LIQUIDS PIPELINES

Liquids Pipelines consists of crude oil, natural gas liquids and refined products pipelines in Canada and the United States.

Liquids Pipelines earnings were $274.2 million in 2006 compared with $229.1 million in 2005. The increase resulted from strong results from the Enbridge System, the commencement of operations of the Spearhead Pipeline and the acquisition of the Olympic Pipeline.

Earnings from Liquids Pipelines were $229.1 million for the year ended December 31, 2005, an increase of $9.2 million from 2004. The increase was due to higher Athabasca System earnings, consistent with the take or pay agreement with the major shipper, and improved earnings from Feeder Pipelines and Other, primarily Frontier Pipeline, which paid Federal Energy Regulatory Commission (FERC) ordered reparations in 2004.

Revenues in the Liquids Pipelines segment increased to $1,048.1 million in the year ended December 31, 2006 from
$881.0 million in the year ended December 31, 2005. The increased revenue was due to a higher revenue requirement on the Enbridge System as well as the start up of Spearhead Pipeline, which commenced operations in the first quarter of 2006 and Olympic Pipeline, which was acquired in the first quarter of 2006.

Revenues in the Liquids Pipelines segment were $881.0 million in 2005 comparable with $872.7 million for 2004.

Results of Operations
Enbridge System earnings were $202.3 million for the year ended December 31, 2006 compared with $170.1 million for the year ended December 31, 2005. This increase reflected higher earnings from a number of factors including lower oil loss costs, favourable ITS performance and, within Terrace, lower taxes, higher toll revenues and the impact of higher volumes generating surcharge revenue.

Enbridge System earnings were $170.1 million for the year ended December 31, 2005 compared with $171.6 million for the year ended December 31, 2004. The $1.5 million decrease was due to a lower earnings base from the ITS component of Enbridge System and higher taxes within the Terrace component. The decrease was partially offset with earnings from the reliability and service metrics under the ITS as well as savings from cost management programs.

Incentive Tolling
Tolls on the Enbridge System are governed by various agreements, which are subject to the approval of the National Energy Board (NEB). The NEB’s jurisdiction over the Enbridge System includes statutory authority over matters such as construction, rates and ratemaking agreements and other contractual arrangements with customers. Significant agreements include the ITS applicable to the Enbridge mainline system (excluding Line 8 and Line 9), the Terrace agreement and the System Expansion Program (SEP) II Risk Sharing Agreement. Tolls on the core mainline system have been governed by incentive tolling settlements since 1995.

In 2005, Enbridge and the Canadian Association of Petroleum Producers (CAPP) approved the key terms of a new negotiated ITS, effective from January 1, 2005 to December 31, 2009. In January 2006, the NEB approved the ITS. The ITS continues the sharing of earnings in excess of a stipulated threshold and provides a fixed annual mainline integrity allowance. In addition to the incentive-based provisions in prior agreements, service and reliability metrics have been added to the new ITS to further align the Company’s interests with its shippers. The Company has the opportunity to increase earnings by achieving performance targets under the new performance metric provisions.

In conjunction with the Terrace Agreement, the new ITS continues the throughput protection provisions included in earlier incentive tolling arrangements, ensuring the Company is insulated from volume fluctuations beyond its control. The agreements govern both current and future shippers on the pipeline and establish tolls each year based on an agreed capacity and an allowed revenue requirement. Where actual volumes on the pipeline fall short of the agreed capacity and Enbridge is unable to collect its annual revenue requirement, such deficiency is rolled into the subsequent year’s tolls for collection from toll payers at that time and a receivable is recognized. This basis may affect the timing of recognition of revenues compared with that otherwise expected under generally accepted accounting principles for companies that are not rate-regulated.

Athabasca System
The Athabasca System, a 540-kilometre (340-mile) synthetic and heavy oil pipeline, links the Athabasca oil sands in the Fort McMurray, Alberta region, to a pipeline transportation hub at Hardisty, Alberta. The Athabasca System also includes the MacKay River, Christina Lake, Surmont and Long Lake feeder lines, growing tankage facilities and the Company’s interest in the Hardisty Caverns Limited Partnership, which provides crude oil storage services.

Results of Operations
Earnings for the year ended December 31, 2006 were $52.8 million, an increase of $4.2 million from 2005. Infrastructure additions contributed to the increase, partially offset by higher operating expenses.

Athabasca System earnings were $48.6 million for the year ended December 31, 2005, an increase of $5.8 million from 2004. The increase was consistent with the long-term contract with its major shipper as well as lower operating costs due to leak remediation costs in 2004.

The Company has a long-term (30 year) take-or-pay contract with the major shipper on the Athabasca System, which commenced in 1999. Revenue is recorded based on the contract terms negotiated with the major shipper, rather than the cash tolls collected. The contract provides for volumes and tolls that will achieve an underpinning return on equity, based on an assumed debt/equity ratio and level of operating costs. The committed volumes and the tolls specified in the contract do not generate sufficient cash revenues in the early years to compensate Enbridge for the debt and equity returns, as well as the cost of providing service. Therefore, Enbridge is recording a receivable in these years. This treatment ensures that the revenue recognized each period is in accordance with the contract. This receivable is contractually guaranteed by the shipper and will be collected in the later years of the contract.

Spearhead Pipeline
The Spearhead Pipeline commenced delivery of crude oil from Chicago, Illinois to Cushing, Oklahoma in March 2006. The performance of the Spearhead Pipeline has continued to surpass Enbridge’s expectations with fourth quarter nominations exceeding the pipeline’s 125,000 barrels per day (bpd) capacity. Enbridge is currently evaluating the potential to expand the Spearhead pipeline.

Olympic Pipeline
In February 2006, Enbridge acquired a 65% interest in the Olympic Pipeline from BP Pipelines. Olympic is the largest refined products pipeline in the State of Washington, transporting approximately 290,000 bpd of gasoline, diesel and jet fuel. The pipeline system extends approximately 480 kilometres (300 miles) from Blaine, Washington to Portland, Oregon, connecting four Puget Sound refineries to terminals in Washington and Portland. The system consists of 640 kilometres (400 miles) of 6 to 20 inch diameter pipe, a 500,000-barrel terminal, 9 pumping stations and 21 delivery points or facilities. BP is the operator of the pipeline.

Olympic Pipeline has performed reliably and 2006 earnings were in line with expectations.

Feeder Pipelines and Other
Feeder Pipelines and Other primarily includes the NW System, which transports crude oil from Norman Wells in the Northwest Territories to Zama, Alberta, interests in a number of liquids pipelines in the United States (Frontier, Toledo, Mustang and Chicap), liquid storage facilities (Patoka) and business development costs related to Liquids Pipelines activities.

Earnings in Feeder Pipelines and Other were $6.3 million for the year ended December 31, 2006 compared with $11.5 million for the year ended December 31, 2005 primarily due to increased business development costs related to the Company’s organic growth projects.

Feeder Pipelines and Other earnings for the year ended December 31, 2005 were $11.5 million compared with $5.9 million for the year ended December 31, 2004. The increase was due to the capitalization of Gateway condensate pipeline costs in 2005, as the criteria for capitalization were met, starting in 2005. In addition, Frontier Pipeline earnings were higher due to lower operating costs as well as FERC ordered reparations paid in 2004.

Strategy
The Company seeks to go beyond the traditional regulated utility business model to create additional value for customers. The Liquids Pipelines strategy focuses on meeting the needs of Western Canadian producers and is supported by the Company’s estimates of supply and demand for Western Canadian crude oil.

Supply and Reserves
The vast resource of the Western Canadian Sedimentary Basin (WCSB) and its development, create the basis for the Liquids Pipelines growth strategy. Generally, development of the oil sands resource has more than offset declining conventional production. The NEB estimates that total Western Canada production will be 2.5 million bpd¹ at the end of 2006 (2005 – 2.3 million bpd). At the end of 2005, remaining established conventional oil reserves in Western Canada were estimated to be 3.8 billion barrel² and remaining established reserves from oil sands were estimated at 174 billion barrels³. Combined conventional and oil sands reserves put Canada second only to Saudi Arabia with 14% of the worldwide estimated proved reserves^4.

Demand for WCSB Crude
The Company’s liquids pipelines are dependent upon the demand for crude oil and other liquid hydrocarbons produced from Western Canada. Deliveries from the pipeline system are made in the prairie provinces, the Province of Ontario and the Great Lakes, and Midwest regions of the United States, principally to refineries, either directly or through the connecting pipelines of other companies. Within these regions are located major refining centres near Sarnia, Nanticoke, and Toronto, Ontario; the Minneapolis-St. Paul area of Minnesota; Superior, Wisconsin; Chicago, Illinois; the Patoka/Wood River, Illinois area; Detroit, Michigan; and Toledo, Ohio. Through Company initiatives, crude oil has started to penetrate markets in southern PADD II (the U.S. Midwest) with the Spearhead Pipeline to Cushing, Oklahoma; as well as the U.S. Gulf Coast (PADD III) via a third party pipeline system.

Historically, Canada has been the third largest supplier of crude to the U.S. However, for the past three years, Canada has surpassed both Mexico and Saudi Arabia to become the largest crude oil exporter to the U.S. ¹

Deliveries of WCSB crude into PADD II increased by 64,300 bpd over the last two years with increased WCSB crude oil supply in 2006². Over the same two-year period, deliveries into PADD IV (the U.S. Rocky Mountains) have increased by 6,700 bpd, PADD V (the Western U.S.) deliveries have increased by 6,000 bpd, and PADD III deliveries have increased by 63,800 bpd ². Western Canadian demand is served by local supply and has remained relatively flat over the last two years ². During 2006, greater volumes of Western Canadian crude were transported to Ontario ³, pushing back Atlantic Basin crude oil ².

Key Components of the Liquids Pipelines Strategy
The Liquids Pipelines strategy is driven by the industry’s need for export capacity alternatives, economic sources of diluent and U.S. refiners’ need to maintain diversified sources of supply. The six key components of the Liquids Pipelines strategy are described below as well as progress made to date and future plans towards further advancing the strategy.

1. Capitalize on the Mainline ITS
The ITS rewards Enbridge for achieving certain targeted service levels and product attributes, which adds value for customers. To ensure returns on mainline operations are maximized, the Company will focus on cost efficiency, providing reliable capacity and predictable deliveries, and maintaining optimal batch quality.

The ITS service metrics establish financial bonuses and penalties for prescribed performance targets related to crude oil quality management and predictability of scheduled deliveries. The potential bonuses and penalties for the service metrics are limited to a maximum of $10 million after tax in 2005, escalating to $15 million in each of 2006 and 2007, and to $20 million in each of 2008 and 2009. The targets to achieve the maximum bonus under the ITS become increasingly difficult to achieve in successive years.

The reliability metric provides for bonuses and penalties associated with optimization of system capacity, which are calculated monthly relative to annual capacity targets. Practical constraints around pipeline capacity would limit the bonus for the reliability metric to approximately $12 million per year and penalties are limited to $10 million per year.

ITS metrics bonuses related to 2005 were $10.2 million. ITS metrics bonuses for 2006 are comparable with 2005 and will be filed as part of 2007 toll application with the NEB.

2. Mainline Capacity Expansion
The Chicago refining market has been a traditional destination for Western Canadian crude. The Company is working with shippers and refiners to further expand this market. The Southern Access Expansion and the Alberta Clipper Project are two projects that the Company is undertaking to meet this objective.

Southern Access Mainline Expansion
The Southern Access Mainline Expansion project is currently under construction and will ultimately add a total of 400,000 bpd incremental capacity to the mainline system. The U.S. segment of the expansion from the Canada/U.S. border to Flanagan, Illinois, is being undertaken by EEP and the Canadian segment from Hardisty, Alberta to the Canada/U.S. border is being undertaken by Enbridge.

The Canadian segment expansion schedule has been expedited with 120,000 bpd added in 2006, an additional 63,000 bpd expected in 2008 and another 85,000 bpd expected in 2009 in order to match the total additional capacity of 400,000 bpd being provided in the United States. With the support of industry, the proposed diameter of the Southern Access Expansion from Superior, Wisconsin to Flanagan, Illinois has been increased to 42 inches, increasing the estimated cost to US$1.3 billion on the U.S. segment, to be undertaken by EEP. The estimated cost of the Canadian segment, to be undertaken by Enbridge is $0.2 billion.

The FERC has approved an Offer of Settlement with respect to rates for the U.S. segment of the expansion. Enbridge filed a Southern Access Expansion surcharge methodology with the NEB in June 2006.

Alberta Clipper Project
The Alberta Clipper Project would involve the construction of a new 36-inch diameter pipeline from Hardisty, Alberta to Superior, Wisconsin, in conjunction with additional pumping power applied to the new 42-inch pipe from Superior to Flanagan, Illinois, described above under Southern Access Expansion. The Alberta Clipper Project would interconnect with the existing mainline system in Superior where it would provide access to Enbridge’s full range of delivery points and storage options, including Chicago, Toledo, Sarnia, Patoka, Wood River and Cushing.

The expected capacity of the pipeline has been increased from 400,000 bpd to 450,000 bpd. The Canadian segment of the line is expected to cost $1.5 billion (in 2006 dollars) and the U.S. segment, which would be undertaken by EEP, is expected to cost US$0.8 billion.

In January 2007, industry confirmed its support for the Alberta Clipper Project. Regulatory applications will be filed once commercial terms are finalized, which is expected to occur in the first quarter of 2007. The Alberta Clipper Project is expected to be in service in late 2009 or 2010.

Line 4 Extension Project
The company obtained industry support for the extension of Line 4, part of the Enbridge mainline system, between Hardisty, Alberta and the Company’s terminal at Edmonton, Alberta. The project is expected to cost $0.3 billion and, subject to receipt of required regulatory approval is targeted to be in service in late 2008.

3. Upstream Pipeline Development
Increasing oil sands production will require significant new infrastructure upstream of the mainline and the Company is developing a number of projects to support the development of the Alberta oil sands. Growth opportunities already secured include construction of the Waupisoo Pipeline and expansion of the Athabasca System, including the contruction of Long

Lake and Surmont laterals. In addition, a number of large new oil sands requiring substantial upstream pipeline facilities will be selecting a service provider in 2007, and the Company is well positioned to secure a significant portion of these growth opportunities.

Waupisoo Pipeline
The 30-inch diameter, 380-kilometre (236-mile) long Waupisoo Pipeline will transport crude oil from the Cheecham terminal, currently under construction on the Athabasca Pipeline, to the Edmonton, Alberta area. The initial capacity of the line will be 350,000 bpd and is expandable to a maximum of 600,000 bpd with additional pumping units.

Enbridge has filed an application for regulatory approval with the Alberta Energy and Utilities (AEUB) Board and other provincial government departments. Subject to timely receipt of regulatory approvals, expected in the first quarter of 2007, Enbridge will begin construction on the approximately $0.5 billion pipeline in 2007, with an expected in-service date of mid-2008.

The previously announced diluent line has been removed from the regulatory filing in order to expedite the crude oil line, which is needed earlier. Enbridge will continue discussion with all interested parties regarding the diluent line, with construction and an in-service date to be determined at a later date.

Athabasca Pipeline Expansion Projects
In 2006, the Company furthered several expansion projects on the Athabasca Pipeline. The expansion projects include the addition of pumping stations at Elk Point and Cheecham, as well as modifications to existing pumping stations. Construction is progressing and the projects are scheduled to be completed early 2007.

Surmont Oil Sands Project
The Surmont Oil Sands Project consists of pipeline and tank facilities required by the Surmont Project at the Cheecham Terminal on the Athabasca Pipeline. Enbridge has 25-year agreements with ConocoPhillips Surmont Partnership and Total E&P Canada Ltd. (the Surmont Shippers), to provide pipeline transportation services on the Athabasca Pipeline for an initial contract volume of up to 50,000 bpd of crude oil with the option to increase the contract volume to up to 220,000 bpd for future phases of production. The agreements also provide flexibility for the Surmont Shippers to transfer their production to the proposed Waupisoo Pipeline to the Edmonton area. Enbridge has completed construction and is awaiting first production

Long Lake Oil Sands Project
The Company has agreements with Nexen Inc. and OPTI Canada Inc. (the Long Lake Shippers) to provide pipeline transportation services for the Long Lake Project. The agreements provide for an initial contract volume of up to 60,000 bpd of crude oil with provisions for volume increases. The Long Lake lateral agreement is for a term of 25 years and the agreement for service on the Athabasca Pipeline is for a 50-month term with extension provisions. Under the terms of the agreements, Enbridge will construct, own and operate the pipeline and tank facilities required by the Long Lake Project, as well as pipeline laterals and tank facilities at the Cheecham terminal on the Athabasca Pipeline. Construction of the laterals and facilities is underway and expected to be in service in early 2007, to coincide with first production rom the Long Lake Oil Sands Project.

4. New Market Access
The Company will develop new options to expand market access for Canadian crude. Specific initiatives include: extending the Mainline south of Chicago to Patoka, Illinois, expansion of the Spearhead Pipeline from Chicago to Cushing by 65,000 bpd, developing access to the Gulf Coast market directly from Alberta or through a combination of existing infrastructure and new pipelines, and accessing markets in Asia and California.

Southern Access Extension
The Southern Access Extension involves the construction of a new 36-inch diameter, 400,000 bpd pipeline extending the mainline from Flanagan, Illinois to Patoka at a cost of approximately US$0.4 billion to Enbridge. Discussions with shippers have been finalized and, with industry support for this project, a FERC Offer of Settlement was filed on September 1, 2006.

The initial Offer of Settlement proposing a rolled in toll design was not approved by the FERC. However, support for the project remains very strong and Enbridge is working with industry on an alternative tolling structure to address the initial opposition from the intervening parties. The Company expects that a second application will be filed with the FERC in the first quarter of 2007 to allow the project to continue on schedule, with an estimated 2009 in-service date.

U.S Gulf Coast Initiatives
The Company continues to meet with industry to explore and develop various options to enhance access to the U.S. Gulf Coast for Canadian supply. Alternatives under discussion include the development of incremental pipeline capacity to the U.S. Gulf Coast, given the projected increase in Canadian production. This interest includes support for a project from Patoka to the U.S. Gulf Coast to deliver an incremental 400,000 bpd of Canadian crude; and a new 400,000 bpd pipeline, which could transport oil from Alberta directly to Texas. This pipeline would also connect to refining centers in Denver, Colorado and Cushing.

The Company is examining greenfield pipeline options as well as the use of existing pipelines that may be candidates for reversal or expansion. The development of a number of alternative large diameter pipeline initiatives allows shippers to choose the projects that best meet their needs.

Eastern PADD II / Eastern Canada
Enbridge is exploring options to provide approximately 300,000 bpd incremental pipeline capacity to the Eastern PADD II region from the Chicago area in conjunction with potential expansion of existing lines serving the Sarnia, Ontario market.

The Gateway Project
The Gateway Project includes both a condensate import pipeline and a petroleum export pipeline. The condensate line would transport imported diluent from Kitimat, British Columbia to the Edmonton, Alberta area. The petroleum export line would transport crude oil from the Edmonton area to Kitimat. The condensate line is expected have a 20-inch diameter and an initial capacity of 193,000 bpd. The petroleum export line would have a 36-inch diameter and an initial capacity of 525,000 bpd. Capital cost estimates will be completed once commercial terms are finalized.

Current shipper preferences to accelerate the development of capacity to traditional U.S. markets will likely result in the acceleration of the Alberta Clipper Project, such that it precedes the Gateway Pipeline project. The Company now estimates that the Gateway in-service date will be in the 2012 to 2014 timeframe. The decision to proceed with the regulatory filing for either pipeline is subject to commercial considerations, including satisfactory completion of shipper agreements, environmental assessment as well as public and Aboriginal consultation.

5. Diluent Supply Projects
Increasing heavy oil production requires new supplies of diluent, which is needed to dilute heavy oils for transport through pipelines. The Company is developing projects, to bring diluent to Alberta from the Midwest, as well as imported diluent supplies from the west coast of British Columbia, as described above in the Gateway Project.

Southern Lights Pipeline
Following the successful closing of a binding open season in July 2006, Enbridge announced plans in December 2006 to proceed with the Southern Lights Pipeline to increase the availability of diluent in Alberta. When completed, this 180,000 bpd, 20-inch diameter pipeline will transport diluent from Chicago to Edmonton and is expected to be in service in mid 2010.

The Southern Lights Pipeline project involves reversing the flow of a portion of Enbridge’s Line 13, an existing crude oil pipeline, from Clearbrook, Minnesota to Edmonton. The Canadian portion of Line 13 is currently part of the mainline system and the U.S. portion of Line 13 is owned by EEP. In order to replace the light crude capacity that would be lost through the reversal of Line 13, the Southern Lights Project also includes the construction of a new 20-inch diameter crude oil pipeline from Cromer, Manitoba to Clearbrook, and the expansion of existing Line 2. These changes to the existing crude oil system will ultimately increase southbound light crude system capacity by approximately 45,000 bpd. The capital cost of the Southern Lights project, including the new 20-inch diameter diluent pipeline, is estimated at approximately US$1.3 billion.

In the fourth quarter of 2006, Enbridge received industry endorsement for the Southern Lights Pipeline project including an acceleration of the light crude capacity replacement and a delay in the transfer of Line 13 from the mainline system to the Southern Lights project. The impact of this change will be to increase the light crude system capacity on the mainline system by 215,000 bpd until the earlier of the completion of construction of new capacity out of the Western Canadian basin or the middle of 2010. On this date, Line 13 will be transferred to the Southern Lights project. Also during the fourth quarter, EEP approved the exchange of the portion of Line 13 currently owned by EEP for a portion of the Cromer to Clearbrook crude oil pipeline to be constructed. Remaining regulatory applications are expected to be filed in the first quarter of 2007.

6. Terminating and Storage Infrastructure
Based on producer interest, the Company plans to increase its investment in contract terminals over the next five years. Upstream contract storage projects include the Hardisty Terminal, the Stonefell Terminal near Fort Saskatchewan and expansion of the Athabasca Terminal. Downstream projects are under development or consideration by Enbridge or EEP at Flanagan, Patoka, Cushing and the U.S. Gulf Coast. The Company and EEP are also constructing significant additions to the capacity of the common carrier mainline terminals at Edmonton, Superior and Chicago.

Hardisty Terminal
The Company plans to proceed with the construction of a new crude oil terminal at Hardisty, Alberta. The terminal is expected to have a capacity of 7.5 million barrels and will cost approximately $0.4 billion. Enbridge has executed contracts for over 80% of the capacity and is close to closing contracts for the balance of the capacity. It is anticipated that the terminal will start to come into service early in 2008, with tanks being commissioned throughout 2008 and into 2009. An additional phase of development which will increase the terminal’s capacity by up to 3.4 million barrels, is planned and the Company is in discussions with customers who are seeking this additional capacity. Once complete, the Hardisty Terminal will be one of the largest crude oil terminals in North America.

Stonefell Terminal
A Energy Inc. is building a bitumen upgrader near Fort Saskatchewan, Alberta for which Enbridge has agreed to provide pipeline and terminaling services. Based on initial scope and cost estimates, Enbridge expects to invest approximately $0.1 billion in new facilities to provide storage services at a new satellite terminal to be developed adjacent to the upgrader. Enbridge will also provide pipeline transportation for the upgrader’s output from the new terminal to a refinery hub near Edmonton. These facilities are expected to be in service in mid-2008.

The Stonefell Terminal is also strategically located adjacent to several other proposed or operating upgrading facilities and pipeline systems and will be a focus for further development of contract terminaling infrastructure.

Downstream Terminaling
The Company continues to advance many downstream terminaling projects, including EEP-sponsored projects with an estimated US$0.1 billion cost for adding approximately 5 million barrels of storage at Cushing in 2007. Enbridge is pursuing several other terminaling projects estimated at US$0.2 billion with in-service dates of 2007 and 2008

Capital Expenditures
Liquids Pipelines generally spends $80 to $100 million each year on ongoing capital improvements and core maintenance capital projects. In 2007, the Company expects to spend $150 million on capital maintenance and improvements. Expenditures for organic growth projects described above were $320 million in Canada for 2006. For 2007, the Company expects to spend $1.3 billion for the organic growth projects. Discussion of the Company’s access to financing is included under Liquidity and Capital Resources.

Legal Proceeding – CAPLA Claim
The Canadian Alliance of Pipeline Landowners’ Associations (CAPLA) and two individual landowners have commenced a class action against the Company and TransCanada PipeLines Limited. The claim relates to restrictions in the National Energy Board Act on crossing the pipeline and the landowners’ use of land within a 30-metre control zone on either side of the pipeline easements. The Company believes it has a sound defence and intends to vigorously defend the claim. The Plaintiffs filed a motion to establish a cause of action, which is one of the requirements to have the motion certified as a class action under the Class Proceedings Act (Ontario). The motion was dismissed by the Ontario District Court in late 2006. The Plaintiff has since appealed the decision and the appeal is expected to be heard by the Court of Appeal during the first half of 2007. Since the outcome is indeterminable, the Company has made no provision at this time for any
potential liability.

Business Risks
The risks identified below are specific to the Liquids Pipelines business. General risks that affect the Company as a whole are described under Risk Management.

Supply and Demand
The operation of the Company’s liquids pipelines are dependent upon the supply of, and demand for, crude oil and other liquid hydrocarbons from Western Canada. Supply, in turn, is dependent upon a number of variables, including the availability and cost of capital and labour for oil sands projects, the price of natural gas used for steam production, and the price of crude oil. Demand is dependent, among other things, on weather, gasoline price and consumption, manufacturing, alternative energy sources and global supply disruptions.

ITS Metrics
The ITS governing the Enbridge System measures the Company’s performance in areas key to customer service. If the Company fails to meet the baseline targets set out in the new ITS, for all service and reliability metrics, the Company could be required to pay penalties to shippers up to a maximum of $25 million in 2007 and $30 million in 2008 and 2009.

Regulation
Earnings from the Enbridge System and other liquids pipelines are subject to the actions of various regulators, including the NEB. Actions of the regulators related to tariffs, tolls and facilities impact earnings from these operations. The NEB prescribes a benchmark multi-pipeline rate of return on common equity, which is 8.46% in 2007 (2006 – 8.88%). To the extent the NEB rate of return fluctuates, a portion of the Enbridge System and other liquids pipelines earnings will change. The Company believes that regulatory risk can be reduced through the negotiation of long-term agreements with shippers.

Competition
Competition among common carrier pipelines is based primarily on the cost of transportation, access to supply, the quality and reliability of service and contract carrier alternatives and proximity to markets. Other common carriers are available to producers to ship Western Canadian liquids hydrocarbons to markets in either Canada or the United States. As well, competition could arise from pipeline proposals that may provide access to market areas currently served by the Company’s liquids pipelines. One such proposal is the Keystone Project put forward by TransCanada Corporation to ship Western Canadian crude oil into PADD II starting in 2009. The Company believes that its liquids pipelines are serving larger markets and provide attractive options to producers in the WCSB due to their competitive tolls and multiple delivery and storage points. Also, shippers are not required to enter into long-term shipping commitments on the mainline system. The Company’s existing right of way provides a competitive advantage, as it can be difficult and costly to obtain new rights of way for new pipelines. This can act as a barrier to entry for other companies considering constructing new pipelines. The ITS and the Terrace Agreement on the Enbridge System provide throughput protection which insulates the Company from negative volume fluctuations beyond its control. The Lakehead System, owned by EEP, has no similar throughput protection and is exposed to volume fluctuations.

Increased competition could arise from new feeder systems servicing the same geographic regions as the Company’s feeder pipelines.