Management’s Report

To the Shareholders of Enbridge Inc.

Management is responsible for the accompanying consolidated financial statements and all other information in this Annual Report. The consolidated financial statements have been prepared in accordance with Canadian generally accepted accounting principles and necessarily include amounts that reflect management’s judgment and best estimates. Financial information contained elsewhere in this Annual Report is consistent with the consolidated financial statements.

Management has established systems of internal control that provide reasonable assurance that assets are safeguarded from loss or unauthorized use and produce reliable accounting records for the preparation of financial information. The internal control system includes an internal audit function and an established code of business conduct.

The Board of Directors and its committees are responsible for all aspects related to governance of the Company. The Audit, Finance & Risk Committee of the Board, composed of directors who are not officers or employees of the Company, has a specific responsibility for ensuring that management fulfills its responsibilities for financial reporting and internal controls related thereto. The Committee meets with management, internal auditors and independent auditors to review the consolidated financial statements and the internal controls as they relate to financial reporting. The Audit, Finance & Risk Committee reports its findings to the Board for its consideration in approving the consolidated financial statements for issuance to the shareholders.

PricewaterhouseCoopers LLP, appointed by the shareholders as the Company’s independent auditors, conducts an examination of the consolidated financial statements in accordance with Canadian generally accepted auditing standards.

Patrick D. Daniel	Stephen J. Wuori
President & Chief Executive Officer January 23, 2004	Group Vice President & Chief Financial Officer

42     Management’s Report

Auditors’ Report

To the Shareholders of Enbridge Inc.

We have audited the consolidated statements of financial position of Enbridge Inc. as at December 31, 2003 and 2002 and the consolidated statements of earnings, retained earnings and cash flows for each of the years in the three year period ended December 31, 2003. These financial statements are the responsibility of the Corporation’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with Canadian generally accepted auditing standards. Those standards require that we plan and perform an audit to obtain reasonable assurance whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation.

In our opinion, these consolidated financial statements present fairly, in all material respects, the financial position of the Company as at December 31, 2003 and 2002 and the results of its operations and cash flows for each of the years in the three year period ended December 31, 2003 in accordance with Canadian generally accepted accounting principles.

Calgary, Alberta, Canada	Chartered Accountants
January 23, 2004

Comments by Auditors for U.S. Readers on Canada-U.S. Reporting Difference

In the United States, reporting standards for auditors require the addition of an explanatory paragraph (following the opinion paragraph) when there is a change in accounting principles that has a material effect on the comparability of the Corporation’s financial statements, such as the changes in stock-based compensation and accounting for goodwill described in Note 1 to the consolidated financial statements. Our report to the shareholders dated January 23, 2004 is expressed in accordance with Canadian reporting standards which do not require a reference to such a change in accounting principles in the auditors’ report when the change is properly accounted for and adequately disclosed in the financial statements.

Calgary, Alberta, Canada	Chartered Accountants
January 23, 2004

Auditors’ Report     43

Consolidated Statements Of Earnings

(millions of Canadian dollars, except per share amounts)
Year ended December 31,	2003			2002			2001
Revenues
Gas sales		3,061.7			2,987.7			2,675.3
Transportation		1,560.6			1,296.6			1,177.6
Energy services		233.0			263.2			228.0
		4,855.3			4,547.5			4,080.9
Expenses
Gas costs		2,720.1			2,578.0			2,202.8
Operating and administrative		800.8			834.1			739.1
Depreciation		443.0			403.9			392.5
Writedown of Enbridge Midcoast Energy assets (Note 3)		–			122.7			–
		3,963.9			3,938.7			3,334.4
Operating Income		891.4			608.8			746.5
Investment and Other Income (Note 18)		208.2			283.1			194.9
Gain on Sale of Assets to Enbridge Income Fund (Note 3)		239.9			–			–
Interest Expense (Note 10)		(451.3	)		(422.0	)		(437.1	)
		888.2			469.9			504.3
Income Taxes (Note 16)		(187.4	)		(102.1	)		(66.7	)
Earnings From Continuing Operations		700.8			367.8			437.6
Earnings From Discontinued Operations (Note 5)		–			242.3			45.3
Earnings		700.8			610.1			482.9
Preferred Security Distributions (Note 12)		(26.7	)		(26.7	)		(17.5	)
Preferred Share Dividends (Note 13)		(6.9	)		(6.9	)		(6.9	)
Earnings Applicable to Common Shareholders		667.2			576.5			458.5
Earnings Applicable to Common Shareholders
Continuing Operations		667.2			334.2			413.2
Discontinued Operations		–			242.3			45.3
		667.2			576.5			458.5
Earnings Per Common Share (Note 13)
Continuing Operations		4.03			2.09			2.63
Discontinued Operations		–			1.51			0.28
		4.03			3.60			2.91
Diluted Earnings Per Common Share (Note 13)
Continuing Operations		4.00			2.06			2.60
Discontinued Operations		–			1.50			0.28
		4.00			3.56			2.88

Consolidated Statements Of Retained Earnings

(millions of Canadian dollars, except per share amounts)
Year ended December 31,	2003			2002			2001
Retained Earnings at Beginning of Year		1,128.1			812.3			581.3
Earnings Applicable to Common Shareholders		667.2			576.5			458.5
Effect of Change in Accounting for Stock-Based Compensation		–			(5.4	)		–
Preferred Securities Issue Costs		–			(4.2	)		–
Common Share Dividends		(283.9	)		(251.1	)		(227.5	)
Retained Earnings at End of Year		1,511.4			1,128.1			812.3
Dividends Paid Per Common Share		1.66			1.52			1.40

The accompanying notes to the consolidated financial statements are an integral part of these statements.

44     Consolidated Statements Of Earnings

Consolidated Statements Of Cash Flows

(millions of Canadian dollars)
Year ended December 31,	2003			2002			2001
Cash Provided By Operating Activities
Earnings from continuing operations		700.8			367.8			437.6
Charges/(credits) not affecting cash
Depreciation		443.0			403.9			392.5
Equity less than/(in excess of) cash distributions		(22.1	)		(44.6	)		1.2
Gain on sale of assets to Enbridge Income Fund		(239.9	)		–			–
Gain on reduction of ownership interest		(50.0	)		(10.0	)		(23.4	)
Gain on sale of securities		–			(21.4	)		–
Writedown of EGD regulatory receivable		26.0			–			–
Writedown of Enbridge Midcoast Energy assets		–			122.7			–
Future income taxes		85.8			(64.7	)		3.4
Other		21.4			(21.0	)		(75.6	)
Changes in operating assets and liabilities (Note 19)		(569.8	)		151.6			(323.1	)
Cash provided by operating activities of discontinued operations		–			26.3			1.9
		395.2			910.6			414.5
Investing Activities
Acquisitions (Note 4)		(78.3	)		(289.3	)		(599.1	)
Long-term investments		(50.5	)		(1,282.7	)		(41.8	)
Additions to property, plant and equipment		(391.3	)		(729.9	)		(683.3	)
Proceeds on redemption of Enbridge Commercial
Trust preferred units (Note 8)		24.9			–			–
Sale of assets to Enbridge Income Fund (Note 3)		331.2			–			–
Sale of Energy Services business (Note 5)		–			993.3			–
Sale of Enbridge Midcoast Energy assets (Note 3)		–			529.3			–
Sale of securities and other assets		–			184.3			–
Repayments by/(loans to) affiliate		427.2			358.1			(280.6	)
Changes in construction payable		(3.7	)		(14.8	)		(14.0	)
Other		–			–			(2.9	)
		259.5			(251.7	)		(1,621.7	)
Financing Activities
Net change in short-term borrowings and short-term debt		359.8			(1,180.9	)		1,521.4
Long-term debt issues		150.0			247.4			905.6
Long-term debt repayments		(725.0	)		(382.7	)		(979.6	)
Non-recourse long-term debt issued by joint ventures		538.3			–			–
Non-recourse long-term debt repaid by joint ventures		(663.8	)		–			–
Non-controlling interests		(4.0	)		0.2			(4.1	)
Preferred securities issued		–			193.5			–
Common shares issued		70.9			293.1			23.3
Enbridge Energy Management shares issued (Note 8)		–			421.9			–
Preferred security distributions		(26.7	)		(26.7	)		(17.5	)
Preferred share dividends		(6.9	)		(6.9	)		(6.9	)
Common shares dividends		(283.9	)		(251.1	)		(227.5	)
		(591.3	)		(692.2	)		1,214.7
Increase/(Decrease) in Cash		63.4			(33.3	)		7.5
Cash at Beginning of Year		40.7			74.0			66.5
Cash at End of Year		104.1			40.7			74.0

The accompanying notes to the consolidated financial statements are an integral part of these statements.

Consolidated Statements Of Cash Flows     45

Consolidated Statements Of Financial Position

(millions of Canadian dollars)
December 31,	2003			2002
Assets
Current Assets
Cash		104.1			40.7
Accounts receivable and other		1,138.8			817.5
Gas in storage		809.8			583.8
		2,052.7			1,442.0
Property, Plant and Equipment, net (Note 6)		8,530.9			6,947.6
Long-Term Investments (Note 8)		2,390.9			3,371.5
Receivable from Affiliate		169.8			701.5
Deferred Amounts and Other Assets (Note 9)		486.5			315.8
Future Income Taxes (Note 16)		192.5			209.0
		13,823.3			12,987.4
Liabilities And Shareholders’ Equity
Current Liabilities
Short-term borrowings		649.6			247.5
Accounts payable and other		894.1			714.1
Interest payable		97.0			102.6
Current maturities and short-term debt (Note 10)		674.9			652.3
Current portion of non-recourse long-term debt (Note 11)		34.2			–
		2,349.8			1,716.5
Long-Term Debt (Note 10)		5,243.1			6,040.3
Non-Recourse Long-Term Debt (Note 11)		752.4			–
Future Income Taxes (Note 16)		829.0			837.4
Non-Controlling Interests (Note 8)		523.0			560.8
		9,697.3			9,155.0
Shareholders’ Equity
Share capital
Preferred securities (Note 12)		532.4			533.7
Preferred shares (Note 13)		125.0			125.0
Common shares (Note 13)		2,239.9			2,169.0
Retained earnings		1,511.4			1,128.1
Foreign currency translation adjustment		(147.0	)		12.3
Reciprocal shareholding (Note 8)		(135.7	)		(135.7	)
		4,126.0			3,832.4
Commitments and Contingencies (Note 21)
		13,823.3			12,987.4

The accompanying notes to the consolidated financial statements are an integral part of these statements.

Approved by the Board:

Donald J. Taylor	Robert W. Martin
Chair	Director

46     Consolidated Statements Of Financial Position

Notes to the Consolidated Financial Statements

Enbridge Inc. (Enbridge or the Company) is a leader in the transportation and distribution of energy. Enbridge conducts its business through five operating segments: Liquids Pipelines, Gas Pipelines, Sponsored Investments, Gas Distribution and Services, and International. These operating segments are strategic business units established by senior management to facilitate the achievement of the Company’s long-term objectives, to aid in resource allocation decisions and to assess operational performance.

Liquids Pipelines

Liquids Pipelines includes the operation of common carrier and feeder pipelines that transport crude oil and other liquid hydrocarbons.

Gas Pipelines

Gas Pipelines includes proportionately consolidated investments in transmission pipelines that transport natural gas.

Sponsored Investments

Sponsored Investments consists of the Company’s investments in Enbridge Energy Partners, L.P. (EEP), Enbridge Energy Management, L.L.C. (EEM), (collectively, the Partnership) and Enbridge Income Fund (EIF). The Partnership transports crude oil and other liquid hydrocarbons through common carrier and feeder pipelines and transports, gathers, processes and markets natural gas and natural gas liquids. From May 2001 to October 2002, the Company, through its subsidiary, Enbridge Pipelines Inc., owned 100% of Enbridge Midcoast Energy Inc., which is now a wholly owned subsidiary of EEP. Enbridge Income Fund is a publicly traded income fund whose primary operations include a 50% interest in a gas transmission pipeline and a 100% interest in a crude oil and liquids pipeline and gathering system.

Gas Distribution and Services

Gas Distribution and Services consists of gas utility operations which serve residential, commercial, industrial and transportation customers, primarily in central and eastern Ontario. It also includes natural gas distribution activities in Quebec, New Brunswick and New York State, as well as gas service operations, including the Company’s proportionately consolidated investment in Aux Sable and natural gas gathering and processing operations through an equity investment in AltaGas Services Inc.

International

The Company’s International business invests in energy transportation and related energy projects outside of Canada and the United States. This business also provides consulting and training services related to proprietary pipeline operating technologies and natural gas distribution.

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

The consolidated financial statements of the Company are prepared in accordance with Canadian generally accepted accounting principles (Canadian GAAP). These accounting principles are different in some respects from United States generally accepted accounting principles (U.S. GAAP) and the significant differences that impact the Company’s financial statements are described in Note 22. Amounts are stated in Canadian dollars unless otherwise noted.

The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, as well as the disclosure of contingent assets and liabilities in the financial statements. Actual results could differ from these estimates.

Basis of Presentation

The consolidated financial statements include the accounts of Enbridge Inc., its subsidiaries and its proportionate share of the accounts of joint ventures. Investments in entities which are not subsidiaries or joint ventures, but over which the Company exercises significant influence, are accounted for using the equity method. Other investments are accounted for at cost.

Notes to the Consolidated Financial Statements     47

The Company’s gas distribution activities within the Gas Distribution and Services segment are conducted primarily through a wholly-owned subsidiary, Enbridge Gas Distribution Inc. (Enbridge Gas). The fiscal year-end of Enbridge Gas is September 30 and its results are consolidated on a one quarter lag basis, which reflects the results of Enbridge Gas operations in accordance with its regulatory, tax and operating cycles. Accordingly, references to “December 31” mean the financial position of Enbridge Gas as at September 30 and references to the “year ended December 31” mean the results of Enbridge Gas for the year ended September 30. Events subsequent to September 30 may provide additional information relating to items included in the financial statements of Enbridge Gas and may reveal conditions existing at the financial statement date that affect the estimates involved in the preparation of the financial statements. All such information that becomes available prior to completion of the Enbridge Inc. consolidated financial statements would be used in evaluating the estimates made and the financial statements would be adjusted where necessary.

Regulation

The Company’s Liquids Pipelines, Gas Pipelines, and gas distribution activities within the Gas Distribution and Services segment are subject to regulation by various authorities, including the National Energy Board (NEB), the Federal Energy Regulatory Commission (FERC), and the Ontario Energy Board (OEB). Regulatory bodies exercise statutory authority over matters such as construction, rates and underlying accounting practices, and ratemaking agreements with customers. In order to recognize the economic effects of the actions of the regulator, the timing of recognition of certain revenues and expenses in these operations may differ from that otherwise expected under generally accepted accounting principles.

Revenue Recognition

Revenues are recorded when products have been delivered or services have been performed. Certain of the Liquids Pipelines, Gas Pipelines, and gas distribution operations within the Gas Distribution and Services segment are subject to regulation and, accordingly, there are circumstances where revenues recognized do not match the cash tolls or the billed amounts. For rate-regulated operations, revenue is recognized in a manner that is consistent with the underlying rate design as mandated by the regulatory authority. Certain other operations recognize revenue under the terms of enforceable, committed long-term delivery contracts.

Income Taxes

The regulated activities of the Company recover income tax expense based on the taxes payable method when prescribed by regulators for ratemaking purposes or when stipulated in ratemaking agreements. Therefore, rates do not include the recovery of future income taxes related to temporary differences. Consequently, the taxes payable method is followed for accounting purposes as there is reasonable expectation that all future income taxes will be recovered in rates when they become payable.

For all other operations, the liability method of accounting for income taxes is followed. Future income tax assets and liabilities are determined based on temporary differences between the tax bases of assets and liabilities and their carrying values for accounting purposes. Future income tax assets and liabilities are measured using the tax rate that is expected to apply when the temporary differences reverse.

Foreign Currency Translation

The functional currency of the Company’s foreign operations, except for certain financing and investing operations, is the U.S. dollar. The Company also holds a Euro dollar equity investment in a foreign operation in Spain. These operations, which include those of proportionately consolidated U.S. dollar investments and the Euro dollar equity investment, are self-sustaining and are translated into Canadian dollars using the current rate method. Under this method, assets and liabilities are translated using period-end exchange rates, with revenues and expenses translated using average rates for the period. Gains and losses arising on translation of these operations are included as a separate component of shareholders’ equity.

48     Notes to the Consolidated Financial Statements

The remaining foreign operations of the Company, including certain financing and investing operations, are integrated with those of the parent company and are translated into Canadian dollars using the temporal method. Under this method, monetary assets and liabilities denominated in foreign currencies are translated at exchange rates in effect at the balance sheet date. Non-monetary assets and liabilities denominated in foreign currencies are translated at exchange rates in effect on the dates the assets were acquired or liabilities were assumed. Revenues and expenses are translated at rates of exchange prevailing on the transaction dates. Under this method, gains and losses on translation are reflected in income when incurred.

Cash

Cash includes short-term and demand deposits with a term to maturity of three months or less when purchased and are recorded at cost.

Gas in Storage

Natural gas in storage is recorded in inventory at prices approved by the OEB in the determination of customer sales rates. The actual price of gas purchased may differ from the OEB-approved price and includes the effect of natural gas price risk management activities. The difference between the approved price and the actual cost of the gas purchased is deferred for future disposition by the OEB.

Property, Plant and Equipment

Expenditures for system expansion and major renewals and betterments are capitalized; maintenance and repair costs are expensed as incurred. Interest during the construction period is capitalized. Regulated operations capitalize an allowance for interest during construction and, if approved, an allowance for equity funds used during construction, at rates authorized by the regulatory authorities.

Depreciation

Depreciation of property, plant and equipment generally is provided on a straight-line basis over the estimated service lives of the assets.

Future Removal and Site Restoration Costs

Future removal and site restoration costs are not determinable due to the indeterminable life of certain assets. Accordingly, no provision has been made for these costs. There is also reasonable expectation that any costs incurred will be recovered through future tolls when they become payable.

Depreciation expense for Gas Distribution and Services operations includes a provision for future removal and site restoration costs at rates approved by the regulator. Actual costs incurred are charged to accumulated depreciation.

Deferred Amounts

The Company defers certain charges which the regulatory authorities permit to be recovered through future rates. These charges are recognized when regulatory approval for these recoveries has been received. Other deferred charges are amortized straight-line over various periods depending on the nature of the charges and include long-term financing and hedging costs which are amortized over the terms of the related debt or hedge agreements.

Goodwill

Goodwill represents the excess of the purchase price over the fair value of net identifiable assets upon acquisition of a business. Effective January 1, 2002, the Company adopted the standard of the Canadian Institute of Chartered Accountants (CICA) related to goodwill and other intangible assets. Under the standard, goodwill is not amortized but is tested for impairment at least annually and written down to fair value if the criteria for impairment are met. The standard has been applied prospectively.

Notes to the Consolidated Financial Statements     49

Goodwill arising from the acquisition of Midcoast Energy Resources, Inc. in May 2001 (sold to EEP in October 2002) was amortized on a straight-line basis over 30 years prior to the adoption of the new standard. Results of operations for the year ended December 31, 2001 included goodwill amortization of $7.2 million. This amortization reduced both earnings per common share and diluted earnings per common share by $0.05 for the year ended December 31, 2001.

Derivative Financial Instruments

Gains and losses on financial instruments used to hedge the Company’s net investment in foreign operations are included in the foreign currency translation adjustment in shareholders’ equity. Amounts received or paid related to derivative financial instruments used to hedge the currency risk of cash flows from foreign currency denominated transactions are recognized concurrently with the hedged cash flows. Amounts received or paid related to derivative financial instruments used to hedge the price of energy commodities are recognized as part of the cost of the underlying physical purchases. For other derivative financial instruments used for hedging purposes, amounts received or paid, including any gains and losses realized upon settlement, are recognized over the term of the hedged item.

The Company applies settlement accounting to derivative financial instruments. Under this method, gains and losses on derivative instruments that qualify for hedge accounting are not recorded until they are realized. The notional amounts are not recorded in the financial statements as they do not represent amounts exchanged by the counterparties.

Post-Employment Benefits

The Company maintains pension plans which provide defined benefit and defined contribution pension benefits. Pension costs and obligations for the defined benefit pension plans are determined using the projected benefit method and are charged to earnings as services are rendered, except for the regulated operations of the Gas Distribution and Service segment where contributions made to the plan are expensed as paid, consistent with the recovery of such costs in rates. For the defined contribution plans, contributions made by the Company are expensed.

The Company also provides post-employment benefits other than pensions, including group health care and life insurance benefits for eligible retirees, their spouses and qualified dependants. The cost of such benefits is accrued during the years employees render service, except for the regulated operations of the Gas Distribution and Services segment where the cost of providing these benefits is expensed as paid, consistent with the recovery of such costs in rates.

Stock-Based Compensation

Effective January 1, 2002, the Company adopted the CICA standard for stock-based compensation. The standard required retroactive application for certain stock compensation awards as a charge to opening retained earnings without restatement of prior periods. Upon adoption, a charge to opening retained earnings of $5.4 million was recorded relating to outstanding stock appreciation rights, which expire in 2004.

Effective January 1, 2003, the Company early adopted new requirements in the CICA standard for stock-based compensation. The standard now requires the Company to apply the fair value based method of accounting for all awards granted. This method has been applied on a prospective basis and has resulted in a charge to income, in the year of adoption, of $1.9 million.

Comparative Amounts

Certain comparative amounts have been restated to conform with the current year’s financial statement presentation.

50     Notes to the Consolidated Financial Statements

New Accounting Standards

Impairment of Long-lived Assets

A new standard is in effect, for fiscal years beginning on or after April 1, 2003, for recognizing, measuring and disclosing impairment of long-lived assets held for use. The standard requires that an impairment loss be recognized in an amount equal to the difference between carrying value and fair value when the carrying value of a long-lived asset exceeds the expected undiscounted future cash flows. A recoverability test will be performed on asset groups as events or circumstances change in order to determine whether or not the assets are impaired. The Company is currently assessing the impact of the standard, if any, on its financial statements, and will adopt the standard for the fiscal year commencing January 1, 2004.

Hedging Relationships

A new guideline is in effect, for fiscal years beginning on or after July 1, 2003, for identifying, designating and documenting hedge relationships, and assessing their effectiveness. The guideline provides parameters on the conditions necessary for hedge accounting to be applied, but does not specify the methods to be used in its application. The guideline, however, does require that the Company adopt an accounting policy for assessing the effectiveness of its hedge relationships. Any ineffectiveness is to be recognized in income for the period. The Company is currently assessing the impact of the guideline, if any, on its financial statements, and will adopt the guideline for the fiscal year commencing January 1, 2004.

Generally Accepted Accounting Principles

A new standard is in effect, for all fiscal years beginning on or after October 1, 2003, for identifying appropriate sources of generally accepted accounting principles, and the doctrines that constitute generally accepted accounting principles. Any changes to accounting policies resulting from the adoption of this standard are to be applied prospectively. At present, the standard has an exemption for rate-regulated operations. The Company is currently assessing the impact of this standard and its related exemption, if any, on the financial statements.

Asset Retirement Obligations

A new standard is in effect, for fiscal years beginning on or after January 1, 2004, for recognizing, measuring and disclosing liabilities for asset retirement obligations and the associated asset retirement costs. A similar standard has been adopted by the Financial Accounting Standards Board in the United States, effective for fiscal years beginning after June 15, 2002. This new standard is not expected to have a material impact on the Company’s financial statements.

Consolidation of Variable Interest Entities

A new guideline is in effect, for all annual and interim periods beginning on or after November 1, 2004, for applying consolidation principles to entities subject to control on a basis other than through ownership of voting interests. A similar standard has been adopted by the Financial Accounting Standards Board in the United States (FIN 46), effective for interim periods commencing after July 15, 2003. If the interpretation of the Canadian standard is consistent with FIN 46, it would result in the consolidation of Enbridge Income Fund as described in Note 22.

Notes to the Consolidated Financial Statements     51

2. SEGMENTED INFORMATION

Year ended December 31, 2003

										Gas
	Liquids			Gas			Sponsored			Distribution
(millions of dollars)	Pipelines			Pipelines			Investments			& Services			International			Corporate1			Consolidated
Revenues		821.5			222.1			–			3,785.4			26.2			0.1			4,855.3
Gas costs		–			–			–			(2,720.1	)		–			–			(2,720.1	)
Operating and administrative		(288.8	)		(41.2	)		–			(415.9	)		(30.5	)		(24.4	)		(800.8	)
Depreciation		(142.6	)		(56.7	)		–			(237.6	)		(2.0	)		(4.1	)		(443.0	)
Operating income/(loss)		390.1			124.2			–			411.8			(6.3	)		(28.4	)		891.4
Investment and other income/(expense)		3.4			36.6			113.1			19.8			78.1			(42.8	)		208.2
Gain on sale of assets		–			–			239.9			–			–			–			239.9
Interest and preferred equity charges		(102.1	)		(58.7	)		–			(162.2	)		(0.5	)		(161.4	)		(484.9	)
Income taxes		(77.9	)		(32.0	)		(118.7	)		(115.8	)		1.0			156.0			(187.4	)
Earnings/(loss) applicable to common shareholders		213.5			70.1			234.3			153.6			72.3			(76.6	)		667.2

Year ended December 31, 2002

										Gas
	Liquids			Gas			Sponsored			Distribution
(millions of dollars)	Pipelines			Pipelines			Investments			& Services			International			Corporate1			Consolidated
Revenues		787.7			–			1,219.0			2,513.5			27.2			0.1			4,547.5
Gas costs		–			–			(1,051.4	)		(1,526.6	)		–			–			(2,578.0	)
Operating and administrative		(282.5	)		–			(109.5	)		(410.4	)		(19.0	)		(12.7	)		(834.1	)
Depreciation		(150.6	)		–			(17.3	)		(229.5	)		(2.9	)		(3.6	)		(403.9	)
Writedown of Enbridge Midcoast Energy Assets		–			–			(122.7	)		–			–			–			(122.7	)
Operating income/(loss)		354.6			–			(81.9	)		347.0			5.3			(16.2	)		608.8
Investment and other income		4.8			66.3			44.8			32.1			64.0			71.1			283.1
Interest and preferred equity charges		(99.8	)		–			(28.1	)		(161.7	)		(1.6	)		(164.4	)		(455.6	)
Income taxes		(70.0	)		(18.5	)		14.1			(93.1	)		0.3			65.1			(102.1	)
Earnings/(loss) applicable to common shareholders		189.6			47.8			(51.1	)		124.3			68.0			(44.4	)		334.2
Earnings from discontinued operations																				242.3
Earnings applicable to common shareholders																				576.5

52     Notes to the Consolidated Financial Statements

Year ended December 31, 2001

										Gas
	Liquids			Gas			Sponsored			Distribution
(millions of dollars)	Pipelines			Pipelines			Investments			and Services			International			Corporate1			Consolidated
Revenues		722.9			–			681.5			2,645.7			30.8			–			4,080.9
Gas costs		–			–			(558.9	)		(1,643.9	)		–			–			(2,202.8	)
Operating and administrative		(258.7	)		–			(53.3	)		(392.0	)		(19.0	)		(16.1	)		(739.1	)
Depreciation		(139.8	)		–			(24.1	)		(223.3	)		(2.5	)		(2.8	)		(392.5	)
Operating income/(loss)		324.4			–			45.2			386.5			9.3			(18.9	)		746.5
Investment and other income		13.7			57.8			43.1			5.5			27.0			47.8			194.9
Interest and preferred equity charges		(106.0	)		(0.1	)		(26.2	)		(162.4	)		(0.1	)		(166.7	)		(461.5	)
Income taxes		(67.7	)		(16.2	)		(24.9	)		(40.0	)		(0.6	)		82.7			(66.7	)
Earnings/(loss) applicable to common shareholders		164.4			41.5			37.2			189.6			35.6			(55.1	)		413.2
Earnings from discontinued operations																				45.3
Earnings applicable to common shareholders																				458.5

1 Corporate includes new business development activities and investing and financing activities, including general corporate investments and financing costs not allocated to the business segments.

2 The measurement basis for preparation of segmented information is consistent with the significant accounting policies described in Note 1.

3 Segmented information of all years is restated consistent with the change in segments in the fourth quarter of 2003.

Total Assets

(millions of dollars)
December 31,	2003		2002
Liquids Pipelines		3,406.0		3,468.5
Gas Pipelines		1,649.7		1,243.8
Sponsored Investments		1,396.3		850.8
Gas Distribution and Services		6,156.4		5,543.0
International		835.7		830.7
Corporate		379.2		1,050.6
		13,823.3		12,987.4

Additions to Property, Plant and Equipment

(millions of dollars)
Year ended December 31,	2003		2002		2001
Liquids Pipelines		123.4		255.7		216.8
Gas Pipelines		11.3		–		–
Sponsored Investments		–		128.9		85.2
Gas Distribution and Services		249.0		315.0		314.1
International and Corporate		7.6		7.4		23.7
		391.3		707.0		639.8
Discontinued Operations		–		22.9		43.5
		391.3		729.9		683.3

Notes to the Consolidated Financial Statements     53

2. SEGMENTED INFORMATION (continued)

Geographic Information

Revenues¹

(millions of dollars)
Year ended December 31,	2003		2002		2001
Canada		3,739.4		3,102.3		3,317.7
United States		1,089.6		1,418.0		736.8
Other		26.3		27.2		26.4
		4,855.3		4,547.5		4,080.9

1 Revenues are attributed to countries based on the country of origin of the product or services sold.

Property, Plant and Equipment

(millions of dollars)
December 31,	2003		2002
Canada		6,747.3		6,733.6
United States		1,776.6		204.8
Other		7.0		9.2
		8,530.9		6,947.6

3. DISPOSITIONS

Alliance Pipeline Canada and Enbridge Pipelines (Saskatchewan) Inc.

On June 30, 2003, the Company formed EIF, an unincorporated open-ended trust established under the laws of Alberta. On formation, the Company sold its 50% interest in the Canadian segment of the Alliance Pipeline together with its 100% interest in Enbridge Pipelines (Saskatchewan) Inc. to EIF for total proceeds of $905.0 million before working capital adjustments of $20.6 million and transaction costs of $0.2 million. The Company recorded an after-tax gain on the sale of $169.1 million. Enbridge’s net investment in Alliance Canada was $333.6 million at December 31, 2002 and was classified as a long-term investment. The net assets of Enbridge Pipelines (Saskatchewan) Inc. consist primarily of property, plant and equipment and comprised $86.5 million of Enbridge Inc.’s total property, plant and equipment balance at December 31, 2002.

Enbridge Midcoast Energy

In October 2002, the Company closed the sale of the United States assets of Enbridge Midcoast Energy to EEP, including the Northeast Texas assets described in Note 4. The book value of the assets was written down by $82.2 million, after tax, to reflect fair value based on the proceeds of $1,289.3 million. The Company received cash proceeds of approximately $529.3 million with the remaining consideration in the form of assumed affiliate debt.

4. ACQUISITIONS

Cushing to Chicago Pipeline System

In September 2003, the Company acquired 90% of the outstanding shares of CCPS Transportation L.L.C., owner of the Cushing to Chicago Pipeline System. Of the total purchase price, $78.3 million was paid on the date of acquisition. Payment of the remaining US$65.0 million depends upon completion of reversal of the flow of the pipeline and must be paid no later than December 31, 2004 to allow reversal to proceed. The acquisition was accounted for using the purchase method and the results of operations have been included in the consolidated statement of earnings from the date of acquisition. The amount paid was allocated to property, plant and equipment.

54     Notes to the Consolidated Financial Statements

Northeast Texas

In March 2002, the Company acquired natural gas gathering and processing facilities in Northeast Texas for cash consideration of $289.3 million. These assets are included in the sale described in Note 3. The results of operations have been included in the consolidated statement of earnings for the period of ownership.

(millions of dollars)
Fair Value of Assets Acquired
Property, plant and equipment	242.3
Goodwill	56.2
Working capital deficiency	(9.2	)
	289.3
Purchase Price
Cash	288.2
Transaction costs	1.1
	289.3

Midcoast Energy Resources, Inc.

On May 11, 2001, the Company acquired all the outstanding shares of Midcoast Energy Resources, Inc., a Houston-based energy company, for cash consideration of $561.8 million and the assumption of long-term debt. This business is included in the sale described in Note 3. The acquisition was accounted for using the purchase method and the results of operations have been included in the consolidated statements of earnings from the date of acquisition until they were sold in October 2002.

(millions of dollars)
Fair Value of Assets Acquired
Property, plant and equipment	677.3
Working capital deficiency	(37.2	)
Goodwill	328.9
Future income taxes	(39.0	)
Other non-current assets	37.8
	967.8
Purchase Price
Cash	554.5
Long-term debt assumed	406.0
Transaction costs	7.3
	967.8

Frontier Pipeline Company

The Company acquired an additional 34.0% interest in Frontier Pipeline Company for $46.0 million in December 2001, increasing the Company’s ownership to 77.8%. The purchase price was allocated primarily to property, plant and equipment.

Notes to the Consolidated Financial Statements     55

5. DISCONTINUED OPERATIONS

The sale of the Company’s operations that provide energy products and services to retail and commercial customers, including the water heater rental program, closed in May 2002.

Selected financial information related to discontinued operations is as follows.

Earnings

(millions of dollars)
Year ended December 31,	2002		2001
Gain on disposition, net of tax		240.0		–
Earnings		2.3		45.3
Earnings from discontinued operations		242.3		45.3

Selected Earnings Information

(millions of dollars)
Year ended December 31,	2002		2001
Revenues		181.9		463.0
Income tax expense		34.6		2.5
Allocated interest expense		12.1		35.4

6. PROPERTY, PLANT AND EQUIPMENT

(millions of dollars)	Weighted Average					Accumulated
December 31, 2003	Depreciation Rate			Cost		Depreciation		Net
Liquids Pipelines
Pipeline		2.4	%		2,453.5		1,038.0		1,415.5
Pumping Equipment, Buildings, Tanks and Other		3.9	%		2,215.0		690.7		1,524.3
Land and Right-of-Way		1.9	%		34.1		16.0		18.1
Under Construction		—			47.0		—		47.0
					4,749.6		1,744.7		3,004.9
Gas Pipelines
Pipeline		3.7	%		1,544.4		196.6		1,347.8
Land and Right-of-Way		2.9	%		36.6		4.5		32.1
Metering and Other		2.9	%		85.6		11.6		74.0
Under Construction		—			6.4		—		6.4
					1,673.0		212.7		1,460.3
Gas Distribution and Services
Gas Mains		4.3	%		1,866.4		320.2		1,546.2
Gas Services		4.5	%		1,811.1		370.1		1,441.0
Regulating and Metering Equipment		3.7	%		581.9		106.2		475.7
Storage		2.7	%		283.1		40.7		242.4
Computer Technology		8.0	%		124.1		74.5		49.6
Other		5.4	%		325.6		58.4		267.2
					4,992.2		970.1		4,022.1
Other		6.6	%		66.7		23.1		43.6
					11,481.5		2,950.6		8,530.9

56      Notes to the Consolidated Financial Statements

(millions of dollars)	Weighted Average					Accumulated
December 31, 2002	Depreciation Rate			Cost		Depreciation		Net
Liquids Pipelines
Pipeline		2.5	%		2,489.7		1,030.0		1,459.7
Pumping Equipment, Buildings, Tanks and Other		4.2	%		2,166.1		711.6		1,454.5
Land and Right-of-Way		1.7	%		34.3		16.0		18.3
Under Construction		—			92.7		—		92.7
					4,782.8		1,757.6		3,025.2
Gas Distribution and Services
Gas Mains		3.0	%		1,758.1		236.1		1,522.0
Gas Services		4.3	%		1,682.3		287.3		1,395.0
Regulating and Metering Equipment		3.6	%		551.5		81.4		470.1
Storage		2.7	%		268.8		30.3		238.5
Computer Technology		25.0	%		150.5		141.2		9.3
Other		4.0	%		293.5		48.5		245.0
					4,704.7		824.8		3,879.9
Other		6.6	%		61.1		18.6		42.5
					9,548.6		2,601.0		6,947.6

7. JOINT VENTURE

Alliance Pipeline Canada, Alliance Pipeline U.S., Aux Sable, and Alliance Canada Marketing, have been jointly controlled since April 1, 2003. Vector Pipeline Canada, and Vector Pipeline U.S. have been jointly controlled since October 1, 2003. The Company’s proportionate share of earnings, cash flows and financial position related to these entities is summarized below, with the exception of Alliance Pipeline Canada for the period subsequent to June 30, 2003 as the Company’s 50% interest in Alliance Pipeline Canada was sold effective June 30, 2003 to EIF.

	April 1, 2003
(millions of dollars)	to December 31, 2003
Earnings
Revenues		421.7
Gas sales		(168.1	)
Operating and administrative		(81.5	)
Depreciation		(59.7	)
Interest expense		(59.7	)
Investment and other income		5.1
Income taxes		0.3
Proportionate share of net earnings		58.1
Cash Flows
Cash provided by operations		99.4
Cash provided by investing activities		(1.4	)
Cash used in financing activities		(197.7	)
Proportionate share of decrease in cash		(99.7	)

Notes to the Consolidated Financial Statements      57

7. JOINT VENTURE (continued)

(millions of dollars)	December 31, 2003
Financial Position
Current assets		118.7
Property, plant and equipment, net		1,562.2
Other long-term assets		102.9
Current liabilities		(122.6	)
Long-term debt		(752.4	)
Other long-term liabilities		(17.8	)
Proportionate share of net assets		891.0

Included in the Company’s proportionate share of cash from joint ventures is $18.7 million held in trust, pursuant to finance agreements of the joint venture. Under these finance agreements, funds received from shippers, in settlement of transportation rates, as well as interest earned on trust account balances, are segregated in trust accounts and first applied to meet debt service and operating requirements. Amounts in excess of these requirements are transferred to a non-trust account for partnership distributions on a quarterly basis.

8. LONG-TERM INVESTMENTS

(millions of dollars)
December 31,	Ownership Interest			2003		2002
Equity Investments
Liquids Pipelines
Chicap Pipeline		22.8	%		25.0		32.4
Gas Pipelines
Alliance Pipeline Canada		—			—		333.6
Alliance Pipeline U.S.		—			—		345.0
Vector Pipeline		—			—		474.8
					—		1,153.4
Sponsored Investments
The Partnership		12.2	%		743.6		815.5
Enbridge Income Fund		41.9	%		—		—
					743.6		815.5
Gas Distribution and Services
AltaGas Services		40.3	%		210.7		204.2
Noverco		32.1	%		36.7		28.9
Aux Sable		—			—		135.0
Other					16.0		14.0
					263.4		382.1
International
Compañía Logistica de Hidrocarburos (CLH)		25.0	%		531.2		541.2
Corporate					17.8		17.2
Cost Investments
Sponsored Investments
Enbridge Income Fund					380.2		—
Gas Distribution and Services
Noverco					181.4		181.4
FuelCell Energy/Global Thermoelectric					25.0		25.0
					206.4		206.4
International
OCENSA Pipeline					223.3		223.3
					2,390.9		3,371.5

58      Notes to the Consolidated Financial Statements

Equity investments include $536.4 million (2002 – $551.9 million) representing the unamortized excess of the purchase price over the underlying net book value of the investee’s assets at the date of purchase. The excess has been allocated to property, plant and equipment on the basis of estimated fair values and is amortized over the economic life of the assets.

Alliance Pipeline, Aux Sable and Vector Pipeline

In 2003, the Company invested $223.2 million (2002 – $315.3 million) in Alliance and Aux Sable, increasing the Company’s interest from 37.1% to 50.0% in Alliance Pipeline Canada, 37.1% to 50% in Alliance Pipeline U.S. and 30.9% to 42.7% in Aux Sable. The purchase price was $36.9 million (2002 – ($7.1) million) less than the underlying net book value of the assets. This amount has been allocated to property, plant and equipment and is being amortized over the economic life of the assets.

On October 1, 2003 the Company invested $97.7 million in Vector, including the assumption of $61.5 million in debt, increasing the Company’s ownership interest from 45% to 60%. The purchase price was $36.3 million less than the underlying net book value of the assets. This amount has been allocated to property plant and equipment and is being amortized over the economic life of the assets.

As a result of these additional investments, the Company established joint control (see Note 7). Therefore, the Company’s interest in Alliance Pipeline Canada, Alliance Pipeline U.S., Aux Sable and Alliance Canada Marketing are accounted for as joint ventures effective April 1, 2003 and the Company’s interest in Vector Pipeline Canada and Vector Pipeline U.S. are accounted for as joint ventures effective October 1, 2003. On June 30, 2003, the Company sold its 50% interest in Alliance Pipeline Canada to Enbridge Income Fund.

The Partnership

In October 2002, EEM, a partially-owned subsidiary, completed an initial public offering of 9,000,000 limited liability shares. The proceeds from the offering were used to purchase I-units, a new class of limited partnership interest from EEP. The Company purchased 17.2% of the EEM shares, increasing its total net investment in the Partnership to 14.1% from 12.9%. Although 82.8% of EEM is widely held, the Company has voting control of EEM. The Company’s statement of financial position includes 100% of EEM’s investment in EEP which totals $478.8 million (2002 – $529.9 million). The Company’s net investment in the Partnership, after deducting the non-controlling interest of $396.4 million (2002 – $438.8 million), is $347.7 million (2002 – $376.7 million).

In 2003, EEP completed two public issuances of partnership units. As the Company elected not to participate in either of these offerings, its effective interest in EEP was reduced to 12.2% from 14.1%. This resulted in recognition of a total dilution gain of $20.3 million (2002 – $6.1 million), net of tax and minority interest.

Noverco

Noverco holds an approximate 10% reciprocal shareholding in the Company. As a result, the Company has a pro-rata interest of 3.2% (2002 – 3.2%) in its own shares. Both the equity investment in Noverco Inc. and shareholders’ equity have been reduced by the reciprocal shareholding of $135.7 million (2002 – $135.7 million).

The Company owns a cost investment in Noverco of $181.4 million (2002 – $181.4 million), which is entitled to a cumulative dividend based on the average yield of Government of Canada bonds maturing in more than 10 years plus 4.34%.

CLH

In 2002, the Company invested $430.8 million in CLH, a refined products transportation and storage company in Spain. The Company’s 25% interest is accounted for by the equity method. Contingent consideration of up to 84.3 million Euros ($137.2 million) will become payable over the next three years if certain minimum annual and cumulative volume targets are met. The purchase price included $340.9 million representing the excess of purchase price over the underlying net book value of the assets. The excess has been allocated to property, plant and equipment and is being amortized over the economic life of the assets.

Notes to the Consolidated Financial Statements      59

8. LONG-TERM INVESTMENTS (continued)

Enbridge Income Fund

On June 30, 2003, the Company formed EIF, an unincorporated open-ended trust established under the laws of Alberta. On formation, EIF acquired the Company’s 50% interest in the Canadian segment of the Alliance Pipeline together with its 100% interest in Enbridge Pipelines (Saskatchewan) Inc. The Company has 14,500,000 subordinated trust units of EIF and 38,023,750 preferred units of Enbridge Commercial Trust (ECT), a direct subsidiary of EIF, at December 31, 2003. The subordinated trust units result in a 41.9% common equity interest in EIF.

The Company’s $145.0 million initial investment in subordinated units of EIF was offset by a $145.0 million unrecognized gain resulting in a book value of nil. The unrecognized gain is being amortized into income over the life of the underlying assets of EIF and is included as a component of equity earnings.

The Company’s 38 million preferred units are accounted for as a $380.2 million cost investment at December 31, 2003. At the request of the Company, the ECT preferred units will be repurchased for cancellation in certain specified circumstances by ECT with a repurchase price per ECT preferred unit based on the net issue price realized from the sale (or that could be realized from the sale) of an ordinary trust unit to the public. The ECT preferred units have no voting rights and mature on June 30, 2033 at which time ECT is obligated to redeem all of the outstanding ECT preferred units for a price of ten dollars per unit. The economic terms of these units are comparable to those of ordinary common units. As such, the approximate fair value of these preferred units, valued at the December 31, 2003 closing price of $12.89 per ordinary common unit, is $490.1 million.

OCENSA Pipeline

The Company owns a cost investment in the OCENSA Pipeline of $223.3 million (2002 – $223.3 million) which earns a fixed rate of return. The fair value of this investment is approximately $270.0 million, estimated using year-end market information and various assumptions. As no market exists for an instrument of this nature, the actual fair value in an open market may vary significantly.

Income from Equity Investments

(millions of dollars)
Year ended December 31,	2003		2002		2001
Liquids Pipelines		1.1		1.0		8.5
Gas Pipelines		31.6		67.1		57.6
Sponsored Investments		73.3		40.9		23.3
Gas Distribution and Services		19.9		7.7		(9.7	)
International		45.7		34.2		0.3
Corporate		1.2		—		—
		172.8		150.9		80.0

Consolidated retained earnings at December 31, 2003 includes undistributed earnings from equity investments of $130.5 million (2002 – $148.7 million).

9. DEFERRED AMOUNTS AND OTHER ASSETS

(millions of dollars)
Year ended December 31,	2003		2002
Regulatory and contractual deferrals		232.9		159.6
Long-term portion of receivables from hedge counterparty		127.7		36.9
Deferred pension funding		66.3		72.7
Deferred financing charges		37.3		34.6
Other		22.3		12.0
		486.5		315.8

60      Notes to the Consolidated Financial Statements

At December 31, 2003, $105.1 million (2002 – $102.9 million) was subject to amortization. Amortization expense of deferred amounts in 2003 was $18.4 million (2002 – $21.7 million; 2001 – $23.5 million). Accumulated amortization at the end of 2003 was $38.9 million (2002 – $27.2 million).

10. DEBT

(millions of dollars)	Weighted Average
December 31,	Interest Rate			Maturity		2003		2002
Liquids Pipelines
Debentures		8.20	%		2024		200.0		300.0
Medium-term notes		6.66	%		2005-2029		622.7		622.5
Other1							58.7		58.8
Gas Distribution and Services
Debentures		11.00	%		2004-2024		635.0		635.0
Medium-term notes		6.34	%		2004-2032		1,030.0		1,105.0
Other							9.5		9.0
Corporate
Senior term notes2 (US$275.0 million)		8.08	%		2005-2007		397.8		397.8
Medium-term notes		6.14	%		2004-2032		1,790.0		1,788.7
Variable rate credit facility							—		400.0
Variable rate credit facility3							—		252.7
Preferred securities (Note 12)		7.79	%		2048-2051		17.6		16.3
Other4							1,156.7		1,106.8
Total Debt							5,918.0		6,692.6
Current maturities of long-term debt							450.0		225.0
Other short-term debt							224.9		427.3
Current Maturities and Short-Term Debt							674.9		652.3
Long-Term Debt							5,243.1		6,040.3

1	Primarily commercial paper borrowings.
2	The principal amount is recorded at the swapped rate.
3	2002 included US$160.0 million.
4	Primarily commercial paper borrowings. Includes US$306.0 million (2002 – US$582.5 million).

Short-term debt in the amount of $1,000.0 million (2002 – $1,000.0 million) is supported by the availability of long-term committed credit facilities and has been classified as long-term debt.

Long-term debt maturities for the years ending December 31, 2004 through 2008 are $450.0 million, $528.6 million, $440.0 million, $369.3 million and $220.0 million, respectively.

Interest Rate Management

				2003		2002
(millions of dollars)	Weighted Average
December 31,	Effective Rate			Notional Amounts
Liquids Pipelines
Commercial paper		6.04	%		25.4		25.4
Corporate
Senior term notes1		7.40	%	US$	275.0	US$	275.0
Variable rate debt		2.30	%		—		400.0

1 Subject to a cross-currency swap.

Notes to the Consolidated Financial Statements       61

10 . DEBT (continued)

The weighted average effective rate reflects the interest rate of debt instruments after giving effect to interest swap agreements.

Interest Expense

(millions of dollars)
December 31,	2003			2002			2001
Long-term debt		431.7			392.9			345.0
Commercial paper and other short-term debt		20.2			29.0			85.8
Short-term borrowings		9.6			9.6			12.2
Capitalized		(10.2	)		(9.5	)		(5.9	)
		451.3			422.0			437.1

In 2003, total interest paid was $467.1 million (2002 – $429.3 million; 2001 – $452.2 million).

Credit Facilities

(millions of dollars)
December 31, 2003	Committed		Uncommitted		Drawdowns
Liquids Pipelines		150.0		—		—
Gas Distribution and Services		659.0		6.5		14.5
Corporate		1,887.7		—		—
		2,696.7		6.5		14.5

Committed facilities carry a weighted average standby fee of 0.10% per annum on the unutilized portion. The committed facilities for Liquids Pipelines expire in 2004 and are extendible annually thereafter subject to the approval of lenders. The committed facilities for Gas Distribution and Services expire in 2004 and 2006 and are extendible annually thereafter subject to the approval of the lenders. The committed facilities for Corporate expire in 2004 and 2008 and are extendible annually thereafter subject to the approval of the lenders. Drawdowns under all of these facilities bear interest at prevailing market rates.

11 . NON-RECOURSE DEBT OF JOINT VENTURES

(millions of dollars)
December 31,	2003
Credit Facilities (US$21.7 million)		28.0
Senior Notes:
7.770% due 2015 (US$140.0 million)		180.9
6.996% due 2019 (US$153.4 million)		198.3
7.877% due 2025 (US$100.0 million)		129.2
4.591% due 2025 (US$146.2 million)		189.0
Obligations under capital leases (US$47.4 million)		61.2
		786.6
Less current portion of long-term debt (US$26.5 million)		(34.2	)
		752.4

The debt of joint ventures is non-recourse to Enbridge. Security provided by the joint ventures is limited to all of the rights and assets of the individual joint venture and does not extend to the rights and assets of Enbridge, except to the extent of Enbridge’s investment.

62      Notes to the Consolidated Financial Statements

The Senior Notes may be redeemed by Alliance Pipeline U.S. at any time, at a price equal to the outstanding principal plus accrued but unpaid interest and a make-whole premium. Alliance Pipeline U.S. may be required to redeem the Senior Notes, in whole or in part, from proceeds received under insurance claims for damages if the proceeds are not applied to repair or rebuild the Alliance pipeline system.

Interest on the Senior Notes is payable semi-annually. Principal repayments commenced June 30, 2001 on the 6.996% Senior Notes, December 31, 2001 on the 7.770% Senior Notes, June 30, 2003 on the 4.591% Senior Notes and commences June 30, 2019 on the 7.877% Senior Notes. Principal repayments are due semi-annually thereafter in each instance and are closely tied to the recovery rates for capital depreciation and deferred income taxes contained in the transportation agreements.

Long-term debt maturities on joint venture borrowings for the years ending December 31, 2004 through 2008 are $34.2 million, $32.0 million, $56.0 million, $37.6 million and $38.0 million, respectively.

12. PREFERRED SECURITIES

The Company has $175.0 million of 7.6%, $200 million of 7.8%, and $175.0 million of 8.0% Preferred Securities outstanding. The Preferred Securities may be redeemed at the Company’s option, in whole or in part, after the fifth anniversary of each issue and have no stated maturity date. The Company has the right to defer, subject to certain conditions, payments of distributions on the securities for up to 20 consecutive quarterly periods. Deferred and regular distribution amounts are payable in cash or, at the option of the Company, in common shares of the Company. As a result, the Preferred Securities are classified into their respective debt and equity components. The equity component of the Preferred Securities is $532.4 million at December 31, 2003 (2002 – $533.7 million).

13. SHARE CAPITAL

The authorized share capital of the Company consists of an unlimited number of common shares with no par value and an unlimited number of preferred shares.

Common Shares

(millions of dollars; number of common shares in millions) December 31,	2003				2002				2001
	Number				Number				Number
	of Shares		Amount		of Shares		Amount		of Shares		Amount
Balance at beginning of year		169.7		2,169.0		162.9		1,875.9		161.8		1,852.6
Dividend Reinvestment and Share Purchase Plan		0.4		17.1		0.2		8.3		0.2		7.2
Stock based compensation expense		—		1.9		—		—		—		—
Issued to Noverco		—		—		0.5		23.1		—		—
Public issue		—		—		5.0		225.4		—		—
Exercise of stock options and other		1.8		51.9		1.1		36.3		0.9		16.1
Balance at end of year		171.9		2,239.9		169.7		2,169.0		162.9		1,875.9

Preferred Shares

The 5,000,000 5.5% Cumulative Redeemable Preferred Shares, Series A are entitled to fixed, cumulative, preferential dividends of $1.375 per share per year, payable quarterly. Subsequent to December 31, 2003, the Company may, at its option, redeem all or a portion of the outstanding preferred shares for $26.00 per share if redeemed on or prior to December 1, 2004; $25.75 if redeemed on or prior to December 1, 2005; $25.50 if redeemed on or prior to December 1, 2006; $25.25 if redeemed on or prior to December 1, 2007; and $25.00 if redeemed thereafter, in each case with all accrued and unpaid dividends to the redemption date.

Notes to the Consolidated Financial Statements       63

13. SHARE CAPITAL (continued)

Earnings Per Common Share

Earnings per common share is calculated by dividing earnings applicable to common shareholders by the weighted average number of common shares outstanding. The weighted average number of shares outstanding has been reduced by the Company’s pro-rata weighted average interest in its own common shares of 5.3 million shares (2002 – 5.3 million shares), resulting from the investment in Noverco.

The treasury stock method, used for calculating diluted earnings per share, uses an adjusted weighted average number of common shares outstanding, which reflects the effect of exercising all dilutive securities.

(number of common shares in millions)
December 31,	2003		2002		2001
Weighted average shares outstanding		165.5		160.3		157.3
Effect of dilutive securities		1.4		1.7		1.5
Diluted weighted average shares outstanding		166.9		162.0		158.8

Dividend Reinvestment and Share Purchase Plan

Under the plan, registered shareholders may reinvest dividends in common shares of the Company or make optional cash payments to purchase additional common shares, in either case, free of brokerage or other charges.

Shareholder Rights Plan

The Shareholder Rights Plan is designed to encourage the fair treatment of shareholders in connection with any takeover offer for the Company. Rights issued under the plan become exercisable when a person, and any related parties, acquires or announces the intention to acquire 20% or more of the Company’s outstanding common shares without complying with certain provisions set out in the plan or without approval of the Board of Directors of the Company. Should such an acquisition or announcement occur, each rights holder, other than the acquiring person and related parties, will have the right to purchase common shares of the Company at a 50% discount to the market price at that time.

14. STOCK OPTION PLAN

The Company’s Incentive Stock Option Plan (2002) includes fixed stock options and performance-based stock options. A maximum of 15 million common shares is reserved for issuance under the plan.

Fixed Stock Options

Full-time, key employees are granted options to purchase common shares that are exercisable at the market price of common shares at the date the options are granted. Generally, options vest in equal annual installments over a four-year period and expire ten years after the issue date. Outstanding stock options expire over a period ending no later than February 6, 2013.

Outstanding Fixed Stock Options

(options in thousands; exercise price in dollars) December 31,	2003					2002					2001
				Weighted					Weighted					Weighted
				Average					Average					Average
				Exercise					Exercise					Exercise
	Number			Price		Number			Price		Number			Price
Options at beginning of year		5,042			32.16		5,120			29.06		4,112			26.76
Options granted		1,042			41.65		1,024			43.80		2,024			30.11
Options exercised		(1,244	)		26.64		(1,003	)		26.31		(843	)		19.27
Options cancelled or expired		(99	)		39.87		(99	)		37.59		(173	)		34.47
Options at end of year		4,741			35.96		5,042			32.16		5,120			29.06
Options vested		2,319					2,639					2,853

64       Notes to the Consolidated Financial Statements

Fixed Stock Option Characteristics

(options in thousands; exercise price in dollars)
December 31, 2003

Options Outstanding								Options Vested
				Weighted		Weighted				Weighted
				Average		Average				Average
Exercise				Remaining		Exercise				Exercise
Price Range		Number		Life (years)		Price		Number		Price
	10.30-19.99		117		1.72		14.70		117		14.70
	20.00-29.99		1,078		5.44		26.02		796		25.77
	30.00-39.99		1,564		5.76		35.95		1,165		35.22
	40.00-47.71		1,982		8.29		42.64		241		43.63
			4,741						2,319

Performance-based Options

The Plan provides for the grant of performance-based stock options to executive officers that become exercisable based on the performance of the Company’s common share price. Of the outstanding performance-based stock options as at December 31, 2003, 810,000 remain unexercisable and were granted September 16, 2002 at $46.30 per share. These performance-based stock options vest in equal annual installments over their five-year term and become exercisable, as to 50% of the grant, if the price on an Enbridge common share exceeds $61.00 for 20 consecutive trading days during the period September 16, 2002 to September 16, 2007 and, as to 100% of the grant, if the price of an Enbridge common share exceeds $71.00 for 20 consecutive trading days during the same aforementioned period. The term will extend to eight years if any of these options become exercisable before the end of the five-year term.

Outstanding Performance-based Options

(options in thousands; exercise price in dollars) December 31,	2003					2002					2001
				Weighted					Weighted					Weighted
				Average					Average					Average
				Exercise					Exercise					Exercise
	Number			Price		Number			Price		Number			Price
Options at beginning of year		2,045			37.73		1,479			32.03		1,480			31.60
Options granted		—			—		810			46.30		65			41.13
Options exercised		(549	)		31.39		(244	)		31.66		—			—
Options cancelled		—			—		—			—		(66	)		31.35
Options at end of year		1,496			40.05		2,045			37.73		1,479			32.03
Options vested		686			32.67		1,235			32.10		740			31.31

At December 31, 2003, the exercise prices of outstanding performance-based options ranged from $31.35 to $46.30 (2002 – $31.35 to $46.30; 2001 – $31.35 to $41.13). Outstanding performance-based options will expire over a period ending no later than September 16, 2010.

Notes to the Consolidated Financial Statements       65

14. STOCK OPTION PLAN (continued)

Pro forma Compensation Expense

If the Company had used the fair-value based method to account for fixed stock options and performance-based options granted in fiscal 2002, earnings and earnings per share would have been as follows.

(millions of dollars)
Year ended December 31,	2003			2002
Earnings applicable to common shareholders from continuing operations
As reported		667.2			334.2
Total stock-based compensation expense 1		(5.9	)		(2.9	)
Included as an expense in the statement of earnings 2		1.9			—
Pro forma		663.2			331.3
Earnings applicable to common shareholders
As reported		667.2			576.5
Total stock-based compensation expense 1		(5.9	)		(2.9	)
Included as an expense in the statement of earnings 2		1.9			—
Pro forma		663.2			573.6
Earnings per common share from continuing operations
As reported		4.03			2.09
Pro forma		4.01			2.07
Earnings per common share
As reported		4.03			3.60
Pro forma		4.01			3.58

1	Total stock-based compensation expense if the fair value based method to expense stock options had been applied since January 1, 2002.
2	Stock-based compensation recognized as an expense in the statement of earnings for options granted in 2003 as a result of the adoption of the fair valued based method January 1, 2003.

The Black-Scholes model was used to calculate the fair value of fixed stock options and the barrier valuation model was used to calculate the fair value of performance-based options. Significant assumptions used in these models are as follows:

Year ended December 31,	2003			2002			2003		2002
	Fixed Stock						Performance-based
	Options						Options
Fair value per option	$	8.46		$	11.42			—	$	7.65
Valuation assumptions
Expected option term (years)		8			10			—		8
Expected volatility		22	%		25	%		—		24	%
Expected dividend yield		3.95	%		3.51	%		—		3.46	%
Risk-free interest rate		5.24	%		5.33	%		—		4.20	%

66      Notes to the Consolidated Financial Statements

15. FINANCIAL INSTRUMENTS

Derivative Financial Instruments Used for Risk Management

The Company is exposed to movements in foreign currency exchange rates, interest rates and the price of energy commodities, primarily natural gas. In order to manage these exposures for both shareholders and ratepayers, the Company utilizes derivative financial instruments to create offsetting positions to specific exposures. These instruments are not used for speculative purposes.

Derivative financial instruments involve credit and market risks. Credit risk arises from the possibility that a counterparty will default on its contractual obligations and is limited to those contracts where the Company would incur a loss in replacing the instrument. The Company minimizes credit risk by entering into risk management transactions only with institutions that possess investment grade credit ratings or with approved forms of collateral. For transactions with terms greater than five years, the Company may also retain the right to require a counterparty, that would otherwise meet the Company’s credit criteria, to provide collateral.

Foreign Exchange

The Company has an exposure to foreign currency exchange rates, primarily because of its U.S. dollar denominated investments and its Euro investment in CLH where both carrying values and earnings are subject to foreign exchange risk. The Company utilizes par forward contracts and cross currency swaps to manage a portion of the foreign exchange exposure. In addition, cross currency swaps have been entered into to hedge the Company’s exposure on its U.S. dollar denominated senior term notes.

Interest Costs

The Company enters into forward interest rate agreements, swaps and collars to swap floating rate debt to fixed and hedge against the effect of future interest rate movements on its variable rate debt. The Company monitors its debt portfolio mix of fixed and variable rate instruments and has entered into fixed to floating interest rate swaps, with notional amounts of $300.0 million, to manage the balance of fixed and floating rate debt.

Energy Commodity Costs

The Company uses over-the-counter natural gas price swaps, futures, options and collars to manage physical exposures that arise in the management of merchant capacity commitments to the Alliance and Vector pipelines. The Company also uses these derivative instruments to manage any exposures that may arise from physical asset optimization and natural gas supply agreements.

As a result of the Company’s ownership interest in Aux Sable Liquid Products L.P., it is exposed to the price differential between natural gas and natural gas liquids (“NGL”). This risk is hedged through the use of over-the-counter derivatives whereby the forward prices of natural gas and NGLs are fixed with swaps, or capped or collared with options.

Natural Gas Supply Management

The Company hedges a portion of the cost of future natural gas supply requirements of Enbridge Gas, as allowed by the regulator. Amounts paid or received under the hedge agreements are recognized as part of the cost of the natural gas purchases and are recovered through the ratemaking process. At December 31, 2003, the Company had entered into natural gas price swaps and options to manage the price for approximately 8.9%, or 13.1 billion cubic feet, of its forecast fiscal 2004 system gas supply.

Notes to the Consolidated Financial Statements     67

15. FINANCIAL INSTRUMENTS (continued)

Fair Values

The fair values of derivatives have been estimated using year-end market information. These fair values approximate the amount that the Company would receive or pay to terminate the contracts.

December 31, (millions of dollars unless otherwise noted)	2003							2002
	Notional		Fair Value					Notional		Fair Value
	Principal		Receivable/					Principal		Receivable/
	or Quantity		(Payable)			Maturity		or Quantity		(Payable)			Maturity
Foreign exchange
U.S. cross currency swaps		535.8		(30.6	)		2005-2022		535.8		24.9			2005-2022
Euro cross currency swaps		434.7		(46.1	)		2004-2019		371.1		(54.4	)		2003
Forwards (cumulative exchange amounts)		1,889.5		67.9			2004-2022		1,993.0		(244.6	)		2003-2022
Energy commodities
Natural gas (bcf)		63.6		12.4			2004-2008		35.3		(1.5	)		2003-2004
Natural gas supply management (bcf)		13.1		(3.4	)		2004		5.9		(0.2	)		2003
Interest rates
Interest rate swaps		561.0		1.9			2005-2029		934.1		0.6			2003-2029
Forward interest rate swaps		532.0		(1.0	)		2004-2005		—		—			—

In addition, the Company has forward foreign exchange contracts with a notional principal of Canadian $214.0 million (2002 – $448.6 million), to exchange Canadian for U.S. dollars. The outstanding instruments expire in 2005 and 2007. The contracts are not effective hedges for accounting purposes but offset an exposure related to income taxes on foreign currency gains or losses on Canadian dollar debt of a U.S. subsidiary. These instruments are recorded at fair value and have a fair value payable of $10.5 million as at December 31, 2003 (2002 – $36.9 million receivable).

As the Company has not settled any hedging instruments in advance of the hedged transactions, there were no deferred gains or losses for any of the Company’s hedges of anticipated transactions at December 31, 2003 and 2002. A credit risk on derivative financial instruments amounted to $94.8 million at December 31, 2003 with no significant concentration with any single counterparty.

Fair Values of Other Financial Instruments

The fair value of financial instruments, other than derivatives, represents the amounts that would have been received from or paid to counterparties, calculated at the reporting date, to settle these instruments. The carrying amount of all financial instruments classified as current approximates fair value because of the short maturities of these instruments. The estimated fair values of all other financial instruments are based on quoted market prices or, in the absence of specific market prices, on quoted market prices for similar instruments and other valuation techniques.

The carrying amounts of all financial instruments, except for debt, approximate fair value. The fair value of debt does not include the effects of hedging.

68       Notes to the Consolidated Financial Statements

Total Debt

(millions of dollars) December 31,	2003				2002
	Carrying		Fair		Carrying		Fair
	Amount		Value		Amount		Value
Liquids Pipelines		881.4		990.6		981.3		1,084.5
Gas Distribution and Services		1,674.5		1,972.1		1,749.0		1,989.2
Corporate		3,362.1		3,540.1		3,962.3		4,081.3
		5,918.0		6,502.8		6,692.6		7,155.0

Non-recourse debt of joint ventures has a carrying value of $786.6 million and a fair value of $845.7 million.

Trade Credit Risk

Trade receivables related to Liquids Pipelines consist primarily of amounts due from companies operating in the oil and gas industry and are collateralized by the crude oil and other products contained in the Company’s pipelines and storage facilities. Credit risk in the Gas Distribution and Services segment is reduced by the large and diversified customer base and the ability to recover an estimate for doubtful accounts through the ratemaking process. Included in accounts receivable is an allowance for doubtful accounts of $35.1 million at December 31, 2003 (2002 – $31.1 million).

16. INCOME TAXES

Income Tax Rate Reconciliation

(millions of dollars)
Year ended December 31,	2003			2002			2001
Earnings before income taxes		888.2			746.8			552.1
Combined statutory income tax rate		35.6	%		38.0	%		41.0	%
Income taxes at statutory rate		316.2			283.8			226.3
Increase/(decrease) resulting from:
Tax rate changes on future income tax balances		6.2			8.1			(67.5	)
Future income taxes related to regulated operations		(34.5	)		(36.7	)		(35.7	)
Non-taxable items, net		(70.5	)		(99.5	)		(28.2	)
Lower foreign tax rates		(44.4	)		(42.2	)		(36.8	)
Large Corporations Tax		18.1			16.9			18.8
Other		(3.7	)		6.3			(7.7	)
Income Taxes		187.4			136.7			69.2
Continuing operations		187.4			102.1			66.7
Discontinued operations		—			34.6			2.5
		187.4			136.7			69.2
Effective income tax rate		21.1	%		18.3	%		12.5	%

In 2003, income taxes paid amounted to $202.9 million (2002 – $105.2 million; 2001 – $110.5 million).

Notes to the Consolidated Financial Statements   69

16. INCOME TAXES (continued)

Components of Future Income Taxes

(millions of dollars)
December 31,	2003		2002
Future Income Tax Liabilities
Differences in accounting and tax bases of property, plant and equipment		368.0		313.8
Differences in accounting and tax bases of investments		368.2		525.7
Other		187.2		110.1
		923.4		949.6
Future Income Tax Assets
Loss carryforwards		241.7		283.0
Other		45.2		38.2
		286.9		321.2
Total Net Future Income Tax Liability		636.5		628.4

Accumulated future income taxes related to rate-regulated operations which have not been recorded in the accounts amounted to $551.2 million at December 31, 2003 (2002 – $511.2 million). Had the liability method been prescribed by the regulatory authorities for ratemaking purposes, such amounts would have been recorded and recovered in revenues.

At December 31, 2003, the Company has recognized the benefit of unused tax loss carryforwards of $708.8 million. Unused tax loss carryforwards expire as follows: 2004 – $0.1 million; 2005 – $3.4 million; 2006 – $26.1 million; 2007 – $71.9 million; 2008 – $56.8 million, 2009 – $17.4 million and 2010 and beyond – $533.1 million.

Geographic Components of Pretax Earnings and Income Taxes

(millions of dollars)
Year ended December 31,	2003			2002			2001
Earnings before income taxes
Canada		693.0			346.1			297.2
United States		40.1			(5.0	)		103.8
Other		155.1			128.8			103.3
Continuing operations		888.2			469.9			504.3
Discontinued operations		—			276.9			47.8
		888.2			746.8			552.1
Current income taxes
Canada		108.4			154.8			44.4
United States		(10.9	)		3.2			8.9
Other		4.1			8.8			10.0
Continuing operations		101.6			166.8			63.3
Discontinued operations		—			36.9			20.1
		101.6			203.7			83.4
Future income taxes
Canada		116.6			(54.5	)		(9.0	)
United States		(31.0	)		(10.5	)		12.4
Other		0.2			0.3			—
Continuing operations		85.8			(64.7	)		3.4
Discontinued operations		—			(2.3	)		(17.6	)
		85.8			(67.0	)		(14.2	)
Current and future income taxes
Continuing operations		187.4			102.1			66.7
Discontinued operations		—			34.6			2.5
		187.4			136.7			69.2

70     Notes to the Consolidated Financial Statements

17. POST-EMPLOYMENT BENEFITS

Pension Plans

The Company has three pension plans which provide either defined benefit or defined contribution pension benefits or both for employees of the Company. The Liquids Pipelines and Gas Distribution and Services pension plans provide non-contributory defined pension and/or defined contribution benefits to Canadian employees of Enbridge. The Enbridge U.S. pension plan provides either non-contributory defined benefit pension benefits or contributory defined contribution pension benefits to U.S. employees of Enbridge.

Defined Benefit Plans

Retirement benefits under defined benefit plans are based on employees’ years of service and remuneration. Contributions made by the Company are made in accordance with independent actuarial valuations and are invested primarily in publicly-traded equity and fixed income securities. The measurement date used to determine the plan assets and the accrued benefit obligation was September 30, 2003. The effective dates of the most recent actuarial valuations and the next required actuarial valuations are as follows:

	Effective Date of Most Recently	Effective Date of Next Required
	Filed Actuarial Valuation	Actuarial Valuation
Liquids Pipelines	January 1, 2002	January 1, 2005
Enbridge U.S.	January 1, 2003	January 1, 2004
Gas Distribution and Services	January 1, 2002	January 1, 2005

Pension costs under the defined benefit pension plans reflect management’s best estimates of the rate of return on pension plan assets, rate of salary increases and various other factors including mortality rates, terminations and retirement ages. Adjustments arising from plan amendments, actuarial gains and losses, and changes to assumptions are amortized over the expected average remaining service lives of the employees.

Defined Contribution Plans

Contributions are generally based on the employee’s age and/or years of service. For the Enbridge U.S. pension plan, contributions to the defined contribution plans are also based on employee contributions. For defined contribution pension benefits, pension cost equals amounts required to be contributed by the Company.

Post-employment Benefits Other than Pensions

Post-employment benefits other than pensions (OPEB) include primarily supplemental health, dental and life insurance coverage for qualifying retired employees.

Notes to the Consolidated Financial Statements   71

17. POST-EMPLOYMENT BENEFITS (continued)

The following tables detail the changes in the benefit obligation, the fair value of plan assets and the recorded asset or liability using the accrual method.

(millions of dollars)	2003			2002			2003			2002
	OPEB						Pension Benefit
Change in benefit obligation
Benefit obligation, January 1		160.5			132.3			710.1			742.7
Service cost		5.8			4.2			20.0			18.7
Interest cost		10.6			8.8			46.8			45.9
Amendments		(3.3	)		—			—			0.7
Employee contributions		0.4			0.3			—			0.1
Actuarial loss		0.8			31.4			68.8			8.5
Benefits paid		(5.6	)		(5.7	)		(37.8	)		(37.9	)
Divestitures		—			(10.6	)		—			(67.8	)
Effect of exchange rate changes		(13.5	)		(0.2	)		(19.6	)		(0.8	)
Benefit obligation, December 31		155.7			160.5			788.3			710.1
Fair value of plan assets
Fair value of plan assets, January 1		35.5			29.6			933.1			1,076.7
Actual return on plan assets		0.8			3.0			109.7			(20.3	)
Employer’s contributions		11.2			8.5			11.2			19.7
Employee contributions		0.4			0.3			—			0.1
Benefits paid		(5.6	)		(5.7	)		(37.8	)		(37.9	)
Other		—			—			(1.7	)		(2.3	)
Divestitures		—			—			—			(100.9	)
Effect of exchange rate changes		(6.1	)		(0.2	)		(27.8	)		(2.0	)
Fair value of plan assets, December 31		36.2			35.5			986.7			933.1
Asset/(Liability)
Benefit obligation, December 31		(155.7	)		(160.5	)		(788.3	)		(710.1	)
Fair value of plan assets, December 31		36.2			35.5			986.7			933.1
Surplus/(deficit)		(119.5	)		(125.0	)		198.4			223.0
Contribution after measurement date		—			—			2.9			—
Unrecognized prior service cost		0.5			3.4			19.0			20.8
Unrecognized plan liability		29.4			36.2			—			—
Unrecognized net loss/(gain)		28.0			31.5			21.0			4.8
Recorded asset/(liability)		(61.6	)		(53.9	)		241.3			248.6

72     Notes to the Consolidated Financial Statements

Major Categories of Plan Assets

(millions of dollars)
Year ended December 31,	%			2003		2002		%			2003			2002
	OPEB							Pension Benefit
Equity securities		0.0	%		—		—		58.5	%		639.1			542.2
Debt securities		85.9	%		31.1		32.2		37.1	%		404.4			447.8
Other		14.1	%		5.1		3.3		4.4	%		47.8			35.7
		100.0	%		36.2		35.5		100.0	%		1,091.3			1,025.7
Assets attributable to Non-Consolidated Affiliates					—		—					(104.6	)		(92.6	)
Total Assets					36.2		35.5					986.7			933.1

Plan assets are invested primarily in readily marketable investments with thresholds on the credit quality of fixed income securities.

Rate of Return on Plan Assets

(millions of dollars)
Year ended December 31,	%			2003			2002			%			2003			2002
	OPEB									Pension Benefit
Canadian Plans
Equity securities		—			—			—			60.0	%		8.75	%		9.25	%
Fixed income securities		100.0	%		4.5	%		4.5	%		40.0	%		5.00	%		6.00	%
														7.25	%		7.75	%
United States Plan
Equity securities		—			—			—			60.0	%		8.75	%		9.25	%
Fixed income securities		100.0	%		4.50	%		4.50	%		40.0	%		5.00	%		6.00	%
														7.25	%		8.00	%

The Pension Funds exist to ensure that pension benefits will be paid. The Company manages the investment risk of its Pension Funds by setting a long term, asset mix policy for each Pension Fund after consideration of: (i) the nature of Pension Plan liabilities; (ii) the investment horizon of the Plan; (iii) the going concern and solvency funded status and cash flow requirements of the Plans; (iv) the operating environment and financial situation of the Company and its ability to withstand fluctuations in pension contributions; and (v) the future economic and capital markets outlook with respect to investment returns, volatility of returns and correlation between assets. The above table reflects both the target allocation percentage for each of the categories presented at the end of the period, as well as, the expected long-term rate of return on assets, both on a weighted-average basis. The overall expected rate of return is based on the asset allocation targets with estimates for returns on equity and debt securities based on long term expectations.

Plan Contributions by the Company

(millions of dollars)
Year ended December 31,	2003		2002		2003		2002
	OPEB				Pension Benefit
Minimum contributions required		—		—		—		—
Additional contributions		11.2		8.5		11.2		19.7
Total contributions		11.2		8.5		11.2		19.7
Contributions expected to be paid in 2004		10.6				14.8

Notes to the Consolidated Financial Statements   73

17. POST - EMPLOYMENT BENEFITS (continued)

Net Pension Plan and OPEB Costs Incurred

(millions of dollars)
Year ended December 31,	2003			2002			2001
Benefits earned during the year		27.7			25.2			26.3
Interest cost on projected benefit obligations		57.4			54.5			55.2
Actual return on plan assets		(110.5	)		16.7			(125.1	)
Actuarial gain in the year		69.6			38.0			45.0
Amount credited/(charged) to the EEP		(10.2	)		(1.7	)		5.5
Pension and OPEB costs incurred		34.0			132.7			6.9

Net Pension Plan and OPEB Costs Recognized

(millions of dollars)
Year ended December 31,	2003			2002			2001
Benefits earned during the year		27.7			25.2			26.3
Interest cost on projected benefit obligations		57.4			54.5			55.2
Expected return on plan assets		(64.8	)		(75.3	)		(93.7	)
Amortization and deferral of unrecognized amounts		15.3			6.9			(6.8	)
Amount credited/(charged) to EEP		(10.2	)		(1.7	)		5.5
Pension and OPEB cost/(credit) recognized		25.4			9.6			(13.5	)

The above tables reflect the funded status, recorded pension and OPEB assets and liabilities and pension and OPEB cost for all of the Company’s benefit plans on an accrual basis. However, in accordance with its ability to recover employee benefit costs on a pay-as-you-go basis for the regulated operations of Gas Distribution and Services, the Company records the cost of such benefits on a cash basis. Using the cash basis for the Gas Distribution and Services plans and the accrual method for other plans, the Company’s pension cost was $9.4 million (2002 – $3.6 million credit; 2001 – $4.0 million cost). The pension asset was $71.4 million (2002 – $73.1 million). The Company’s OPEB cost totaled $7.0 million (2002 – $6.8 million; 2001 – $5.9 million). The OPEB liability was $10.0 million (2002 – $8.4 million). These net benefits or liabilities are recorded on the balance sheet in Deferred Amounts and Other Assets. The pension and OPEB assets and obligations for discontinued operations were included in the sale transaction.

Economic Assumptions

The weighted average assumptions made in the measurement of the cost of the pension plans and OPEB are as follows:

Year ended December 31,	2003			2002			2001			2003			2002			2001
	OPEB									Pension Benefit
Discount rate		6.79	%		6.95	%		7.15	%		6.75	%		6.81	%		7.06	%
Average rate of salary increases											4.00	%		4.00	%		4.00	%
Average rate of return on pension plan assets		4.50	%		4.50	%		4.50	%		7.25	%		7.79	%		7.79	%

The weighted average assumptions made in the measurement of the projected benefit obligations of the pension plans and OPEB are as follows:

Year ended December 31,	2003			2002			2001			2003			2002			2001
	OPEB									Pension Benefit
Discount rate		6.31	%		6.79	%		6.95	%		6.29	%		6.75	%		6.81	%
Average rate of salary increases											4.00	%		4.00	%		4.00	%

74     Notes to the Consolidated Financial Statements

Medical Cost Trend Rates

The assumed medical cost trend rates for the next year used to measure the expected cost of benefits and the ultimate trend rate and the year in which the ultimate trend rate is assumed to be achieved are as follows:

							Year in which Ultimate
	Medical Cost Trend Rate			Ultimate Medical Cost			Medical Cost
	Assumption for Next			Trend Rate			Trend Rate Assumption
	Fiscal Year			Assumption			is Achieved
Canadian Plans
Drugs		10	%		4.5	%		2011
Other Medical		4.5	%		4.5	%		2004
Enbridge U.S.		14	%		5.5	%		2011

A 1% increase in the assumed medical and dental care trend rate would result in a change of $26.2 million in the accumulated post-employment benefit obligations and a change of $2.8 million in OPEB cost. A 1% decrease in the assumed medical and dental care trend rate would result in a change of $20.7 million in the accumulated post-employment benefit obligations and a change of $2.1 million in OPEB cost.

18. INVESTMENT AND OTHER INCOME

(millions of dollars)
Year ended December 31,	2003			2002			2001
Equity investments		146.3			143.5			56.7
Gain on reduction of EEP ownership interest		50.0			10.0			23.4
EEM’s equity income from EEP		26.5			7.4			23.3
Minority interest in EEM (equity income and dilution gain)		(25.9	)		(4.0	)		—
Cost investments		67.2			61.1			51.9
Investment income		32.9			22.9			16.3
Allowance for equity funds used during construction		3.2			5.3			3.9
Gain/(loss) on foreign currency contracts		(87.2	)		0.1			(1.7	)
Gain on sale of marketable securities		—			21.4			—
Other		(4.8	)		15.4			21.1
		208.2			283.1			194.9

19. CHANGES IN OPERATING ASSETS AND LIABILITIES

(millions of dollars)
Year ended December 31,	2003			2002			2001
Accounts receivable and other		(354.5	)		75.0			(583.7	)
Gas in storage		(224.8	)		76.0			(145.8	)
Deferred amounts and other assets		(78.9	)		72.4			(77.6	)
Accounts payable and other		93.9			(76.4	)		493.1
Interest payable		(5.5	)		4.6			(9.1	)
		(569.8	)		151.6			(323.1	)

Changes in accounts payable exclude changes in construction payables which are investing activities.

Notes to the Consolidated Financial Statements   75

20. RELATED PARTY TRANSACTIONS

Neither, EEP nor EIF have employees and use the services of the Company for managing and operating their businesses. These services, which are charged at cost in accordance with service agreements, amount to $128.9 million (2002 — $97.2 million; 2001 — $56.2 million) for EEP and $4.7 million for EIF, which began operation on June 30, 2003.

Vector uses the services of Enbridge, a 60% interest owner, to operationally manage its business. These services, which are charged at cost in accordance with service agreements, amounted to $3.3 million for 2003 (2002 — $4.1 million; 2001 — $3.4 million).

EGD acquires its customer care services from CustomerWorks Limited Partnership under an agreement having a five-year term starting January 2002. EGD is charged market prices for these services, which amounted to $95.5 million in 2003 (2002 — $71.8 million).

EGD has contracted for gas transportation services from Alliance Pipeline Limited Partnership and Vector Pipeline Limited Partnership. EGD is charged market prices for these services, which amounted to $40.7 million in 2003 (2002 — $41.3 million; 2001 — $34.8 million) for Alliance Pipeline, and $23.2 million in 2003 (2002 — $25.2 million; 2001 — $20.7 million) for Vector Pipeline.

A subsidiary of the Company earns rental revenue from CustomerWorks Limited Partnership for the use of an automated billing system. In 2003, this revenue amounted to $25.5 million (2002 — $35.1 million). CustomerWorks Limited Partnership began operations on January 1, 2002.

In 2003, Enbridge Gas Services Inc. purchased $33.6 million (2002 — $6.3 million; 2001 — nil) of gas from Enbridge Marketing (US) Inc.

The Company also provides consulting and other services to affiliates. Market prices are charged for these services where they are reasonably determinable; where no market price exists, a cost-based price is determined and charged. The Company may also purchase consulting and other services from affiliates. Prices are determined on the same basis as services provided by the Company. The trade receivable and payable balances include amounts received or paid on behalf of the Company or affiliates.

The Company and affiliates invoice on a monthly basis and amounts are due and paid on a quarterly basis.

21. COMMITMENTS AND CONTINGENCIES

Enbridge Gas Distribution Inc.

The remediation of discontinued manufactured gas plant sites may result in future costs to Enbridge Gas. In October 2002, a claim was filed for $55 million in damages relating to a certain manufactured gas plant site. Enbridge Gas filed a statement of defence in June 2003 denying liability. Although management believes that it has a valid defence to this claim, certain risks exist. The probable overall cost cannot be determined at this time due to uncertainty about the presence and extent of damage in addition to the potential alternative remediation approaches which vary in cost. Enbridge Gas expects that costs, if any, not recovered through insurance would be recovered through rates. As such, management does not believe that the outcome will have a material impact on the financial statements.

In October 2002, the Supreme Court of Canada granted an Application for Leave to Appeal to a customer who commenced an action against Enbridge Gas claiming that the OEB-approved late payment penalties charged to customers were contrary to Canadian federal law. The Court heard the plaintiff’s appeal of the Ontario Court of Appeal’s decision on October 9, 2003 and reserved issuing judgment.

76     Notes to the Consolidated Financial Statements

CAPLA Claim

The Canadian Alliance of Pipeline Landowners’ Associations and two individual landowners have commenced an action, which they will be applying for certification as 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. Since the outcome is indeterminable, the Company has made no provision for any potential liability.

Enbridge Energy Partners

Enbridge Energy Company, Inc. (EEC), which holds a portion of the Company’s equity interest in EEP, has agreed to indemnify EEP from and against substantially all liabilities, including liabilities relating to environmental matters, arising from operations prior to the transfer of its pipeline operations to EEP in 1991. This indemnification does not apply to amounts that EEP would be able to recover in its tariff rates if not recovered through insurance, or to any liabilities relating to a change in laws after December 27, 1991. In addition, in the event of default, EEC, as the General Partner, is subject to recourse with respect to a portion of EEP’s long-term debt, which amounts to US$248 million at December 31, 2003.

22. UNITED STATES ACCOUNTING PRINCIPLES

These consolidated financial statements have been prepared in accordance with Canadian GAAP. The effects of significant differences between Canadian GAAP and U.S. GAAP for the Company are described below.

Earnings and Comprehensive Income

(millions of dollars except per share amounts)
Year ended December 31,	2003			2002			2001
Earnings under Canadian GAAP		700.8			610.1			482.9
Preferred security distributions 1		(26.7	)		(26.7	)		(17.5	)
Stock-based compensation 2		—			(12.1	)		(15.2	)
Loss on ineffective hedges 5		(53.8	)		—			—
Change in income due to consolidation of EIF 7		(2.3	)		—			—
Change in gain due to consolidation of EIF 7		(173.0	)		—			—
Tax effect of the above adjustments		51.5			4.9			6.1
Future income tax recovery/(expense) 3		—			—			92.8
Earnings under U.S. GAAP		496.5			576.2			549.1
Unrealized net gain/(loss) on cash flow hedges 6		66.9			19.5			(150.8	)
Reclassification adjustment on cash flow hedges 6		80.6			—			—
Foreign currency translation adjustment 6		(159.6	)		(1.3	)		15.1
Comprehensive income		484.4			594.4			413.4
Earnings per common share		3.00			3.55			3.45
Diluted earnings per common share		2.98			3.51			3.41

Notes to the Consolidated Financial Statements   77

22. UNITED STATES ACCOUNTING PRINCIPLES (continued)

Financial Position

(millions of dollars)
December 31,	2003						2002
	Canada			United States			Canada		United States
Cash 7		104.1			131.7			40.7		42.7
Accounts receivable and other 6,7		1,138.8			1,192.8			817.5		843.4
Property, plant and equipment7		11,481.5			12,778.2			9,548.6		9,506.6
Accumulated depreciation7		2,950.6			2,974.2			2,601.0		2,596.3
Long-term investments 7		2,390.9			2,010.7			3,371.5		3,421.0
Deferred amounts 3,7		486.5			1,355.8			315.8		1,178.7
Short-term borrowings		649.6			649.6			247.5		256.8
Accounts payable and other 7		894.1			1,000.7			714.1		915.0
Current maturities and short-term debt 7		674.9			721.4			652.3		658.5
Long-term debt 1		5,243.1			6,761.0			6,040.3		6,612.5
Future income taxes 3,6		636.5			1,429.2			628.4		1,403.0
Non-controlling interests 7		523.0			599.7			560.8		560.8
Preferred securities 1		532.4			—			533.7		—
Retained earnings		1,511.4			1,289.5			1,128.1		1,089.8
Additional paid in capital 2		—			27.3			—		27.3
Foreign currency translation adjustment 6		(147.0	)		—			12.3		—
Accumulated other comprehensive loss 6		—			(116.6	)		—		(103.2	)

1	Preferred Securities
	Under U.S. GAAP, the full amount of the Company’s Preferred Securities and related distributions would be recognized as debt and interest expense, respectively. The Preferred Securities have a fair market value of $625.5 million at December 31, 2003 (2002 — $565.0 million).
2	Stock-based Compensation
	Effective January 1, 2003, the Company adopted FAS 123, Accounting for Stock-Based Compensation, on a prospective basis for U.S. GAAP, and elected to use the fair value-based method to measure compensation expense. The adoption of the fair value method for U.S. GAAP eliminates all differences between Canadian and U.S. GAAP for options granted subsequent to the date of adoption. Disclosure differences in pro forma earnings between Canadian and U.S. GAAP for options will remain only for those options granted prior to adoption, January 1, 2002, of the Canadian accounting standard for stock-based compensation.

          Prior to the adoption of FAS 123, the Company accounted for stock-based compensation for U.S. GAAP in accordance with APB 25, Accounting for Stock Issued to Employees, which required the use of the intrinsic value-based method to measure compensation expense. Under Canadian GAAP, the Company’s performance-based options did not give rise to compensation expense. Under U.S. GAAP, the Company’s performance-based options, which vested during 2002 and 2001, gave rise to pre-tax compensation expense of $12.1 million and $6.9 million respectively. No performance-based options vested in 2003. In addition, under U.S. GAAP in 2001, the Company’s Stock Appreciation Rights (SARs) were accounted for using the intrinsic value method, which resulted in pre-tax compensation expense of $8.3 million, whereas, under Canadian GAAP, SARs did not give rise to compensation expense.

3	Future Income Taxes
	Canadian GAAP requires that the effects of tax rate reductions be recognized when they are substantively enacted. Under U.S. GAAP, the effect of tax rate reductions cannot be recognized until enacted. In 2000, the Company recognized $92.8 million of earnings related to substantively enacted tax rate reductions that are recognized in 2001 under U.S. GAAP.

          Under U.S. GAAP, deferred income tax liabilities are recorded for rate-regulated operations, which follow the taxes payable method for ratemaking purposes. As these deferred income taxes are expected to be recoverable in future revenues, a corresponding regulatory asset is also recorded. These assets and liabilities are adjusted to reflect changes in enacted income tax rates. The additional deferred income taxes under U.S. GAAP include the difference between capital cost allowance and depreciation of property, plant and equipment of $551.2 million (2002 – $549.3 million) and the incremental revenue required for the recovery of unrecorded taxes of $286.6 million (2002 – $316.0 million).

4

Accounting for Joint Ventures

U.S. GAAP requires the Company’s investments in joint ventures be accounted for using the equity method. However, under an accommodation of the U.S. Securities and Exchange Commission, accounting for joint ventures need not be reconciled from Canadian to U.S. GAAP. The different accounting treatment affects only display and classification and not earnings or shareholders’ equity. See Note 7 for summarized financial information of joint ventures.

78     Notes to the Consolidated Financial Statements

5 Financial Instruments

For U.S. GAAP purposes, FAS 133, Accounting for Derivative Instruments and Hedging Activities, requires that all derivatives be recorded on the balance sheet as either assets or liabilities at their fair value. Changes in the derivative’s fair value are recognized in current period earnings unless specific hedge accounting criteria are met.

     The accounting for changes in the fair value of derivatives held for hedging purposes depends upon their intended use. For fair value hedges, the effective portion of changes in fair value of derivative instruments is offset in income against the change in fair value, attributed to the risk being hedged, of the underlying hedged asset, liability or firm commitment. For cash flow hedges, the effective portion of changes in fair value of derivative instruments is offset through other comprehensive income, until the variability in cash flows being hedged is recognized in earnings in future accounting periods.

     In order to qualify for hedge accounting, FAS 133 requires that extensive documentation be maintained and that hedge effectiveness tests prescribed by that standard be met at both the inception of a hedge relationship and on a periodic, ongoing basis. Management maintains the necessary level of documentation required to qualify for hedge accounting under FAS 133. However, in one instance during 2003, certain instruments were classified as ineffective hedges resulting in a loss after tax of $32.3 million under U.S. GAAP.

6 Accumulated Other Comprehensive Loss

At December 31, 2003, Accumulated Other Comprehensive Loss consists of an accumulated foreign currency translation adjustment of $(131.5) million (2002 – $28.1 million) and net unrealized gains of $14.9 million (2002 – $(131.3) million) both for derivative financial instruments due to cash flow hedges, including a reclassification adjustment in 2003. The reclassification adjustment of $80.6 million relates to the change in classification of hedging instruments between periods.

     Of the Accumulated Other Comprehensive Loss of $116.6 million, the Company estimates that approximately $5.6 million, representing unrecognized net losses on derivative activities at December 31, 2003, is expected to be reclassified into earnings during the next twelve months.

7 Consolidation of Variable Interest Entities

On December 24, 2003, the Financial Accounting Standards Board issued a revision to FASB Interpretation (FIN) 46, which replaces the interpretation released in January 2003.

     FIN 46 requires the primary beneficiary of a variable interest entity’s activities to consolidate the variable interest entity. FIN 46 defines a variable interest entity as an entity which has one or more of the following characteristics:

1) The equity investment at risk is not sufficient to permit the entity to finance its activities without additional subordinated financial support provided by any parties, including the equity holders.

2) The equity investors as a group lack one or more of the following essential characteristics of a controlling financial interest:

a. The direct or indirect ability to make decisions about the entity’s activities through voting rights or similar rights that have a significant effect on the success of the entity.

b. The obligation to absorb the expected losses of the entity.

c. The right to receive the expected residual returns of the entity. The equity investors do not have that right if their return is capped by the entity’s governing documents or arrangements with other variable interest holders or the entity.

3) The equity investors have voting rights that are not proportionate to their economic interests, and the activities of the entity involve or are conducted on behalf of an investor with a disproportionately small voting interest.

     The primary beneficiary is the party that absorbs a majority of the expected losses and/or receives a majority of the expected residual returns of the variable interest entity’s activities.

     FIN 46 is immediately applicable to variable interest entities created, or interests in variable interest entities obtained, after January 31, 2003. For variable interest entities created, or interests in variable interest entities obtained, on or before January 31, 2003, FIN 46 is required to be applied by the first fiscal year or interim period ending after December 15, 2003. The Company has not identified any material variable interest entities created, or interests in variable entities obtained, before January 31, 2003, which would require consolidation or disclosure under FIN 46.

     On June 30, 2003, the Company formed Enbridge Income Fund (EIF), a publicly traded entity with assets purchased from the Company. The Company has a 41.9% equity interest in EIF, as well as a preferred unit investment that has no voting rights, a stated par value and a 30-year maturity. The preferred units earn a return that is equivalent to the cash distributions per unit to the equity unit holders and are classified as a liability in EIF’s financial statements.

     EIF is considered a variable interest entity as the equity investors lack the right to receive the expected residual returns of the entity. FIN 46 defines expected residual returns as the expected positive variability in the fair value of EIF’s net assets exclusive of variable interests. The preferred units participate in the positive variability as they receive a coupon rate that floats with changes in the cash distributions made to the equity holders of EIF. Consequently, the equity investors lack the right to receive the expected residual returns of the entity.

     The Company is the primary beneficiary of EIF through a combination of the 41.9% equity interest and the preferred unit interest. Under U.S. GAAP, the results of EIF are consolidated with a 27.7% minority interest. The assets and liabilities of EIF have been measured at the same amounts as they were prior to the transfer to EIF and the gain is recorded based on the equity issued to external third parties.

     The U.S. GAAP adjustment reflecting the consolidation of EIF includes a $380.2 million reduction to long-term investments, a $76.7 million increase in non-controlling interests, a reduction in the pre-tax gain on sale from $239.9 million to $66.9 million, and net income is reduced by $2.3 million.

The following accounts of EIF are consolidated for the purposes of the U.S. GAAP financial statements as at December 31, 2003.

Cash	$	27.6	million
Accounts receivable and other	$	34.2	million
Property, plant and equipment	$	1,273.1	million
Deferred amounts	$	31.5	million
Accounts payable and other	$	31.0	million
Current portion of long-term debt	$	40.0	million
Long-term debt	$	1,022.6	million
Future income taxes	$	2.8	million

The consolidation of EIF increases cash by $27.6 million and the statement of cash flows would reflect an increase in cash from operations of $30.4 million, cash from investing activities would decrease by $384.3 million, and cash used in financing activities would increase by $381.5 million.

Notes to the Consolidated Financial Statements       79

Supplemental Disclosure — Pro Forma Compensation Expense

U.S. GAAP requires that, where the fair value based method is not used to measure compensation expense, pro forma earnings and earnings per share, calculated as if the fair value based method had been used, must be disclosed. In Canada, these requirements apply to options granted on or after January 1, 2002 and therefore, the Company’s Canadian GAAP disclosure does not include any options granted prior to that date.

(millions of dollars except per share amounts)
Year ended December 31,	2003			2002			2001
Earnings under U.S. GAAP
As reported		496.5			576.2			549.1
Stock-based compensation expense		(7.9	)		(7.3	)		(4.6	)
Included as an expense in the statement of earnings		1.9			—			—
Pro forma		490.5			568.9			544.5
Earnings per common share
As reported		3.00			3.55			3.45
Stock-based compensation expense		0.04			0.05			0.03
Pro forma		2.96			3.50			3.42
Diluted earnings per common share
As reported		2.98			3.51			3.41
Stock-based compensation expense		0.04			0.04			0.03
Pro forma		2.94			3.47			3.38

The fair value of stock options was calculated in the same manner, using the same assumptions, as disclosed in Note 14 except that for Canadian GAAP, only awards granted since the adoption of the CICA standard for stock-based compensation on January 1, 2002 are included. Assumptions used for U.S. GAAP comparatives in 2001 are as follows.

Year ended December 31,	2001
Risk-free interest rate		5.38	%
Expected life (years)		10
Expected volatility		25	%
Expected quarterly dividends	$	0.38

The weighted average grant-date fair value of options granted during 2001 under the fixed option plan was $10.09.

80      Notes to the Consolidated Financial Statements