ---------------------------------------
<C> <C> <C>
1 Scope Changes resulting 0.18 cents per barrel per $10 0.14 cents per barrel per $10
in Capital cost changes million change in capital costs million change in capital costs
greater than +/- $10
million from original
estimate provided in
Schedule A
- ------- -------------------------------- ------ ---------------------------------- ---------------------------------------
2 Capital Cost Variance 0.09 cents per barrel per $10 0.07 cents per barrel per $10
outside +/- 5 % of million change in capital costs million change in capital costs
estimate provided in
Schedule A
- ------- -------------------------------- ------ ---------------------------------- ---------------------------------------
3 Increases in Multi- For 1999-2007 and for 2008-2013 .3 cents per barrel and .15 cents
pipeline cost of equity beyond per barrel respectively for each 25 basis point change in the multi-
current rate plus pipeline rate of return which exceeds the 1998 multi-pipeline rate of
200 basis points return plus or minus 200 basis points.
- ------- -------------------------------- ------ ---------------------------------- ---------------------------------------
4 Increases in Cost of Debt For Phases II and following, .1 cent per barrel change for every
over 200 basis points 50 basis point change in debt cost above the 200 basis point
above current Long increase. The toll change for debt cost increases shall apply to IPL
Canada (5.28%) and US and LPL independently.
(5.65%) 10 year bonds
- ------- -------------------------------- ------ ---------------------------------- ---------------------------------------
5 Property Tax Increases .2 cents per barrel for each $ 1 million change in property tax
on Terrace Facilities greater than 20%
greater than +/-20 on
estimate
- ------- -------------------------------- ------ ---------------------------------- ---------------------------------------
6 Capacity Penalty 1 cent decrease per barrel per 1 cent decrease per barrel per 35,000
35,000 barrels per day below barrels per day below stated capacity
stated capacity until capacity is until capacity is provided
provided
- ------- -------------------------------- ------ ---------------------------------- ---------------------------------------
</TABLE>
*the values in items 3, 4 and 5 are subject to finalization
30
<PAGE> 162
SCHEDULE C
ADJUSTMENT FOR LPL PHASE III TRIGGER
INCREMENT INCREASE IN YEAR FOLLOWING PUMPINGS BELOW SPECIFIED TARGET
(CDN CURRENCY)
<TABLE>
<CAPTION>
PRIOR YEAR'S ACTUAL AVERAGE TOLL ADJUSTMENT FOR YEAR
PUMPINGS EX- CLEARBROOK
2002 2003 2004-2013
<S> <C> <C> <C>
Greater than 225,000 m3/day 0 cents/barrel 0 cents/barrel 0 cents/barrel
220 000 m3/day to 224 999 m3/day 0 cents/barrel 0 cents/barrel 1 cents/barrel
215 000 m3/day to 219 999 m3/day 0 cents/barrel 1 cents/barrel 2 cents/barrel
210 000 m3/day to 214 999 m3/day 1 cents/barrel 2 cents/barrel 3 cents/barrel
205 000 m3/day to 209 000 m3/day 2 cents/barrel 3 cents/barrel 4 cents/barrel
200 000 m3/day to 204,999 m3/day 3 cents/barrel 4 cents/barrel 5 cents/barrel
</TABLE>
31
<PAGE> 163
Appendix III
IPL'S SYSTEM OPERATION
[Graph]
32
<PAGE> 164
Appendix IV
CERTIFICATE CONDITIONS
General
1. Unless the Board otherwise directs, IPL shall implement or cause to be
implemented all of the policies, practices, recommendations and
procedures for the protection of the environment included in or
referred to in its application, in its undertakings made to other
regulatory agencies or as otherwise adduced in evidence through the
application process.
2. Unless the Board otherwise directs, IPL shall cause the approved
facilities to be designed, manufactured, located, constructed and
installed in accordance with those specifications, drawings and other
information or data set forth in its application or as otherwise
adduced in evidence before the Board.
Prior to the Commencement of Construction
3. Unless the Board otherwise directs, the company shall file, at least 14
days prior to the commencement of construction, a detailed construction
schedule or schedules identifying major construction activities and
shall notify the Board of any substantive modifications to the schedule
or schedules as they occur.
4. Unless the Board otherwise directs, the company shall, at least 14 days
prior to the commencement of construction, file with the Board for
approval the company's field joining program.
5. Unless the Board otherwise directs, IPL shall file with the Board a
report on the feasibility of directionally drilling the South
Saskatchewan, Qu'Appelle and Souris Rivers and obtain approval of the
Board for the crossing methodology at each of these rivers at least 14
days prior to construction at each location.
6. Unless the Board otherwise directs, IPL shall, at least 14 days prior
to the commencement of construction of the pipeline crossings of Eagle
Creek (KP 393.8 and KP 425.9), South Saskatchewan River (KP 505.2),
Qu'Appelle River (KP 657.0), High Hill Creek (KP 667.0), Cottonwood
Creek (KP 679.5), Wascana Creek (KP 689.5), Chapleau Lakes (KP 783.3),
Little Pipestone Creek (KP 907.0), Black Creek (KP 1065.8), Souris
River (KP 1073.5), Spring Brook (KP 1078.4 and KP 1079.0), Oak Creek
(KP 1109.3 and KP 1110.3), Cypress River (KP 1120.1 and KP 1131.6),
Mary Jane Creek (KP 1164.0), Thornhill Coulee (KP 1186.3) and
Deadhorse Creek (KP 1196.8):
(a) file the fish and fish habitat assessment and any new
mitigative measures IPL would implement resulting from the
assessment;
(b) file the assessment of the environmental impact on fish
habitat and resources at the crossing site and downstream
referred to in (a) shall include, without limitation, the
following:
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<PAGE> 165
(i) the distribution of salmonids;
(ii) the presence of salmonids in a tributary;
(iii) the presence of a spawning ground within
100 m of a watercourse crossing;
(iv) the presence of a spawning ground for warm
water species within 100 m of a
watercourse crossing;
(v) the presence of an endangered or threatened
species;
(vi) the presence of a spawning migration;
(vii) a sensitive spawning and nursery habitat
downstream; and
(viii) the risk of sediment transport;
(c) in respect to those watercourse crossings which have been
found to be sensitive, as a result of the assessment in (b)
above:
(i) the exact location and area of spawning
grounds found within 100 m of the
watercourse crossing;
(ii) the percentage of the spawning grounds that
would be affected by construction;
(iii) the species spawning at these sites;
(iv) the exact dates of construction;
(v) a detailed description of the construction
method to be used;
(vi) sedimentation control plans;
(vii) estimates of the habitat loss
and/or diminished productivity; and
(viii) development of a follow-up program on the
productivity, of the spawning grounds
after construction;
(ix) site-specific mitigative and restorative
measures to be employed as a result of
undertakings to regulatory agencies;
(x) evidence to demonstrate that all issues
raised by regulatory agencies have been
satisfactorily resolved, as well as updated
environmental assessments for those areas
where deficiencies were noted; and
(xi) status of authorizations, including the
wording of the environmental
conditions;
(d) provide copies to the Board of all correspondence from
Saskatchewan Environment and Resource Management, Manitoba
Natural Resources and the Department of Fisheries and Oceans -
Habitat Management Division ("DFO-HMD") regarding the
acceptability of the fishery resource assessment referred to
in paragraph (a); and
(e) provide a description of the watercourses where DFO-HMD has
required authorization pursuant to the Fisheries Act and
confirmation that those authorizations have been obtained.
7. IPL shall, prior to the commencement of construction within the wetted
perimeter of any watercourse deemed to be navigable pursuant to the
Navigable Waters Protection Ac:, provide:
(a) confirmation that the appropriate permits have been obtained
from the Canadian Coast Guard's Regional Offices; and
34
<PAGE> 166
(b) a description of any additional procedures or measures that
the Canadian Coast Guard has required IPL to implement at the
watercourse crossings.
8. Unless the Board otherwise directs, IPL shall, at least 5 days prior to
commencement of construction, file with the Board:
(a) copies of the preconstruction archaeology surveys conducted at
the 15 pipeline loop sections between IPL's pump station at
Kerrobert, Saskatchewan and the international border near its
pump station at Gretna, Manitoba; and
(b) copies of all correspondence from the provincial
archaeological authorities regarding the acceptability of the
archaeological surveys referred to in paragraph (a).
DURING CONSTRUCTION
9. Unless the Board otherwise directs, should there be a requirement to
remove excess bedrock by blasting at any work site, IPL shall:
(a) prior to the commencement of construction conduct a survey of
the location of all water wells within 100 m of the proposed
blasting location and sample the well water for quality,
quantity and any additional parameters requested by the
provincial regulatory body;
(b) during blasting and rock removal operations, monitor the
quality and quantity of the water in the water wells surveyed
pursuant to paragraph (a);
(c) if water quality or quantity is affected by blasting
operations, provide each resident utilizing the affected well
with a clear, potable water source in comparable quantity to
the original source until the water in the affected well
returns to its original conditions; and
(d) after construction, conduct a survey of the water wells
surveyed pursuant to paragraph (a) to ensure that there has
been no change to the quality and quantity of the water in the
wells and report the results of those surveys to the Board.
Post Construction
10. IPL shall, prior to the commencement of hydrostatic testing of the
Terrace Phase I Expansion Program facilities, provide confirmation that
all necessary or required regulatory approvals have been obtained and
local municipalities have been consulted.
11. IPL shall, prior to the Terrace Phase I facilities being placed in
service, file with the Board updated copies of:
(a) the company's operations and maintenance manual; and
(b) the company's emergency procedures.
35
<PAGE> 167
12. IPL shall file with the Board, prior to the Terrace Phase I facilities
being placed in service, a report on the re-evaluation of its existing
Line 2 internal corrosion control program, specifically addressing
potential corrosion issues associated with laminar flow.
13. LPL shall, pursuant to section 58 of the Onshore Pipeline Regulations
("OPR"), file with the Board a post-construction environmental report
within six months of the date that the 619 km (385 miles) of 914 runt
(36 inch) outside diameter pipe segments connecting the existing 1219
mm (48 inch) outside diameter pipeline segments are placed in service.
The postconstruction environmental report shall set out the
environmental issues that have arisen up to the date on which the
report is filed and shall:
(a) indicate the issues resolved and those unresolved; and
(b) describe the measures IPL proposes to take in respect of the
unresolved issues.
14. IPL shall, pursuant to section 58 of the OPR, file with the Board, on
or before the 31 December following each of the first two complete
growing seasons after the post-construction environment report referred
to in condition 13 has been filed, a report containing:
(a) a list of the environmental issues indicated as unresolved in
the previous post-construction report and any that have arisen
since that report was filed; and
(b) a description of the measures IPL proposes to take in respect
of any unresolved environmental issues.
15. Unless the Board otherwise directs prior to 31 December 1999, this
certificate shall expire on 31 December 1999 unless construction and
installation with respect to the applied-for facilities has commenced
by that date.
36
<PAGE> 168
Appendix V
ORDER XO-J1-16-98
IN THE MATTER OF THE National Energy Board Act ("the
Act") and the regulations made thereunder; and
IN THE MATTER OF an application, pursuant to section
58 of the Act, by Interprovincial Pipe Line Inc.
("IPL") filed with the Board under File No. 3200-J001-5.
BEFORE the Board on 2 June 1998.
WHEREAS the Board has received IPL's Terrace Phase I Expansion Program
application, dated 2 December 1997 and as amended on 31 March 1998, at an
estimated total cost of $610 million;
AND WHEREAS in its Terrace Phase I Expansion Program application, IPL applied
pursuant to section 58 of the Act for the approval of all applied-for pump unit
additions, replacements and modifications and related facilities and station
piping as listed in Schedule A ("the station facilities");
AND WHEREAS pursuant to the Canadian Environmental Assessment Act ("CEAA"), the
Board has performed an environmental screening of the station facilities and has
considered the information submitted by IPL;
AND WHEREAS the Board has determined, pursuant to paragraph 20(1 )(a) of the
CEAA that, taking into account the implementation of IPL' s proposed mitigative
measures and those set out in the attached conditions, the station facilities
are not likely to cause significant adverse environmental effects;
AND WHEREAS the Board has examined the application and considers it to be in the
public interest to grant the relief requested;
IT IS ORDERED that, pursuant to section 58 of the Act, the station facilities
are exempt from the provisions of sections 30, 31 and 47 of the Act, upon the
following conditions:
1. Unless the Board otherwise directs, IPL shall implement or cause to be
implemented all of the policies, practices, recommendations and
procedures for the protection of the environment included in or
referred to in its application, in its undertakings made to other
regulatory agencies or as otherwise adduced in evidence through the
application process.
2. Unless the Board otherwise directs, IPL shall cause the approved
facilities to be designed, manufactured, located, constructed and
installed in accordance with those specifications, drawings and other
information or data set forth in its application or as otherwise
adduced in evidence before the Board.
37
<PAGE> 169
3. Unless the Board otherwise directs, the company shall file, at least 14
days prior to the commencement of construction, a detailed construction
schedule or schedules identifying major construction activities and
shall notify the Board of any substantive modifications to the schedule
or schedules as they occur.
4. Unless the Board otherwise directs, the company shall, at least 14 days
prior to the commencement of construction, file with the Board for
approval the company's field joining program.
5. IPL shall, prior to the commencement of hydrostatic testing of the
station facilities, provide confirmation that all necessary or required
regulatory approvals have been obtained and local municipalities have
been consulted.
6. IPL shall, prior to the operation of the station facilities, file with the
Board updated copies of:
(a) the company's operations and maintenance manual; and
(b) the company's emergency procedures.
7. IPL shall, during the first quarter of operation after start-up,
conduct and file with the Board noise emission surveys to confirm that
the actual noise emission levels resulting from the installation of new
electrically driven pump units within or adjacent to seven existing IPL
pump stations do not exceed the anticipated noise emission levels at
the pump station fence line and at the nearest residence.
8. Unless the Board otherwise directs prior to 31 December 1999, this
Order shall expire on 31 December 1999 unless construction and
installation with respect to the applied-for facilities has commenced
by that date.
NATIONAL ENERGY BOARD
Michel L. Mantha
Secretary
38
<PAGE> 170
(CHART)
39
<PAGE> 171
Appendix VI
ORDER AO-1 -XO-J1 -10-98
IN THE MATTER OF the National Energy Board Act ("the
Act") and the regulations made thereunder; and
IN THE MATTER OF an application by
Interprovincial Pipe Line Inc. ("IPL") filed with the
Board under File No. 3200-J001-5.
BEFORE the Board on 2 June 1998.
WHEREAS the Board has previously issued Order XO-J1-10-98 approving the
installation of three sending and three receiving scraper traps for use on the
904 mm (48 inch) outside diameter pipe sections upstream of IPL's Herschel,
Glenavon and Glenboro stations;
AND WHEREAS the Board has received IPL's Terrace Phase I Expansion Program
application, dated 2 December 1997 and as amended on 31 March 1998, in which IPL
requested an amendment to Order XO-J1-10-98, allowing the previously approved
three sending scraper traps to be relocated and placed in service at JPL's
Loreburn, Craik and Odessa stations ("the project");
AND WHEREAS pursuant to the Canadian Environmental Assessment Act ("CEAA"), the
Board has considered the information submitted by IPL and has performed an
environmental screening of the proposed project;
AND WHEREAS the Board has determined, pursuant to paragraph 20(1 )(a) of the
CEAA that, taking into account the implementation of IPL's proposed mitigative
measures, the proposed project is not likely to cause significant adverse
environmental effects;
IT IS ORDERED that, pursuant to section 21 of the Act, Order XO-J1-10-98 be
amended and that the project be exempted from sections 30, 31 and 47 of the Act,
upon the following condition:
Unless the Board otherwise directs prior to 31 December 1999, this
Order shall expire on 31 December 1999, unless construction and
installation of the proposed project has commenced by that date.
NATIONAL ENERGY BOARD
Michel L. Mantha
Secretary
40
<PAGE> 172
EXPLANATORY STATEMENT
TERRACE TOLL AGREEMENT
This Explanatory Statement briefly summarizes the primary provisions of the
Terrace Toll Agreement (Exhibit 1, Attachment B).
1. The overall purpose of the Terrace Toll Agreement is to provide a
basis for the recovery by Enbridge and Lakehead of the costs of the Terrace
Expansion Program. Schedule A to the Agreement describes in detail the physical
facilities to be constructed or modified in each phase of the project. Article
2 of the Agreement sets forth a schedule on which each set of new facilities is
expected to be in-service, beginning with the first portion of Phase I (January
15, 1999), and continuing through Phase III (September 30, 2001), with
additional phases to follow in 2002-2007 subject to further agreement of the
parties as to the timing of construction.
2. At each stage, CAPP, as representative of the producers, must request
in writing that Enbridge and Lakehead proceed and must give notice as provided
in Article 3 of the Agreement. If CAPP elects not to request both Phases II and
III by July 1, 2001, then pursuant to Article 14, the recovery of Terrace costs
reverts to a cost-of-service-based surcharge rather than the fixed-rate
surcharge embodied in Articles 6 and 7 of the Agreement. If the parties to the
Agreement cannot agree on the terms of the cost-of-service-based surcharge,
their disagreement is subject to arbitration as provided in Article 15 and
Schedule G. This arbitration is solely for the purpose of determining what
surcharge Lakehead would file with the Commission, and is not intended to limit
or affect the FERC's jurisdiction over the filing in any way, except insofar as
Lakehead and CAPP would be bound not to object to or oppose the arbitrated
result.
<PAGE> 173
3. The basic cost recovery mechanism under the Agreement is that Enbridge
and Lakehead will collectively impose a five-cents-per-barrel Canadian (Cdn)
surcharge on top of the underlying rate for transportation of light crude from
Edmonton, Alberta to Griffith, Indiana (Chicago). This base surcharge is subject
to adjustment "on a distance basis and for commodity credits or surcharges,
consistent with Enbridge and LPL's then existing toll design." Article 7. Thus,
for example, transportation of heavy crude from Edmonton to Chicago would be
subject to a total surcharge of somewhat more than 5 cents (Cdn) in accordance
with Enbridge and Lakehead's existing rate design, which includes a
proportionately higher rate for heavier petroleum to reflect its greater
viscosity. Similarly, the surcharges for shorter or longer hauls would vary in
proportion to distance in the same manner as the underlying rates to which the
surcharges apply.
4. As between Enbridge and Lakehead, the Agreement initially provided
that the five-cent (Cdn) surcharge could be divided at Enbridge and Lakehead's
discretion so long as at least one cent (Cdn) is allocated to each system.
Article 9. Subsequently, Enbridge and Lakehead agreed that the five-cent (Cdn)
surcharge is to be divided initially in such a way that three cents (Cdn) is
incurred on the Enbridge system and two cents (Cdn) is incurred on the Lakehead
system.
5. The two-cent (Cdn) increment on Lakehead is to be converted to U.S.
currency on the basis of the "average exchange rate for the period commencing
October [1,] 1998 and ending December 31, 1998 as published in the Bank of
Canada Review, Statistical Supplement." Article 9. Based on current exchange
rates, the two-cent (Cdn) surcharge would translate into approximately 1.3 cents
(U.S.) per barrel. Except as noted in paragraph 14 below,
2
<PAGE> 174
all future adjustments to the base surcharge under the Agreement will be made
using the same exchange rate calculated under Article 9 of the Agreement.
6. Articles 10 and 22 provide that the three-cent (Cdn) surcharge imposed
by Enbridge will be subject to a so-called Transportation Revenue Variance under
the Enbridge Incentive Toll Settlement Agreement. No such provision applies to
Lakehead, and these Articles are therefore irrelevant to the U.S. tariffs.
7. The two-cent (Cdn) surcharge on Lakehead's rates will remain fixed
through December 31, 2013, subject only to the limited adjustments contemplated
in the Agreement. Thus, the cost recovery for the Terrace project is essentially
levelized during a 15-year period, with most of the cost risks falling on
Enbridge and Lakehead.
8. Under Article 12, Enbridge and Lakehead assume 100 percent of the
operating cost risk (i.e., the risk that actual operating costs will exceed the
costs expected at the time of the Agreement), subject only to a limited
exclusion for property taxes. That exclusion is based on an agreed-upon forecast
of expected future property taxes on the Terrace facilities set forth in
Schedule F to the Agreement. Only if the actual experience varies from the
forecast by 20 percent or more in a given year would there be an adjustment to
the Terrace surcharge by way of a surcharge or surcredit as specified in
Schedule B to the Agreement.
9. Under Article 13, the capital cost risks are shared between
Enbridge/Lakehead and the shippers. Article 13 lists the "target costs" as of
December 13, 1997 for each phase of the project (in Canadian dollars for
Enbridge and U.S. dollars for Lakehead). These target costs are inflated from
January 1, 1998 forward using the Canadian and U.S. Gross Domestic Product
deflators. Enbridge and Lakehead absorb 100 percent of the risk of capital cost
variations (i.e., the risk that costs will exceed the adjusted target costs) up
to 5 percent of the
-3-
<PAGE> 175
listed amounts. Above 5 percent, the five-cent (Cdn) base surcharge is adjusted
upward by 0.09 cents (Cdn) per barrel per $10 million change (pro rata) for
Phase I and 0.07 cents (Cdn) per barrel per $10 million change (pro rata) for
Phase II. Agreement, Schedule B. This results in a split of the capital cost
risk above 5 percent on a 50/50 basis. Similarly, if Enbridge and/or Lakehead
can save on capital costs against the target cost, no adjustment is made for the
first 5 percent of variance and any variance in excess of 5 percent is shared
50/50 under the same Schedule B formula. This provision gives Enbridge and
Lakehead an incentive to pursue maximum efficiency in constructing and modifying
any needed facilities and ensures that shippers will benefit from any
substantial efficiencies achieved.
10. Article 17 provides a penalty for Enbridge and Lakehead if the
planned facilities expansions do not yield the additional capacity projected
when tested as provided in Article 17. The penalty is a one-cent (Cdn) per
barrel refund for each 5,500 cubic meters per day (m3/d) (ie, approximately
34,600 barrels per day) by which capacity falls short in a given year.1 This
refund would be achieved by reducing the surcharge proportionately in the year
following the capacity shortfall. No penalty is imposed, however, to the extent
throughput would not have been available to fill the missing capacity on any
event. In addition, pursuant to Article 18, no penalty applies if capacity is
unavailable as a result of the failure to obtain timely regulatory approvals
from necessary agencies.
11. If the capital costs of any phase increase by $10 million (Cdn) or
more due to changes in the scope and timing of the project (as opposed to mere
cost overruns), Article 19
- ---------------
1 This amount is incurred on a pro rata basis, meaning, for example, that a
shortfall of 550 m3/d would lead to a penalty of one-tenth of a cent (Cdn).
-4-
<PAGE> 176
and Schedule B provide that the surcharge will be adjusted by 0.18 cents (Cdn)
per barrel per $10 million (Cdn) change in costs for Phase I, or 0.14 cents
(Cdn) per barrel per $10 million (Cdn) change in costs for Phase II. Agreement,
Schedule B. The result of this provision is effectively to place the costs of
any scope or timing changes requested by CAPP (above $10 million (Cdn)) on the
ratepayers.
12. Article 19 further provides that the surcharge will be
adjusted for construction cost variances due to "agreed upon circumstances which
are extraordinary and not within the control of Enbridge/LPL as more
particularly described in Article 20." This is, in effect, a force majeure
clause for acts of God and similar events. If such events occur, the surcharge
will be adjusted in accordance with Schedule B.
13. Article 19 and Schedule B also provide potential upward or
downward adjustments of the surcharge if the cost of debt or the return on
equity varies by more than two percentage points from 1998 levels. In the case
of debt, if the cost of debt as measured by the current Canadian long bond rate
(5.28%) and 10 year U.S. Treasury bond rate (5.65%) increases or decreases by
more than 200 basis points, the surcharge is increased or decreased 0.1 cent
(Cdn) per barrel for each 50 basis-point change in debt costs, applicable
separately to Enbridge and Lakehead. In the case of equity, if the generic
multi-pipeline cost of equity as determined by the NEB increases or decreases
by more than 200 basis points from its current level, the surcharge in 1999-2007
would be increased or decreased 0.3 cents (Cdn) per barrel for each 25
basis-point change. ID. All changes are made pro rata for increases or decreases
of more or less than the stated amount.
-5-
<PAGE> 177
14. Article 21 is intended to provide protection to Enbridge and Lakehead if,
after completion of Phase III, the anticipated increase in throughput does not
materialize. Schedule C sets forth the amounts and basis for increasing the
surcharge if throughput is too low in various future time periods. Any
adjustments to the surcharge are to be implemented in the year following the
year of the throughput shortfall. For this purpose, Canadian currency values
are to be converted to U.S. currency based on the most recent 12-month average
exchange rate at the time in question.
15. Article 24 provides that the calculation of the surcharge will assume that
the Terrace facilities are depreciated on a straight line basis using a
truncation date of 2024.
16. Article 25 provides CAPP a right to audit Enbridge and Lakehead's
compliance with the Agreement upon the terms set forth in Article 25.
-6-
<PAGE> 178
EXHIBIT NO. 6
EXPLANATORY STATEMENT
350 CENTISTOKE AGREEMENT
This Explanatory Statement briefly summarizes the primary
provisions of the 350 Centistoke Agreement (Exhibit 1, Attachment C).
1. Lakehead will make the change to begin accepting crude with
a viscosity limit of 350 centistokes when CAPP formally requests that Enbridge
and Lakehead commence 350 centistoke service.
2. The 350 Centistoke Agreement provides that the surcharge in
Lakehead's rates for heavy crude petroleum will be increased from 20 percent to
as much as 22 percent on heavy crude petroleum deliveries made after Lakehead
has commenced 350 centistoke service in accordance with the receipt of the CAPP
notice.
<PAGE> 179
EXHIBIT NO. 7
[LOGO]
National Energy Board Office national de l'energie
File: 3400-J001-84
21 August 1997
BY FACSIMILE (403) 420-5389
Mr. Robert L. Nichols
Vice President, Accounting and Regulatory Affairs
Interprovincial Pipe Line Inc.
IPL Tower, 10201 Jasper Avenue
P.O. Box 398
Edmonton, Alberta
T5J 2K9
Dear Mr. Nichols:
Re: Interprovincial Pipe Line Inc. ("IPL")
350 Centistoke Project Application for Orders Pursuant to
Section 58 and Part IV, Dated 22 April 1997
The Board has examined IPL's application, dated 22 April 1997, pursuant
to section 58 and Part IV of the National Energy Board Act (the "Act"), for
approval of facilities additions and toll orders necessary to allow IPL to
increase the density and viscosity limits of heavy crude oil accepted for
transportation ("350 Centistoke Project").
The Board notes that the 350 Centistoke Project was developed between
IPL and an industry task force represented by heavy oil interests and has
received the formal support of the Canadian Association of Petroleum Producers.
The Alberta Department of Energy and PanCanadian Petroleum Limited have filed
letters in support of the project. The Board further notes that no party has
expressed any concerns with IPL's application.
The Board has approved the construction of the 350 Centistoke Project,
as applied-for. Accordingly, the Board has issued Order OX-J1-28-97, the effect
of which is to permit IPL to proceed with construction of the proposed
facilities.
With regard to Part IV matters, the Board finds that the capital and
operating costs relating to the proposed facilities constitute a Non-Routine
Adjustment in accordance with paragraph 7.1(a)(i) of the principles of
settlement, filed in support of IPL's February 1995 Incentive Toll Application
approved by Order TO-1-95, issued 24 March 1995.
-2-
<PAGE> 180
The Board has approved in principle a two percentage point surcharge
(to 22 percent) for heavy crude petroleum with viscosity limits between 100 to
350 square millimetres per second and density limits between 904 to 940
kilograms per cubic metre, inclusive. Pursuant to subsection 19(l) of the Act,
the revised heavy petroleum surcharge will not become effective until
notification from CAPP and the filing of tariffs by IPL pursuant to paragraph
60(l)(a) of the Act.
The Board directs IPL to serve a copy of this letter and the attached
Order on all parties identified on its interested parties list.
Yours truly,
/s/ M.L. Mantha
---------------------------
M. L. Mantha
Secretary
Attach.
<PAGE> 181
[LOGO]
National Energy Board Office national de l'energie
ORDER XO JI-28-97
IN THE MATTER OF the National Energy Board Act
("the Act") and the regulations made
thereunder; and
IN THE MATTER OF an application, pursuant to
section 58 of the Act, by Interprovincial Pipe
Line Inc. ("IPL"), filed with the Board under
File 3400-J001-84.
B E F O R E the Board on 21 August 1997.
WHEREAS the Board has received an application from IPL dated 22 April
1997, respecting the construction of additional pipeline facilities to
enable the transportation of crude oils at higher viscosity and density
limits ("350 Centistoke Project"), estimated cost $9 million;
AND WHEREAS pursuant to the Canadian Environmental Assessment Act (CEAA),
the Board has considered the information submitted by IPL and has
performed an environmental screening of the proposal;
AND WHEREAS the Board has determined, pursuant to paragraph 20(1)(a) of
the CEAA that, taking into account the implementation of IPL's proposed
mitigative measures and those set out in the conditions to this Order,
the proposal is not likely to cause significant adverse environmental
effects;
IT IS ORDERED that the construction of the 350 Centistoke Project is
exempt from the provisions of sections 30, 31 and 47 of the Act, upon the
following conditions:
1) Unless the Board otherwise directs, IPL shall implement
or cause to be implemented all of the policies,
practices, recommendations and procedures for the
protection of the environment included in or referred
to in its application.
2) Unless the Board otherwise directs, IPL shall cause no
variations to the procedures and mitigative measures
for the protection of the environment
<PAGE> 182
without the prior approval of the board.
3) Unless the Board otherwise directs, IPL shall, within
14 days of the receipt of any subsequent concerns
expressed by stakeholders on the IPL right-of-way,
provide the Board with a report detailing the concerns
and the measures IPL will implement to mitigate those
concerns.
4) Unless the Board otherwise directs, IPL shall conduct
noise surveys at those terminals and pump stations
where pumping unit installation and pumping unit
modification are to occur and provide the Board with
confirmation that noise level increases have not
exceeded 3.0 decibels.
5) Unless the Board otherwise directs prior to 31 December
1998, this Order shall expire on 31 December 1998
unless the Construction and installation with respect
to the additional facilities has commenced by that
date.
NATIONAL ENERGY BOARD
/s/ M.L. Mantha
---------------------------------------
M. L. Mantha
Secretary
<PAGE> 183
CERTIFICATE OF SERVICE
I hereby certify that I have, this 27th day of October, 1998, served
copies of the foregoing Offer of Settlement and attachments via first-class
mail, postage prepaid, on the Canadian Association of Petroleum Producers and on
all current shippers of Lakehead Pipe Line Company, Limited Partnership.
/s/ S. Reed
-------------------------------
Steven Reed
<PAGE> 1
EXHIBIT 21
LAKEHEAD PIPE LINE PARTNERS, L.P.
PRINCIPAL SUBSIDIARIES
The Registrant's principal subsidiary is Lakehead Pipe Line Company,
Limited Partnership, a Delaware limited partnership, in which the Registrant has
a 99% limited partner interest.
<TABLE> <S> <C>
<ARTICLE> 5
<MULTIPLIER> 1000
<S> <C>
<PERIOD-TYPE> YEAR
<FISCAL-YEAR-END> DEC-31-1998
<PERIOD-START> JAN-01-1998
<PERIOD-END> DEC-31-1998
<CASH> 47000
<SECURITIES> 0
<RECEIVABLES> 25200
<ALLOWANCES> 0
<INVENTORY> 0
<CURRENT-ASSETS> 111300
<PP&E> 1487300
<DEPRECIATION> 191100
<TOTAL-ASSETS> 1414400
<CURRENT-LIABILITIES> 102300
<BONDS> 814500
0
0
<COMMON> 0
<OTHER-SE> 495000
<TOTAL-LIABILITY-AND-EQUITY> 1414400
<SALES> 0
<TOTAL-REVENUES> 287700
<CGS> 0
<TOTAL-COSTS> 182300
<OTHER-EXPENSES> 1000
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 21900
<INCOME-PRETAX> 88500
<INCOME-TAX> 0
<INCOME-CONTINUING> 88500
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 88500
<EPS-PRIMARY> 3.07
<EPS-DILUTED> 3.07
</TABLE>
