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                                                                   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


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     (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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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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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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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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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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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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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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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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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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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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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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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

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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.

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     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


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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

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16  A "centistoke" is a unit of kinematic viscosity which is commonly used as
    measure of the viscosity of crude petroleum.


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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.


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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.

    
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                                   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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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


                                     - 24 -


<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.


                                     - 2 -


<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




                                     - 4 -


<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


                                     - 3 -


<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.







                                       10


<PAGE>   142

         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.






                                       11


<PAGE>   143


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






                                       12


<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.



                                       13



<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.




                                       14


<PAGE>   146


         -   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.










                                       15


<PAGE>   147


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).



                                       16


<PAGE>   148


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.



























                                       17


<PAGE>   149


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.












                                       18





<PAGE>   150
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


                                       19



<PAGE>   151

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.





















                                       20


<PAGE>   152


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.


                                       21


<PAGE>   153


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

                                       22


<PAGE>   154


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.














































                                       24


<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:





                                       33


<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