exv99w4

(PWC Calgary LH)

Auditors’ Report

To the Shareholders of
Enbridge Inc.

We have audited the consolidated statements of financial position of Enbridge Inc. as at December 31, 2004 and 2003 and the consolidated statements of earnings, retained earnings and cash flows for each of the years in the three year period ended December 31, 2004. These financial statements are the responsibility of the Company’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, 2004 and 2003 and the results of its operations and its cash flows for each of the years in the three year period ended December 31, 2004 in accordance with Canadian generally accepted accounting principles.



Calgary, Alberta, Canada		Chartered Accountants
January 25, 2005

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 preferred securities described in Note 2 to the consolidated financial statements. Our report to the shareholders dated January 25, 2005 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 25, 2005

PricewaterhouseCoopers refers to the Canadian firm of PricewaterhouseCoopers LLP and the other member firms of PricewaterhouseCoopers International Limited, each of which is a separate and independent legal entity.

ENBRIDGE INC.
CONSOLIDATED STATEMENTS OF EARNINGS


(millions of Canadian dollars, except per share amounts)

Year ended December 31,	2004			2003			2002
				Restated			Restated
				(Note 2)			(Note 2)

Revenues
Gas sales		4,554.4			3,061.7			2,987.7
Transportation		1,695.8			1,560.6			1,296.6
Energy services		290.3			233.0			263.2

		6,540.5			4,855.3			4,547.5

Expenses
Gas costs		3,917.0			2,720.1			2,578.0
Operating and administrative		1,015.0			800.8			834.1
Depreciation		525.0			443.0			403.9
Writedown of Enbridge Midcoast Energy assets (Note 4)		—			—			122.7

		5,457.0			3,963.9			3,938.7

Operating Income		1,083.5			891.4			608.8
Investment and Other Income (Note 18)		261.7			208.2			283.1
Gain on Sale of Investment in AltaGas Income Trust (Note 8)		121.5			—			—
Gain on Sale of Assets to Enbridge Income Fund (Note 4)		—			239.9			—
Interest Expense (Note 10)		(525.3	)		(492.8	)		(468.4	)

		941.4			846.7			423.5
Income Taxes (Note 16)		(289.2	)		(172.6	)		(86.6	)

Earnings From Continuing Operations		652.2			674.1			336.9
Earnings From Discontinued Operations (Note 4)		—			—			242.3

Earnings		652.2			674.1			579.2
Preferred Share Dividends (Note 13)		(6.9	)		(6.9	)		(6.9	)

Earnings Applicable to Common Shareholders		645.3			667.2			572.3

Earnings Applicable to Common Shareholders
Continuing Operations		645.3			667.2			330.0
Discontinued Operations		—			—			242.3

		645.3			667.2			572.3

Earnings Per Common Share (Note 13)
Continuing Operations		3.86			4.03			2.06
Discontinued Operations		—			—			1.51

		3.86			4.03			3.57

Diluted Earnings Per Common Share (Note 13)
Continuing Operations		3.83			4.00			2.03
Discontinued Operations		—			—			1.50

		3.83			4.00			3.53

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

ENBRIDGE INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS


(millions of Canadian dollars)

Year ended December 31,	2004			2003			2002
				Restated			Restated
				(Note 2)			(Note 2)

Cash Provided By Operating Activities
Earnings from continuing operations		652.2			674.1			336.9
Charges/(credits) not affecting cash
Depreciation		525.0			443.0			403.9
Equity earnings in excess of cash distributions		(39.2	)		(22.1	)		(44.6	)
Gain on sale of assets to Enbridge Income Fund		—			(239.9	)		—
Gain on reduction of ownership interest		(29.6	)		(50.0	)		(10.0	)
Gain on sale of investment in AltaGas Income Trust		(121.5	)		—			—
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		12.7			85.8			(77.8	)
Other		28.2			21.4			(10.2	)
Changes in operating assets and liabilities (Note 19)		(141.1	)		(569.8	)		151.6
Cash provided by operating activities of discontinued operations		—			—			26.3

		886.7			368.5			877.4

Investing Activities
Acquisitions (Note 5)		(833.9	)		(78.3	)		(289.3	)
Long-term investments		(16.6	)		(50.5	)		(1,282.7	)
Additions to property, plant and equipment		(496.4	)		(391.3	)		(729.9	)
Proceeds on redemption of Enbridge Commercial Trust preferred units		—			24.9			—
Sale of investment in AltaGas Income Trust		346.7			—			—
Sale of assets to Enbridge Income Fund (Note 4)		—			331.2			—
Proceeds on dispositions		—			—			1,706.9
Affiliate loans		—			427.2			358.1
Changes in construction payables		0.5			(3.7	)		(14.8	)

		(999.7	)		259.5			(251.7	)

Financing Activities
Net change in short-term borrowings and short-term debt		738.0			359.8			(1,180.9	)
Long-term debt issues		500.0			150.0			247.4
Long-term debt repayments		(450.0	)		(725.0	)		(382.7	)
Non-recourse long-term debt issued by joint ventures		—			538.3			—
Non-recourse long-term debt repaid by joint ventures		(42.9	)		(663.8	)		—
Non-controlling interests		(2.4	)		(4.0	)		0.2
Preferred securities		(350.0	)		—			200.0
Common shares issued		44.4			70.9			293.1
Enbridge Energy Management shares issued (Note 8)		—			—			421.9
Preferred share dividends		(6.9	)		(6.9	)		(6.9	)
Common share dividends		(315.8	)		(283.9	)		(251.1	)

		114.4			(564.6	)		(659.0	)

Increase/(Decrease) in Cash		1.4			63.4			(33.3	)
Cash at Beginning of Year		104.1			40.7			74.0

Cash at End of Year		105.5			104.1			40.7

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

ENBRIDGE INC.
CONSOLIDATED STATEMENTS OF FINANCIAL POSITION


(millions of Canadian dollars)

December 31,	2004			2003
				Restated
				(Note 2)

ASSETS
Current Assets
Cash		105.5			104.1
Accounts receivable and other		1,451.9			1,120.7
Inventory		791.6			827.9

		2,349.0			2,052.7
Property, Plant and Equipment, net (Note 6)		9,066.5			8,530.9
Long-Term Investments (Note 8)		2,278.3			2,390.9
Receivable from Affiliate (Note 20)		171.7			169.8
Deferred Amounts and Other Assets (Note 9)		729.2			608.2
Intangibles and Goodwill (Note 5)		165.4			—
Future Income Taxes (Note 16)		145.0			192.5

		14,905.1			13,945.0

LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities
Short-term borrowings		650.6			649.6
Accounts payable and other		1,275.9			906.5
Interest payable		83.8			97.0
Current maturities and short-term debt (Note 10)		703.9			635.9
Current portion of non-recourse long-term debt (Note 11)		30.2			34.2

		2,744.4			2,323.2
Long-Term Debt (Note 10)		6,053.3			5,775.5
Non-Recourse Long-Term Debt (Note 11)		665.2			752.4
Other Long-Term Liabilities		151.8			148.3
Future Income Taxes (Note 16)		797.3			829.0
Non-Controlling Interests (Note 12)		514.9			523.0

		10,926.9			10,351.4

Shareholders’ Equity
Share capital
Preferred shares (Note 13)		125.0			125.0
Common shares (Note 13)		2,282.4			2,238.0
Contributed surplus		5.4			1.9
Retained earnings		1,840.9			1,511.4
Foreign currency translation adjustment		(139.8	)		(147.0	)
Reciprocal shareholding (Note 8)		(135.7	)		(135.7	)

		3,978.2			3,593.6

Commitments and Contingencies (Note 21)
		14,905.1			13,945.0

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

Approved by the Board:


“signed”		“signed”
Donald J. Taylor		Robert W. Martin

Chair		Director

ENBRIDGE INC.
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 consists of proportionately consolidated investments in pipelines that transport natural gas including the U.S. portion of the Alliance Pipeline, Vector Pipeline and a system of transmission and gathering pipelines in the Gulf of Mexico.

    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. 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, and the Company’s proportionately consolidated investment in Aux Sable, a natural gas fractionation and extraction business.

    International
The Company’s International business consists of investments 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. S U M M A R Y O F S I G N I F I C A N T A C C O U N T I N G P O L I C I E S

    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.

    The Company’s gas distribution activities within Gas Distribution and Services are conducted primarily through a wholly-owned subsidiary, Enbridge Gas Distribution Inc. (EGD). Prior to 2004, the fiscal year-end of EGD and certain smaller gas distribution subsidiaries was September 30 and their results were consolidated on a one

ENBRIDGE INC.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

    quarter lag basis. In respect of 2003 and 2002, references to “December 31” mean the financial position of EGD as at September 30 and references to the “year ended December 31” mean the results of EGD for the year ended September 30. Starting in 2004, EGD changed its fiscal year end to December 31. Accordingly, the Company’s financial statements for the year ended December 31, 2004 include 15 months of results for EGD and other gas distribution subsidiaries.

    Regulation
The Company’s Liquids Pipelines, Gas Pipelines, and certain Gas Distribution and Services businesses 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 for non rate-regulated entities.

    Revenue Recognition
Generally, revenues are recorded when products have been delivered or services have been performed. However, certain of the Liquids Pipelines, Gas Pipelines and gas distribution operations within Gas Distribution and Services are subject to regulation and, accordingly, there are circumstances where revenues recognized do not match the cash tolls or the billed amounts.

    Certain Liquids Pipelines revenues are recognized under the terms of a committed long-term delivery contract. The Company records revenues based on the terms of the 30-year contract rather than the cash tolls received. On the Company’s main Canadian crude oil pipeline system, for rate-regulated operations, revenue is recognized in a manner that is consistent with the underlying agreements as approved by the regulatory authority.

    For rate-regulated operations in Gas Pipelines, transportation revenues include amounts related to expenses in the financial statements that are expected to be recovered from shippers in future tolls. No revenue is recognized in a given period for tolls received that do not relate to current period expenses. Differences between the recorded transportation revenue and actual toll receipts give rise to receivable or payable balances.

    A significant portion of Gas Distribution and Services operations are subject to rate-regulation and accordingly there are circumstances where the revenues recognized do not match the amounts billed. Revenue is recognized in a manner that is consistent with the underlying rate-setting mechanism as mandated by the regulators. This may give rise to regulatory assets and liabilities on the consolidated statement of financial position pending disposition by a decision of the regulators. Gas distribution revenues are recorded on the basis of regular meter readings and estimates of customer usage since the last meter reading to the end of the reporting period.

    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 the Company expects 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 Company has U.S. dollar operations, which are primarily self-sustaining except for certain financing and investing operations. The Company also holds a Euro equity investment in a foreign operation in Spain. These operations, which include those of proportionately consolidated U.S. dollar investments and the Euro 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

ENBRIDGE INC.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

    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.

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

    Inventory
Inventory is primarily comprised of natural gas in storage held in EGD. Natural gas in storage is recorded in inventory at the prevailing 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.

    Intangibles and Goodwill
Goodwill is not subject to amortization but is tested for impairment at least annually and written down to fair value if the criteria for impairment are met. Goodwill represents the excess of the purchase price over the fair value of net identifiable assets upon acquisition of a business. Intangible assets consist of long-term transportation contracts and are amortized on a straight-line basis over the expected life of the contracts. The depreciation rate for intangibles is 4%.

    Asset Retirement Obligations
No material amount has been recorded for asset retirement obligations relating to the Company’s assets as it is not possible to make a reasonable estimate of the fair value of the liability due to the indeterminate timing and scope of the asset retirements. Management also believes it is reasonable to assume that all retirement costs associated with the regulated pipelines will be recovered through tolls in future periods.

    Depreciation expense for Gas Distribution and Services operations includes a provision for asset retirement obligations at rates approved by the regulator. Actual costs incurred are charged to accumulated depreciation.

    Deferred Amounts and Other Assets
The Company defers certain charges, which the regulatory authorities permit to be recovered through future rates. Assets are realized and liabilities are settled based on the terms of the regulatory approval once 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 hedged items. Deferred financing charges are amortized on a straight-line basis, which approximates the effective interest method, over the life of the related debt and classified as interest expense. The Company recognizes revenues under the terms of a committed long-term delivery contract, which result in a long-term receivable.

ENBRIDGE INC.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

    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 Gas Distribution and Services 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.

    Pension plan assets are measured at fair value. The expected return on pension plan assets is determined using market-related values. Market related values have been calculated using the fair value method. Adjustments arising from plan amendments and the transitional amounts recognized upon adoption of the accounting standard are amortized on a straight-line basis over the average remaining service period of the employees active at the date of amendment. The excess of the net actuarial gain or loss over ten per cent of the greater of the benefit obligation and the fair value of plan assets is amortized over the average remaining service period of the active employees.

    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 Gas Distribution and Services where the cost of providing these benefits is expensed as paid, consistent with the recovery of such costs in rates.

    The measurement date used to determine the plan assets and the accrued benefit obligation was September 30, 2004.

    Stock Based Compensation
Stock options granted after January 1, 2003 are accounted for under the fair value method. Under this method, compensation expense is measured at fair value at the grant date using the Black-Scholes option pricing model and recognized over the vesting period with a corresponding credit to contributed surplus. Stock options granted prior to January 1, 2003 continue to be accounted for as capital transactions when the options are exercised, which does not give rise to compensation expense.

    Performance stock units (PSUs) are accounted for over the three-year term on a mark-to-market basis whereby a liability and expense are recorded based on the number of PSUs outstanding, the current market price of the Company’s shares and the Company’s current performance relative to the specified peer group.

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

ENBRIDGE INC.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

2. C H A N G E S I N A C C O U N T I N G P O L I C I E S

    Recently Adopted Accounting Standards
Asset Retirement Obligations
Effective January 1, 2004, the Company adopted the new CICA standard for asset retirement obligations. This new standard requires that the fair value of asset retirement obligations associated with the retirement of long-lived assets is recognized in the period incurred. The fair value, which approximates the cost a third party would incur in performing the tasks necessary to retire such assets, is recognized at the present value of expected future cash flows and is added to the carrying value of the associated asset and depreciated over the asset’s useful life. The liability is accreted over time through periodic charges to earnings and is reduced by actual costs of decommissioning and reclamation.

    No material amount has been recorded for asset retirement obligations relating to the Company’s assets as it is not possible to make a reasonable estimate of the fair value of the liability due to the indeterminate timing and scope of the asset retirements. Management also believes it is reasonable to assume that all retirement costs associated with the regulated pipelines will be recovered through tolls in future periods.

    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 expired in 2004.

    Effective January 1, 2003, the Company early adopted revised requirements in the CICA standard for stock-based compensation. The standard 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 resulted in a charge to income, in the year of adoption, of $1.9 million.

    Preferred Securities
Effective December 31, 2004, the Company early adopted amendments to the CICA standard on the disclosure and presentation of financial instruments. The amendments require the Company’s preferred securities to be classified wholly as debt rather than splitting the principal and payments components of the securities into debt and equity. The amendments were adopted retroactively and have resulted in financial statement impacts summarized in the table below. In December 2004, $350 million of preferred securities were redeemed.

    Impairment of Long-lived Assets
Effective January 1, 2004, the Company adopted the new CICA standard for recognizing, measuring and disclosing impairment of long-lived assets held for use. The new standard has not had a significant impact on the Company’s financial results.

    Hedging Relationships
Effective January 1, 2004, the Company adopted the new guideline 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 related to instruments recorded in the statement of financial position is to be recognized in income for the period. The new guideline has not had a significant impact on the Company’s financial results.

    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. At present, the standard has an exemption for rate-regulated operations and, as a result, has not had a significant impact on the Company’s financial results.

ENBRIDGE INC.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Financial Impact of Changes in Accounting Policies


(millions of dollars)

Year ended December 31,	2003									2002

	As Reported			Change			As Restated			As Reported			Change			As Restated

Statements of Earnings
Interest expense¹		(451.3	)		(41.5	)		(492.8	)		(422.0	)		(46.4	)		(468.4	)
Income taxes¹		(187.4	)		14.8			(172.6	)		(102.1	)		15.5			(86.6	)
Preferred security distributions¹		(26.7	)		26.7			—			(26.7	)		26.7			—
Earnings to common shareholders¹		667.2			—			667.2			576.5			(4.2	)		572.3

Statements of Retained Earnings
Preferred securities issue costs¹		—			—			—			(4.2	)		4.2			—

Statements of Financial Position
Liabilities
Long-term debt¹		5,243.1			532.4			5,775.5
Shareholders’ Equity
Preferred securities¹		532.4			(532.4	)		—

Change due to retroactive adoption of amendments to the standard on the disclosure and presentation of financial instruments.

New Accounting Standards
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. As a result, the Company will consolidate EIF, starting January 1, 2005. A similar standard has been adopted by the Financial Accounting Standards Board in the United States (FIN 46R), effective for interim periods commencing after July 15, 2003. The impact on the Company’s financial results of consolidating EIF is presented in Note 22, United States Accounting Principles.

ENBRIDGE INC.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

3. S E G M E N T E D I N F O R M A T I O N

Year ended December 31, 2004

Gas

Liquids

Gas

Sponsored

Distribution

(millions of dollars)

Pipelines

Investments

and Services²

International

Corporate¹

Consolidated

Revenues

872.7

271.7

—

5,363.8

32.3

—

6,540.5

Gas costs

—

(3,917.0

)

—

(3,917.0

)

Operating and administrative

(310.1

)

(55.1

)

—

(577.0

)

(38.6

)

(34.2

)

(1,015.0

)

Depreciation³

(145.4

)

(65.7

)

—

(308.4

)

(1.9

)

(3.6

)

(525.0

)

Operating income

417.2

150.9

—

561.4

(8.2

)

(37.8

)

1,083.5

Investment and other income

1.8

0.8

112.2

50.6

81.5

14.8

261.7

Gain on sale of investment

—

121.5

—

121.5

Interest and preferred share dividends

(101.4

)

(65.6

)

—

(211.1

)

(0.2

)

(153.9

)

(532.2

)

Income taxes

(97.7

)

(32.3

)

(46.0

)

(209.3

)

0.5

95.6

(289.2

)

Earnings applicable to common shareholders

219.9

53.8

66.2

313.1

73.6

(81.3

)

645.3


Year ended December 31, 2003

										Gas
	Liquids			Gas			Sponsored			Distribution
(millions of dollars)	Pipelines			Pipelines			Investments			and 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		390.1			124.2			—			411.8			(6.3	)		(28.4	)		891.4
Investment and other income		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 share dividends		(102.1	)		(58.7	)		—			(162.2	)		(0.5	)		(176.2	)		(499.7	)
Income taxes		(77.9	)		(32.0	)		(118.7	)		(115.8	)		1.0			170.8			(172.6	)

Earnings applicable to common shareholders		213.5			70.1			234.3			153.6			72.3			(76.6	)		667.2

ENBRIDGE INC.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS


Year ended December 31, 2002

										Gas
	Liquids			Gas			Sponsored			Distribution
(millions of dollars)	Pipelines			Pipelines			Investments			and 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		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 share dividends		(99.8	)		—			(28.1	)		(161.7	)		(1.6	)		(184.1	)		(475.3	)
Income taxes		(70.0	)		(18.5	)		14.1			(93.1	)		0.3			80.6			(86.6	)

Earnings applicable to common shareholders		189.6			47.8			(51.1	)		124.3			68.0			(48.6	)		330.0

Earnings from discontinued operations																				242.3

Earnings applicable to common shareholders																				572.3

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.		Gas Distribution and Services includes 15 months of results for EGD and other gas distribution businesses, which changed their year end to December 31 in 2004. This change eliminated the quarter lag basis of consolidation and resulted in additional earnings of $57.2 million.
3.		Depreciation expense in Gas Distribution and Services includes a $12.4 million impairment loss on the Calmar Gas Plant. The operations of this plant have not improved to a level to enable the recovery of its carrying costs and as a result it has been written down to an estimated fair value of $5 million.
4.		The measurement basis for preparation of segmented information is consistent with the significant accounting policies described in Note 1.

Total Assets


(millions of dollars)

December 31,	2004		2003

Liquids Pipelines		3,410.7		3,411.1
Gas Pipelines		2,310.2		1,695.0
Sponsored Investments		1,116.3		1,394.5
Gas Distribution and Services		6,599.4		6,218.8
International		958.6		836.1
Corporate		509.9		389.5

		14,905.1		13,945.0

Additions to Property, Plant and Equipment


(millions of dollars)

Year ended December 31,	2004		2003		2002

Liquids Pipelines		83.3		123.4		255.7
Gas Pipelines		10.6		11.3		—
Sponsored Investments		—		—		128.9
Gas Distribution and Services		402.1		249.0		315.0
International and Corporate		0.4		7.6		7.4

		496.4		391.3		707.0
Discontinued Operations		—		—		22.9

		496.4		391.3		729.9

ENBRIDGE INC.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Geographic Information

Revenues¹


(millions of dollars)

Year ended December 31,	2004		2003		2002

Canada		5,030.3		3,739.4		3,102.3
United States		1,482.6		1,089.6		1,418.0
Other		27.6		26.3		27.2

		6,540.5		4,855.3		4,547.5

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,	2004		2003

Canada		6,819.2		6,747.3
United States		2,241.8		1,776.6
Other		5.5		7.0

		9,066.5		8,530.9

4. D I S P O S I T I O N S

    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.

    Discontinued Operations
In the second quarter of 2002, the Company sold its retail and commercial energy services business. Earnings from discontinued operations for the year ended December 31, 2002 were $242.3 million, which included a $240.0 million gain on the sale. During the year ended December 31, 2002, the discontinued operations earned revenues of $181.9 million, incurred tax expense of $34.6 million and were allocated interest expense of $12.1 million.

5. A C Q U I S I T I O N S

Enbridge Offshore System
On December 31, 2004, the Company acquired offshore natural gas pipeline assets located in the Gulf of Mexico, from Shell US Gas & Power LLC for cash consideration of $754.0 million. The assets are held primarily through joint ventures with ownership interests ranging from 22% to 80%. This acquisition expands the Company’s natural gas operations. The acquisition has been accounted for using the purchase method with the results of

ENBRIDGE INC.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

operations included in the consolidated financial statements from December 31, 2004. The value allocated to the assets was determined by an independent appraisal.


(millions of dollars)

Fair Value of Assets Acquired:
Property, plant and equipment	591.8
Intangible assets	133.9
Goodwill	31.5
Other assets	22.5
Other liabilities	(25.7	)


	754.0

Purchase Price:
Cash (includes cash acquired of $9.5 million)	752.9
Transaction costs	1.1


	754.0

    The intangible assets, which are comprised of transportation contracts, will be amortized on the straight-line basis over their estimated useful life of 20 - 25 years. Factors that contributed to a purchase price that includes goodwill include the retention of key employees, which adds to the Company’s industry knowledge, and the potential to use these assets to accommodate the transportation needs of several proposed LNG re-gasification projects.

    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 of $145.8 million, $78.3 million was paid on the date of acquisition and $67.5 million, plus interest of $5.5 million, was paid in December 2004. This final payment triggered the vendor’s right to sell the remaining 10% to the Company at a cost of US$12.4 million. This right expires on December 31, 2005 and, if exercised, obligates the Company to buy the remaining interest.

    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.

    Other
In 2004, the Company acquired interests in other businesses for a total of $17.5 million.

    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 Enbridge Midcoast Energy sale described in Note 4. The results of operations have been included in the consolidated statement of earnings for the period of ownership.

ENBRIDGE INC.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

6. P R O P E R T Y, P L A N T A N D E Q U I P M E N T

(millions of dollars)

Weighted Average

Accumulated

December 31, 2004

Depreciation Rate

Cost

Depreciation

Net

Liquids Pipelines

Pipeline

2.4%

2,534.4

1,118.8

1,415.6

Pumping Equipment, Buildings, Tanks and Other

3.8%

2,255.9

730.4

1,525.5

Land and Right-of-Way

2.1%

38.1

17.5

20.6

Under Construction

—

37.4

—

37.4

4,865.8

1,866.7

2,999.1

Gas Pipelines

Pipeline

3.8%

1,915.7

239.5

1,676.2

Land and Right-of-Way

3.0%

51.4

5.4

46.0

Metering and Other

5.2%

122.8

13.8

109.0

Under Construction

—

35.8

—

35.8

2,125.7

258.7

1,867.0

Gas Distribution and Services

Gas Mains

4.0%

1,920.5

377.0

1,543.5

Gas Services

4.5%

1,759.9

426.4

1,333.5

Regulating and Metering Equipment

3.7%

556.6

118.0

438.6

Storage

2.7%

254.7

44.8

209.9

Computer Technology

16.1%

308.5

164.4

144.1

Other

4.7%

574.8

79.1

495.7

5,375.0

1,209.7

4,165.3

Other

10.7%

61.2

26.1

35.1

12,427.7

3,361.2

9,066.5

ENBRIDGE INC.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS


(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

ENBRIDGE INC.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

7. J O I N T V E N T U R E S

Enbridge has a joint venture interest in the following entities.


(millions of dollars)
	Ownership Interest						Net Assets
December 31,	2004			2003			2004		2003


Joint Ventures
Liquids Pipelines
Mustang Pipeline		30.0	%		30.0	%		18.8		19.0
Hardisty Caverns		50.0	%		50.0	%		35.5		33.6

Gas Pipelines
Alliance Pipeline US		50.0	%		50.0	%		391.3		385.1
Vector Pipeline		60.0	%		60.0	%		441.0		421.6
Enbridge Offshore Pipelines — various joint ventures		22% - 80	%		—			651.5		—

Gas Distribution & Services
Aux Sable		42.7	%		42.7	%		125.7		122.6
Alliance Canada Marketing		42.7	%		42.7	%		0.1		0.1
CustomerWorks Limited Partnership		70.0	%		70.0	%		59.9		51.5
Wind Power Assets		50.0	%		50.0	%		25.6		11.2

								1,749.4		1,044.7

In 2003, the Company invested $223.2 million in Alliance Pipeline Canada, Alliance Pipeline U.S., 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 less than the underlying net book value of the assets. This amount was 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 was allocated to property, plant and equipment and is being amortized over the economic life of the assets.

ENBRIDGE INC.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Following is a summary of the Joint Venture impact on the consolidated financial statements of Enbridge Inc.


(millions of dollars)
Year ended December 31,	2004			2003

Earnings
Revenues		989.7			546.8
Gas sales		(482.4	)		(168.1	)
Operating and administrative		(241.3	)		(182.1	)
Depreciation		(74.9	)		(63.3	)
Interest expense		(66.6	)		(60.4	)
Investment and other income		2.5			6.7
Income taxes		(3.0	)		0.3

Proportionate share of net earnings		124.0			79.9


Cash Flows
Cash provided by operations		36.8			128.6
Cash used in investing activities		(23.4	)		0.7
Cash used in financing activities		(2.8	)		(218.1	)

Proportionate share of increase/(decrease) in cash		10.6			(88.8	)


(millions of dollars)
December 31,	2004			2003

Financial Position
Current assets		202.0			159.3
Property, plant and equipment, net		2,010.8			1,642.7
Other long-term assets		353.5			109.6
Current liabilities		(138.7	)		(98.9	)
Long-term debt		(665.2	)		(752.4	)
Other long-term liabilities		(13.0	)		(15.6	)

Proportionate share of net assets		1,749.4			1,044.7

Included in the Company’s proportionate share of cash from joint ventures is $6.0 million (2003 — $18.7 million) held in trust, pursuant to finance agreements held by a joint venture.

ENBRIDGE INC.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

8. L O N G - T E R M I N V E S T M E N T S


(millions of dollars)
	Ownership
December 31,	Interest			2004		2003


Equity Investments
Liquids Pipelines
Chicap Pipeline		22.8	%		23.0		25.0

Sponsored Investments
The Partnership		11.6	%		730.1		743.6
Enbridge Income Fund		41.9	%		0.1		-

					730.2		743.6
Gas Distribution and Services
Noverco		32.1	%		46.0		36.7
AltaGas Income Trust		—			—		210.7
Other					3.0		16.0

					49.0		263.4
International
Compañía Logistica de Hidrocarburos (CLH)		25.0	%		663.6		531.2

Corporate					2.6		17.8

Cost Investments
Sponsored Investments
Enbridge Income Fund					380.2		380.2
Gas Distribution and Services
Noverco					181.4		181.4
Fuel Cell Energy					25.0		25.0
International
OCENSA Pipeline					223.3		223.3

					2,278.3		2,390.9

    Equity investments include $543.1 million (2003 — $536.4 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 is attributable to the value of property, plant and equipment within the investees based on estimated fair values and is amortized over the economic life of the assets.

    AltaGas Income Trust (AltaGas)
During 2004, AltaGas issued additional trust units. Enbridge did not participate in this offering causing a dilution of ownership to approximately 36% and the recognition of an $8.0 million after tax dilution gain. Enbridge subsequently disposed of its investment in AltaGas. Net of underwriting fees, total cash proceeds from the disposition were $346.7 million, resulting in an after-tax gain of $97.8 million ($121.5 million pre-tax).

    The Partnership
The Company owns 17.2% of EEM, which owns i-units, a class of limited partnership interest in EEP representing an 18.1% ownership in EEP. The Company also has a 2% general partner interest in EEP and a 6.5% direct interest for a combined 11.6% effective ownership in EEP. 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 $480.6 million (2003 — $478.8 million). The Company’s net investment in the Partnership, after deducting the non-controlling interest of $398.9 million (2003 — $396.4 million), is $331.3 million (2003 — $347.7 million).

ENBRIDGE INC.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

    In 2004, EEP completed a public issue of partnership units and in 2003, EEP completed two public issuances of partnership units. As the Company elected not to participate in these offerings, its effective interest in EEP was reduced to 11.6% from 12.2% (2003 — 12.2% from 14.1%). This resulted in recognition of a dilution gain of $7.6 million (2003 — $20.3 million), net of tax and minority interest.

    Enbridge Income Fund
The Company has 14,500,000 subordinated units of EIF and 38,023,750 preferred units of Enbridge Commercial Trust (ECT), a subsidiary of EIF, at December 31, 2004. The subordinated 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 38,023,750 preferred units are accounted for as a $380.2 million (2003 — $380.2 million) cost investment at December 31, 2004. 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, 2004 closing price of $13.94 per ordinary common unit (2003 — $12.89), is $530.1 million (2003 — $490.1 million).

    Noverco
Noverco holds an approximate 10% reciprocal shareholding in the Company. As a result, the Company has a pro-rata interest of 3.2% (2003 — 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 (2003 — $135.7 million).

    The Company owns a cost investment in Noverco, of $181.4 million (2003 — $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%. The fair value of the investment approximates it carrying value as its return is based on a floating rate.

    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. The purchase price included $340.9 million representing the excess of purchase price over the underlying net book value of the assets. The excess is attributable to the value of property, plant and equipment within the investment and is being amortized over the economic life of the assets.

    Subsequent to the initial purchase, contingent payments of 10.5 million Euros ($16.9 million) were made due to CLH meeting minimum annual and cumulative volume targets. In addition, the remaining contingent consideration that may become payable is 74.3 million Euros ($121.0 million). Of this, 63.4 million Euros ($103.3 million) has been accrued at December 31, 2004.

    OCENSA Pipeline
The Company owns a cost investment in the OCENSA Pipeline of $223.3 million (2003 — $223.3 million), which earns a fixed rate of return. The fair value of this investment is approximately $254.3 million (2003 — $270.0 million), estimated using year-end market information.

ENBRIDGE INC.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Income from Equity Investments


(millions of dollars)
Year ended December 31,	2004		2003		2002


Liquids Pipelines		1.1		1.1		1.0
Gas Pipelines		—		31.6		67.1
Sponsored Investments		79.5		73.3		40.9
Gas Distribution and Services		29.4		19.9		7.7
International		49.6		45.7		34.2
Corporate		0.7		1.2		—

		160.3		172.8		150.9

Consolidated retained earnings at December 31, 2004 include undistributed earnings from equity investments of $121.8 million (2003 — $130.5 million).

9. D E F E R R E D A M O U N T S A N D O T H E R A S S E T S


(millions of dollars)
December 31,	2004		2003


Regulatory deferrals		266.8		218.6
Contractual receivables		118.6		100.4
Long-term portion of receivables from hedge counterparty		179.9		114.3
Deferred pension funding		65.0		66.3
Deferred financing charges		39.5		42.2
Other		59.4		66.4

		729.2		608.2

At 2004 year-end, a balance of $114.7 million (2003 — $105.1 million) was subject to amortization. Amortization expense of deferred amounts in 2004 was $13.9 million (2003 — $18.4 million; 2002 — $21.7 million). Accumulated amortization at the end of 2004 was $55.6 million (2003 — $38.9 million).

ENBRIDGE INC.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

10. D E B T


(millions of dollars)
	Weighted Average
December 31,	Interest Rate			Maturity		2004		2003


Liquids Pipelines
Debentures		8.20	%		2024		200.0		200.0
Medium-term notes		6.66	%		2005 - 2029		622.8		622.7
Other¹							90.6		58.7

Gas Distribution and Services
Debentures		10.98	%		2009 - 2024		585.0		635.0
Medium-term notes		6.11	%		2005 - 2033		1,230.0		1,030.0
Other							8.4		9.5

Corporate Senior term notes (US$275.0 million)		8.08	%		2005 - 2007		331.0		397.8
Medium-term notes		6.17	%		2005 - 2032		1,692.5		1,790.0
Preferred securities		7.80	%		2051		200.0		550.0
Other²							1,796.9		1,117.7

Total Debt							6,757.2		6,411.4

Current maturities of long-term debt							530.2		450.0
Other short-term debt							173.7		185.9

Current Maturities and Short-Term Debt							703.9		635.9

Long-Term Debt							6,053.3		5,775.5

1. Primarily commercial paper borrowings.

2. Primarily commercial borrowings and drawdowns on credit facilities. Includes US$585.0 million (2003 — US$306.0 million).

    Short-term debt in the amount of $1,361.1 million (2003 — $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, 2005 through 2009 are $530.2 million, $400.0 million, $340.8 million, $602.0 million and $200.0 million, respectively.

    The Company has $200 million of 7.8% Preferred Securities outstanding. The Preferred Securities may be redeemed at the Company’s option, in whole or in part, after February 15, 2007, being the fifth anniversary of its issue. 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.

ENBRIDGE INC.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Interest Expense


(millions of dollars)
December 31,	2004			2003			2002


Long-term debt		503.8			473.2			439.3
Commercial paper and other short-term debt		21.7			20.2			29.0
Short-term borrowings		10.5			9.6			9.6
Capitalized		(10.7	)		(10.2	)		(9.5	)

		525.3			492.8			468.4

In 2004, total interest paid was $549.3 million (2003 — $508.6 million; 2002 — $473.2 million).

Credit Facilities


(millions of dollars)
December 31, 2004	Committed		Uncommitted		Drawdowns


Liquids Pipelines		150.0		—		—
Gas Distribution and Services		658.4		6.0		11.0
Corporate		2,222.2		—		361.1

		3,030.6		6.0		372.1

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 2005 and are extendible annually subject to the approval of the lenders. The committed facilities for Distribution and Services expire in 2005 and 2007 and are extendible annually thereafter subject to the approval of the lenders. The committed facilities for Corporate expire in 2005, 2006 and 2009 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. N O N - R E C O U R S E D E B T O F J O I N T V E N T U R E S


(millions of dollars)
December 31,	2004			2003


Credit Facilities of Alliance U.S. (US$8.9 million, 2003 — US$21.7 million)		10.6			28.0
Senior Notes of Alliance U.S.:
7.770% due 2015 (US$134.7 million, 2003 — US$140.0 million)		162.1			180.9
6.996% due 2019 (US$143.2 million, 2003 — US$153.4 million)		172.3			198.3
7.877% due 2025 (US$100.0 million, 2003 — US$100.0 million)		120.4			129.2
4.591% due 2025 (US$140.6 million, 2003 — US$146.2 million)		169.3			189.0
Obligations under capital leases (US$50.5 million, 2003 — US$47.4 million)		60.7			61.2

		695.4			786.6
Less current portion of long-term debt (US$25.1 million, 2003 — US$26.5 million)		(30.2	)		(34.2	)

		665.2			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.

ENBRIDGE INC.
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 and principal repayments on the Senior Notes are payable semi-annually each June 30 and December 31; principal repayments on the 7.877% Senior Notes commence June 2019. Principal repayments 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, 2005 through 2009 are $30.2 million, $43.4 million, $35.5 million, $36.1 million and $41.2 million, respectively.

12. N O N - C O N T R O L L I N G I N T E R E S T S


(millions of dollars)
December 31,	2004		2003


EEM		369.8		377.0
Enbridge Gas Distribution preferred shares		100.0		100.0
Other		45.1		46.0

		514.9		523.0

Non-controlling interests in EEM include third party interest in the investment of $398.9 million (2003 — $396.4 million) plus third party interests in distributions received from, and earnings of, EEM.

The 4,000,000 4.82% Cumulative Redeemable Enbridge Gas Distribution Preferred Shares, Group 3 Series D are entitled to fixed, cumulative, preferential dividends. Subsequent to July 1, 2009, the Company may, at its option, redeem all or a portion of the outstanding preferred shares, equal to 500,000 or more, for $25.50 if the preferred shares are listed or $25.00 in all other circumstances in each case with all accrued and unpaid dividends to the redemption date. On July 1, 2009, and every five years thereafter, the preferred shares are convertible into cumulative, redeemable preference shares, Group 2, Series D. The Series D preferred shares would pay fixed cumulative dividends quarterly at rates selected with reference to the Government of Canada yield.

13. S H A R E C A P I T A L

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.

ENBRIDGE INC.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Common Shares


(millions of dollars; number of common shares in millions)
December 31,	2004				2003				2002
	Number				Number				Number
	of Shares		Amount		of Shares		Amount		of Shares		Amount


Balance at beginning of year		171.9		2,238.0		169.7		2,169.0		162.9		1,875.9
Dividend Reinvestment and Share Purchase Plan		0.2		11.0		0.4		17.1		0.2		8.3
Issued to Noverco		—		—		—		—		0.5		23.1
Public issue		—		—		—		—		5.0		225.4
Exercise of stock options and other		1.0		33.4		1.8		51.9		1.1		36.3

Balance at end of year		173.1		2,282.4		171.9		2,238.0		169.7		2,169.0

Contributed Surplus


(millions of dollars)
December 31,	2004			2003


Balance at beginning of year		1.9			—
Stock-based compensation		3.7			1.9
Option exercises		(0.2	)		—

Balance at end of year		5.4			1.9

    The fair value based method to expense stock options has been applied on a prospective basis since January 1, 2003. Stock-based compensation expense from fixed stock options and performance-based options is recognized in earnings over the vesting period with a corresponding increase in contributed surplus. Contributed surplus is decreased and share capital is increased upon the exercise of these options.

    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, 2004, the Company may, at its option, redeem all or a portion of the outstanding preferred shares for $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.

    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 (2003 — 5.3 million shares), resulting from the investment in Noverco.

    The treasury stock method is used to determine the dilutive impact of stock options. This method assumes that any proceeds from the exercise of stock options would be used to purchase common shares at the average market price during the period.

ENBRIDGE INC.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS


(number of common shares in millions)
December 31,	2004		2003		2002


Weighted average shares outstanding		167.2		165.5		160.3
Effect of dilutive options		1.4		1.4		1.7

Diluted weighted average shares outstanding		168.6		166.9		162.0

    For the year ended December 31, 2004, 875,400 (2003 — nil, 2002 — 33,500) stock options with a weighted average exercise price of $51.47 (2003 — nil, 2002 — 46.70) were excluded from the diluted earnings per share calculation. Stock options are excluded when the exercise price exceeds the average share price in a respective period.

    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 its 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 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. S T O C K O P T I O N A N D S T O C K U N I T P L A N S

The Company maintains two plans for long-term incentive compensation: the Incentive Stock Option Plan (2002) and the Performance Stock Unit Plan (2004). The Company’s Incentive Stock Option Plan includes fixed stock options and performance-based stock options. A maximum of 15 million common shares is reserved for issuance under this plan. The Company’s Performance Stock Unit Plan grants notional units equivalent to one Enbridge Inc. common share.

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 October 1, 2014.

ENBRIDGE INC.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Outstanding Fixed Stock Options


(options in thousands; exercise price in dollars)
December 31,	2004					2003					2002
				Weighted					Weighted					Weighted
				Average					Average					Average
				Exercise					Exercise					Exercise
	Number			Price		Number			Price		Number			Price


Options at beginning of year		4,741			35.96		5,042			32.16		5,120			29.06
Options granted		891			51.47		1,042			41.65		1,024			43.80
Options exercised		(779	)		30.08		(1,244	)		26.64		(1,003	)		26.31
Options cancelled or expired		(28	)		47.30		(99	)		39.87		(99	)		37.59

Options at end of year		4,825			39.71		4,741			35.96		5,042			32.16

Options vested		2,521					2,319					2,639

Fixed Stock Option Characteristics


(options in thousands; exercise price in dollars)
December 31, 2004
	Options Outstanding						Options Vested
			Weighted
			Average		Weighted				Weighted
Exercise	Number		Remaining		Average		Number		Average
Price Range	(000’s)		Life (years)		Exercise Price		(000’s)		Exercise Price


10.30 - 19.99		40		1.16		14.90		40		14.90
20.00 - 29.99		750		4.55		25.91		750		25.91
30.00 - 39.99		1,265		5.08		36.17		1,066		35.81
40.00 - 49.99		1,895		7.48		42.62		665		42.93
50.00 - 59.99		875		9.10		51.47		—		—

		4,825						2,521

Performance-based Options
The Plan provides for the grant of performance-based 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, 2004, 810,000 remain unexercisable and were granted September 16, 2002 at $46.30 per option. 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 per share 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.

ENBRIDGE INC.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Outstanding Performance-based Options


(options in thousands; exercise price in dollars)
December 31,	2004					2003					2002
				Weighted					Weighted					Weighted
				Average					Average					Average
				Exercise					Exercise					Exercise
	Number			Price		Number			Price		Number			Price


Options at beginning of year		1,496			40.05		2,045			37.73		1,479			32.03
Options granted		—			—		—			—		810			46.30
Options exercised		(218	)		32.39		(549	)		31.39		(244	)		31.66
Options cancelled		—			—		—			—		—			—

Options at end of year		1,278			41.36		1,496			40.05		2,045			37.73

Options vested		468			32.81		686			32.67		1,235			32.10

At December 31, 2004, the exercise prices of outstanding performance-based options ranged from $31.35 to $46.30 (2003 — $31.35 to $46.30; 2002 — $31.35 to $46.30). Outstanding performance-based options will expire over a period ending no later than September 16, 2010. Vested performance-based options will expire in 2006.

Performance Stock Units
During the year ended December 31, 2004, the Company implemented a Performance Stock Unit (PSU) plan and granted 32,975 PSUs to the Company’s senior officers. Cash awards under the PSU plan may be paid out at the end of a three-year performance cycle. Awards are calculated by multiplying the number of units outstanding at the end of the performance period by the Company’s share price at the time and by a performance multiplier as determined by the Company’s total shareholder return over the three-year performance period relative to a specified peer group of companies. The performance multiplier ranges from 0, if the Company’s performance fails to meet threshold performance levels, to a maximum of 2, if the Company outperforms its peer group. Upon settlement, the number of PSUs outstanding is increased to include additional PSUs equal to the number of additional shares that would have been received had the PSUs been treated as shares enrolled in the Dividend Reinvestment Plan (DRIP) during the three-year period.

Outstanding Performance Stock Units



December 31,	2004


Units at beginning of year		-
Units granted		32,975
DRIP		869

Units at end of year		33,844

Units vested		-

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.

ENBRIDGE INC.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS


(millions of dollars)
Year ended December 31,	2004			2003			2002


Earnings applicable to common shareholders from continuing operations
As reported		645.3			667.2			330.0
Total stock-based compensation expense¹		(8.2	)		(5.9	)		(2.9	)
Included as an expense in the statement of earnings²		4.2			1.9			—

Pro forma		641.3			663.2			327.1

Earnings applicable to common shareholders
As reported		645.3			667.2			572.3
Total stock-based compensation expense¹		(8.2	)		(5.9	)		(2.9	)
Included as an expense in the statement of earnings²		4.2			1.9			—

Pro forma		641.3			663.2			569.4

Earnings per common share from continuing operations
As reported		3.86			4.03			2.06

Pro forma		3.83			4.01			2.04

Earnings per common share
As reported		3.86			4.03			3.57

Pro forma		3.83			4.01			3.55

1. Total stock-based compensation expense if the fair value based method to expense all outstanding stock options had been applied since January 1, 2002.

2. Stock-based compensation recognized as an expense in the statement of earnings for options and performance stock units granted in 2004 and 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:


	Fixed Stock Options									Performance Based Options
Year ended December 31,	2004			2003			2002			2004		2003		2002

Fair value per option	$	7.70		$	8.46		$	11.42			—		—	$	7.65
Valuation assumptions
Expected option term (yrs)		8			8			10			—		—		8
Expected volatility		15	%		22	%		25	%		—		—		24	%
Expected dividend yield		3.54	%		3.95	%		3.51	%		—		—		3.46	%
Risk-free interest rate		4.80	%		5.24	%		5.33	%		—		—		4.20	%

15. F I N A N C I A L I N S T R U M E N T S

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. In order to manage these exposures the Company utilizes derivative financial instruments to create offsetting financial positions to specific underlying or cash market physical 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.

ENBRIDGE INC.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

    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, $275 million USD (2003 — $275 million USD) 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 an aggregate notional amount of $300 million (2003 — $300 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 the value of pipeline capacity that arise from capacity commitments to the Alliance and Vector pipelines. The Company also uses derivative instruments to fix the value of variable price exposures that arise from physical asset optimization and natural gas supply agreements.

    As a result of the Company’s ownership interest in Aux Sable Products L.P., it is exposed to 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 EGD, on behalf of its ratepayers, 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, 2004, the Company had entered into natural gas price swaps and options to manage the price for approximately 27%, or 34.9 billion cubic feet, of its forecast fiscal 2005 system gas supply.

ENBRIDGE INC.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

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.

(millions of dollars unless otherwise noted)

December 31,

2004

2003

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

(51.1

)

2005-2022

535.8

(30.6

)

2005-2022

Euro cross currency swaps

493.5

(51.3

)

2005-2019

434.7

(46.1

)

2004-2019

Forwards (cumulative exchange amounts)

1,740.3

181.0

2005-2022

1,889.5

67.9

2004-2022

Energy commodities

Natural gas (bcf)

107.8

(1.0

)

2005-2010

63.6

12.4

2004-2008

Natural gas supply management (bcf)

34.9

(28.1

)

2005

13.1

(3.4

)

2004

Interest rates

Interest rate swaps

1,069.0

1.5

2005-2029

561.0

1.9

2005-2029

Forward interest rate swaps

200.0

—

2006

532.0

(1.0

)

2004-2005

    In addition, the Company has forward foreign exchange contracts with a notional principal of Canadian $214.0 million (2003 — $214.0 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 $28.8 million as at December 31, 2004 (2003 — $10.5 million).

    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, 2004 and 2003. A credit risk on derivative financial instruments amounted to $211.2 million at December 31, 2004 (2003 — $94.8 million) with no significant concentration with any single counterparty.

    Interest Rate Management
The derivative instruments used to manage interest rate risk and the associated debt related to these instruments are as follows:


(millions of dollars)
			Effective			Notional
December 31, 2004	Maturity		Interest Rate¹			Amounts

Liquids Pipelines
Commercial paper (floating to fixed interest swap)		2029		6.0	%		25.4

Corporate
Commercial paper (floating to fixed interest swap)		2005		2.7	%		400.0
Commercial paper (floating to fixed interest swap)		2005-2006		2.3	%	US$	285.5
Senior term notes (cross currency swap)		2005-2007		7.4	%	US$	275.0
Medium term notes 5.45% (fixed to floating interest swap)		2006	floating				300.0

1. After giving effect to the derivative financial instruments.

ENBRIDGE INC.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

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 fair value of other financial instruments reflect the Company’s best estimate and are based on the Company’s valuation techniques or models to estimate market values.

Total Debt


(millions of dollars)
December 31,	2004				2003
	Carrying		Fair		Carrying		Fair
	Amount		Value		Amount		Value


Liquids Pipelines		913.4		1,037.8		881.4		990.6
Gas Distribution and Services		1,823.4		2,168.9		1,674.5		1,972.1
Corporate		4,020.4		4,275.6		3,855.5		4,089.6

		6,757.2		7,482.3		6,411.4		7,108.3

The fair value of debt does not include the effects of hedging. Non-recourse debt of joint ventures has a carrying value of $695.4 million (2003 — $786.6 million) and a fair value of $769.4 million (2003 — $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. Trade receivables in Gas Pipelines also consist primarily of amounts due from companies in the oil and gas industry and are collateralized by the products contained in the 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 $45.5 million at December 31, 2004 (2003 — $35.1 million).

ENBRIDGE INC.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

16. I N C O M E T A X E S

Income Tax Rate Reconciliation


(millions of dollars)
Year ended December 31,	2004			2003			2002

Earnings before income taxes		941.4			846.7			700.4

Combined statutory income tax rate		34.4	%		35.6	%		38.0	%

Income taxes at statutory rate		323.8			301.4			266.2
Increase/(decrease) resulting from:
Tax rate changes on future income tax balances		42.7			6.2			8.1
Future income taxes related to regulated operations		(13.2	)		(34.5	)		(36.7	)
Non-taxable items, net		(44.6	)		(70.5	)		(99.5	)
Lower foreign tax rates		(40.9	)		(44.4	)		(42.2	)
Large Corporations Tax		17.6			18.1			16.9
Other		3.8			(3.7	)		8.4

Income Taxes		289.2			172.6			121.2

Continuing operations		289.2			172.6			86.6
Discontinued operations		—			—			34.6

		289.2			172.6			121.2

Effective income tax rate		30.7	%		30.4	%		17.0	%

In 2004, income taxes paid amounted to $243.2 million (2003 — $202.9 million; 2002 — $105.2 million).

Components of Future Income Taxes

(millions of dollars)

December 31,

2004

2003

Future Income Tax Liabilities

Differences in accounting and tax bases of property, plant and equipment

425.3

368.0

Differences in accounting and tax bases of investments

323.0

368.2

Other

197.2

187.2

945.5

923.4

Future Income Tax Assets

Loss carryforwards

207.5

241.7

Other

85.7

45.2

293.2

286.9

Total Net Future Income Tax Liability

652.3

636.5

Accumulated future income taxes related to rate-regulated operations, which have not been recorded in the accounts amounted to $596.8 million at December 31, 2004 (2003 — $551.2 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, 2004, the Company has recognized the benefit of unused tax loss carryforwards of $596.4 million (2003 — $708.8 million). Unused tax loss carryforwards expire as follows: 2005 - $0.3 million; 2006 — $24.9 million; 2007 — $24.6 million; 2008 — $22.1 million, 2009 — $9.5 million 2010 — $4.6 million and 2011 and beyond — $510.4 million.

ENBRIDGE INC.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Geographic Components of Pretax Earnings and Income Taxes


(millions of dollars)
Year ended December 31,	2004			2003			2002

Earnings before income taxes
Canada		682.9			651.5			299.7
United States		123.2			40.1			(5.0	)
Other		135.3			155.1			128.8

Continuing operations		941.4			846.7			423.5
Discontinued operations		—			—			276.9

		941.4			846.7			700.4

Current income taxes
Canada		267.4			93.7			152.4
United States		5.0			(10.9	)		3.2
Other		4.1			4.0			8.8

Continuing operations		276.5			86.8			164.4
Discontinued operations		—			—			36.9

		276.5			86.8			201.3

Future income taxes
Canada		(18.3	)		116.6			(67.6	)
United States		30.6			(31.0	)		(10.5	)
Other		0.4			0.2			0.3

Continuing operations		12.7			85.8			(77.8	)
Discontinued operations		—			—			(2.3	)

		12.7			85.8			(80.1	)

Current and future income taxes
Continuing operations		289.2			172.6			86.6
Discontinued operations		—			—			34.6

		289.2			172.6			121.2

ENBRIDGE INC.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

17.   P O S T - E M P L O Y M E N T   B E N E F I T S

    Pension Plans
The Company has three basic 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 benefit pension and/or defined contribution benefits to Canadian employees of Enbridge. The Enbridge U.S. pension plan provides non-contributory defined benefit pension benefits. The Company has four supplemental pension plans which provide pension benefits that exceed those benefits earned in the regulated plan.

    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 effective dates of the most recent actuarial valuations and the next required actuarial valuations for the basic plans are as follows:


	Effective Date of Most Recently	Effective Date of Next Required
	Filed Actuarial Valuation	Actuarial Valuation

Liquids Pipelines	January 1, 2004	January 1, 2007
Enbridge U.S.	January 1, 2004	January 1, 2005
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.

    Defined Contribution Plans
Contributions are generally based on the employee’s age, years of service and remuneration. For defined contribution pension benefits, pension costs equal amounts required to be contributed by the Company. Pension costs in respect of these plans during the year were $2.3 million (2003 — $2.0 million; 2002 — $2.3 million).

    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.

    The following tables detail the changes in the benefit obligation, the fair value of plan assets and the recorded asset or liability for the Company’s defined benefit pension plans and OPEB plans using the accrual method.

ENBRIDGE INC.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS


(millions of dollars)	OPEB						Pension Benefit
	2004			2003			2004			2003

Change in benefit obligation
Benefit obligation, January 1		155.7			160.5			788.3			710.1
Service cost		4.0			5.8			22.7			20.0
Interest cost		9.4			10.6			49.4			46.8
Amendments		(2.2	)		(3.3	)		0.7			—
Employee contributions		0.4			0.4			—			—
Actuarial loss		13.5			0.8			30.4			68.8
Benefits paid		(5.4	)		(5.6	)		(38.9	)		(37.8	)
Other		—			—			3.3			—
Effect of exchange rate changes		(5.1	)		(13.5	)		(8.0	)		(19.6	)

Benefit obligation, December 31		170.3			155.7			847.9			788.3

Fair value of plan assets
Fair value of plan assets, January 1		36.2			35.5			986.7			933.1
Actual return on plan assets		1.7			0.8			110.0			109.7
Employer’s contributions		9.9			11.2			14.5			11.2
Employee contributions		0.4			0.4			—			—
Benefits paid		(5.4	)		(5.6	)		(38.9	)		(37.8	)
Other		—			—			(0.8	)		(1.7	)
Effect of exchange rate changes		(2.6	)		(6.1	)		(9.7	)		(27.8	)

Fair value of plan assets, December 31		40.2			36.2			1,061.8			986.7

Asset/(Liability)
Benefit obligation, December 31		(170.3	)		(155.7	)		(847.9	)		(788.3	)
Fair value of plan assets, December 31		40.2			36.2			1,061.8			986.7

Surplus/(deficit)		(130.1	)		(119.5	)		213.9			198.4
Contribution after measurement date		—			—			2.9			2.9
Unamortized prior service cost		0.4			0.5			17.2			19.0
Unamortized transitional obligation/(asset)		24.2			29.4			(24.1	)		—
Unamortized net loss		38.9			28.0			26.0			21.0

Recorded asset/(liability)		(66.6	)		(61.6	)		235.9			241.3

The above table reflects the funded status and recorded pension and OPEB assets and liabilities 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 net pension asset was $72.9 million (2003 — $71.4 million). The net OPEB liability was $11.8 million (2003 — $10.0 million). These net assets or liabilities are recorded on the balance sheet in Deferred Amounts and Other Assets with the current portion recorded in working capital accounts.

ENBRIDGE INC.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Major Categories of Plan Assets


(millions of dollars)	OPEB										Pension Benefit
Year ended December 31,	2004					2003					2004						2003
	%			Amount		%			Amount		%			Amount			%			Amount

Equity securities		—			—		—			—		58.7	%		691.1			58.5	%		639.1
Fixed income securities		84.1	%		33.8		85.9	%		31.1		37.0	%		435.4			37.1	%		404.4
Other		15.9	%		6.4		14.1	%		5.1		4.3	%		50.4			4.4	%		47.8

Total Assets		100.0	%		40.2		100.0	%		36.2		100.0	%		1,176.9			100.0	%		1,091.3

Assets attributable to former Affiliates					—					—					(115.1	)					(104.6	)

					40.2					36.2					1,061.8						986.7

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

Expected Rate of Return on Plan Assets


	OPEB						Pension Benefit
Year ended December 31,	2004			2003			2004			2003

Canadian Plans		4.50	%		4.50	%		7.25	%		7.25	%

United States Plan		4.50	%		4.50	%		7.75	%		7.25	%

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 years, 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)

OPEB

Pension Benefit

Year ended December 31,

2004

2003

2004

2003

Total contributions

9.9

11.2

14.5

11.2

Contributions expected to be paid in 2005

10.9

12.2

Benefits Expected to be Paid by the Company


(millions of dollars)
Year ended December 31,	2005		2006		2007		2008		2009		2010 - 2014

Expected future benefit payments		48.2		47.6		49.7		52.0		54.4		316.2

ENBRIDGE INC.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Net Pension Plan and OPEB Costs Recognized


(millions of dollars)
Year ended December 31,	2004			2003			2002

Benefits earned during the year		29.0			27.7			25.2
Interest cost on projected benefit obligations		58.8			57.4			54.5
Actual return on plan assets		(111.7	)		(110.5	)		16.7
Difference between actual and expected return on plan assets		41.1			45.7			(92.0	)
Amortization of prior service costs		2.3			2.8			2.3
Amortization of transitional obligation		2.2			0.5			4.2
Amortization of actuarial loss		10.1			12.0			0.4
Special Termination Benefits		3.3			—			—
Amount charged to EEP		(7.8	)		(10.2	)		(1.7	)

Pension and OPEB cost recognized		27.3			25.4			9.6

The above table reflects the 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 $11.6 million (2003 — $9.4 million; 2002 — $(3.6) million).

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


	OPEB									Pension Benefits
Year ended December 31,	2004			2003			2002			2004			2003			2002

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	%
Average rate of return on pension plan assets		4.50	%		4.50	%		4.50	%		7.32	%		7.25	%		7.79	%

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


	OPEB									Pension Benefits
Year ended December 31,	2004			2003			2002			2004			2003			2002

Discount rate		6.21	%		6.31	%		6.79	%		6.26	%		6.29	%		6.75	%
Average rate of salary increases											4.00	%		4.00	%		4.00	%

ENBRIDGE INC.
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:


	Medical Cost Trend Rate Assumption for Next Fiscal Year	Ultimate Medical Cost Trend Rate Assumption	Year in which Ultimate Medical Cost Trend Rate Assumption is Achieved

Canadian Plans
Drugs	10%	5%	2017
Other Medical	5%	5%	2005

Enbridge U.S.	12%	5%	2012

A one percent increase in the assumed medical and dental care trend rate would result in a change of $27.1 million in the accumulated post-employment benefit obligations and a change of $2.5 million in benefit and interest costs. A one percent decrease in the assumed medical and dental care trend rate would result in a change of $21.6 million in the accumulated post-employment benefit obligations and a change of $1.9 million in benefit and interest costs.

18. I N V E S T M E N T A N D O T H E R I N C O M E


(millions of dollars)
Year ended December 31,	2004			2003			2002

Equity investments		132.2			146.3			143.5
Gain on reduction of EEP ownership interest		19.7			50.0			10.0
EEM’s equity income from EEP		28.1			26.5			7.4
Minority interest in EEM (equity income and dilution gain)		(20.2	)		(25.9	)		(4.0	)
Gain on reduction of AltaGas ownership interest		9.9			—			—
Cost investments		84.0			67.2			61.1
Investment income		25.8			32.9			22.9
Allowance for equity funds used during construction		0.9			3.2			5.3
Gain/(loss) on foreign currency contracts		(21.3	)		(87.2	)		0.1
Gain on sale of marketable securities		—			—			21.4
Other		2.6			(4.8	)		15.4

		261.7			208.2			283.1

19. C H A N G E S I N O P E R A T I N G A S S E T S A N D L I A B I L I T I E S


(millions of dollars)
Year ended December 31,	2004			2003			2002

Accounts receivable and other		(347.4	)		(346.9	)		81.5
Inventory		35.3			(232.4	)		69.5
Deferred amounts and other assets		(94.2	)		(78.9	)		72.4
Accounts payable and other		278.3			93.9			(76.4	)
Interest payable		(13.1	)		(5.5	)		4.6

		(141.1	)		(569.8	)		151.6

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

ENBRIDGE INC.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

20.   R E L A T E D   P A R T Y   T R A N S A C T I O N S

    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 $173.0 million (2003 — $128.9 million; 2002 — $97.2 million) for EEP and $9.4 million (2003 — $4.7 million) for EIF, which began operation on June 30, 2003.

    Through the ownership of Enbridge Income Fund, Enbridge has an ownership interest in Alliance Canada. Alliance Canada has administrative and operation services agreements to provide services to Alliance Pipeline L.P. (an entity Enbridge jointly controls) in exchange for reimbursement of incurred costs or at rates consistent with those obtainable from independent third parties. Certain amounts reimbursed under the services agreements with Alliance Pipeline L.P. also include a recovery of costs relating to the use of common administrative assets. The Company’s share of the amounts charged to Alliance Pipeline L.P. during the year ended December 31, 2004 were $3.2 million (six month period ended December 31, 2003 — $1.6 million).

    The receivable from affiliate of $171.7 million (2003 — $169.8 million) resulted from the sale of Enbridge Midcoast Energy to EEP and the assumption of affiliate debt. The weighted average interest rate is 6.60% for 2004 and 2003. The receivable, which matures in 2007 is denominated in U.S. dollars. The balance on December 31, 2004 was US$142.1 million (2003 — US$133.1 million). Interest income related to the affiliate receivable was $11.8 million (US$9.0 million), $21.7 million (US$15.5 million) and $7.6 million (US$4.9 million), in 2004, 2003 and 2002, respectively. The fair value of the receivable at December 31, 2004 is $171.1 million.

    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 $4.4 million for 2004 (2003 — $3.3 million; 2002 — $4.1 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 $127.0 million in 2004 (2003 — $95.5 million; 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 $50.6 million in 2004 (2003 — $40.7 million; 2002 — $41.3 million) for Alliance Pipeline, and $39.1 million in 2004 (2003 — $23.2 million; 2002 — $25.2 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 2004, this revenue amounted to $22.5 million (2003 — $25.5 million; 2002 — $35.1 million). CustomerWorks Limited Partnership began operations on January 1, 2002.

    In 2004, Enbridge Gas Services Inc., a subsidiary of the Company, purchased $30.7 million (2003 - $33.6 million; 2002 — $6.3 million) and sold $8.8 million (2003 — $1.3 million, 2002 — nil) of gas from/to Enbridge Marketing (US) Inc., a subsidiary of EEP.

    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.

ENBRIDGE INC.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

21.   C O M M I T M E N T S   A N D   C O N T I N G E N C I E S

    Enbridge Gas Distribution Inc.
Class Action Lawsuit — late payment penalties
On April 22, 2004, the Supreme Court of Canada released its decision in a case commenced against Enbridge Gas Distribution (EGD) by a customer with respect to late payment penalties. The Supreme Court of Canada determined that EGD would be required to repay a portion of amounts paid to it as late payment penalties from April 1994. The total amount of late payment penalties billed between April 1994 and February 2002 (when EGD’s late payment penalty was revised), was approximately $74 million, of which, a portion may be eligible for repayment. The amount payable is not determinable at this time. The Supreme Court has directed that a lower court determine the amount payable. Case conferences were held before a judge of the Ontario Supreme Court in August and December 2004 to discuss the remaining outstanding issues following the Supreme Court’s decision. Further court proceedings to determine the amount payable and other related issues are likely to be held in 2005. Late payment penalty revenues are included in EGD’s estimate of revenues for the year and therefore offset rates charged to customers. Revenues from late payment penalties accrue to the benefit of all customers, thereby reducing the cost of providing distribution services. The Ontario Energy Board (OEB) approved these estimates and the resulting rates each year. EGD intends to apply to the OEB for recovery of any amount payable that results from this action.

    Bloor Street Incident
EGD has been charged under both the Ontario Technical Standards and Safety Act (the TSSA) and the Ontario Occupational Health and Safety Act (the OHSA) in connection with an explosion that occurred on Bloor Street West in Toronto on April 24, 2003. The maximum possible fine upon conviction on all charges would be approximately $5.0 million in the aggregate. EGD has also been named as a defendant in a number of civil actions related to the explosion. A Coroner’s Inquest in connection with the explosion is also possible. The courts have not yet dealt with any of the charges laid under the TSSA or the OHSA, and thus it is not possible at this time to predict or comment upon the potential outcome. EGD does not expect the civil actions to result in any material financial impact.

    Remediation of Discontinued Manufactured Gas Plant Sites
The remediation of discontinued manufactured gas plant sites may result in future costs to EGD. In October 2002, a claim was filed for $55 million in damages relating to a certain manufactured gas plant site. EGD filed a statement of defence in June 2003 denying liability. EGD expects that trial scheduling will take place in the summer of 2005 and that a trial date will be fixed for early 2006. 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. EGD 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 any material financial impact.

    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 INC.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

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$217 million at December 31, 2004 (2003 — US$248 million).

22.   U N I T E D   S T A T E S   A C C O U N T I N G   P R I N C I P L E S

    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,	2004			2003			2002

Earnings under Canadian GAAP		645.3			667.2			572.3
Stock-based compensation¹		—			—			(12.1	)
Loss on ineffective hedges⁴		—			(53.8	)		—
Tax effect of the above adjustments		—			21.5			4.9

Earnings under U.S. GAAP		645.3			634.9			565.1
Unrealized net gain/(loss) on cash flow hedges⁵		(32.9	)		66.9			19.5
Reclassification adjustment on cash flow hedges⁵		—			80.6			—
Foreign currency translation adjustment⁵		2.4			(159.6	)		(1.3	)

Comprehensive income		614.8			622.8			583.3

Earnings per common share		3.86			3.84			3.53

Diluted earnings per common share		3.83			3.80			3.49

ENBRIDGE INC.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Financial Position


(millions of dollars)

December 31,	2004						2003
	Canada			United States			Canada			United States

Cash ⁶		105.5			120.3			104.1			131.7
Accounts receivable and other^5,6		1,451.9			1,483.6			1,120.7			1,174.7
Property, plant and equipment⁶		12,427.7			13,802.3			11,481.5			12,829.9
Accumulated depreciation⁶		3,361.2			3,468.2			2,950.6			2,986.0
Goodwill and intangibles⁶		165.4			581.8			—			421.5
Long-term investments⁶		2,278.3			1,898.1			2,390.9			2,009.0
Deferred amounts^2,6		729.2			1,699.2			745.7			1,477.5
Accounts payable and other⁶		1,275.9			1,375.8			894.1			1,011.7
Current maturities and short-term debt⁶		703.9			715.2			674.9			642.4
Current portion of non-recourse debt⁶		30.2			71.7			34.2			74.2
Long-term debt⁶		6,053.3			6,264.9			5,775.5			5,940.3
Non-recourse debt⁶		665.2			1,503.5			752.4			1,637.8
Other long-term liabilities⁶		151.8			158.5			148.3			154.8
Future income taxes²		652.3			1,638.9			636.5			1,558.0
Non-controlling interests⁶		514.9			689.9			523.0			709.5
Retained earnings		1,840.9			1,770.3			1,511.4			1,440.8
Additional paid in capital¹		—			27.3			—			27.3
Foreign currency translation adjustment⁵		(139.8	)		—			(147.0	)		—
Accumulated other comprehensive loss⁵		—			(147.1	)		—			(116.6	)

1.   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 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, gave rise to pre-tax compensation expense of $12.1 million. No performance-based options vested in 2003 or 2004.

2.   Future Income Taxes

    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 $596.8 million (2003 — $551.2 million) and the incremental revenue required for the recovery of unrecorded taxes of $331.3 million (2003 — $286.6 million).

ENBRIDGE INC.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

3.   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.

4.   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.

5.   Accumulated Other Comprehensive Loss

    At December 31, 2004, Accumulated Other Comprehensive Loss consists of an accumulated foreign currency translation balance of $129.1 million (2003 — $131.5 million) and net unrealized losses of $18.0 million (2003 — gains of $14.9 million). For U.S. GAAP purposes the foreign currency translation adjustment balance is classified as a component of Accumulated Other Comprehensive Loss. The fair value of derivative financial instruments that qualify as cash flow hedges are also included in Accumulated Other Comprehensive Loss. The reclassification adjustment of $80.6 million relates to the change in classification of hedging instruments between periods.

    Of the total Accumulated Other Comprehensive Loss of $147.1 million (2003 — $116.6 million), the Company estimates that approximately $27.9 million (2003 — $5.6 million), representing unrecognized net losses on derivative activities at December 31, 2004, is expected to be reclassified into earnings during the next twelve months and primarily relates to natural gas supply management.

6.   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 46R requires the primary beneficiary of a variable interest entity’s activities to consolidate the variable interest entity. FIN 46R 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.

ENBRIDGE INC.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

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.

    For variable interest entities created, or interests in variable interest entities obtained, on or before January 31, 2003, FIN 46R 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 46R.

    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.

    The U.S. GAAP adjustment reflecting the consolidation of EIF includes a $380.4 million (2003 -$381.9 million) reduction to long-term investments and a $175.0 million (2003-$186.5 million) increase in non-controlling interests.

    The following accounts of EIF are consolidated for the purposes of the U.S. GAAP financial statements:


(millions of dollars)

*December 31,*	*2004*		2003

Cash		*14.8*		27.6
Accounts receivable and other		*34.7*		34.2
Property, plant and equipment		*1,395.4*		1,454.6
Deferred amounts		*42.0*		31.5
Intangibles		*108.3*		113.4
Goodwill		*308.1*		308.1
Accounts payable and other		*33.8*		31.0
Current portion of non-recourse long-term debt		*41.5*		40.0
Long-term debt		*207.0*		201.9
Non-recourse long-term debt		*838.3*		885.4
Other long-term liabilities		*6.7*		6.5
Future income taxes		*92.1*		96.0

The consolidation of EIF increases cash by $14.8 million (2003 — $27.6 million) and the statement of cash flows would reflect an increase in cash from operations of $73.0 million (2003 — $36.4 million), cash from investing activities would decrease by $14.7 million (2003 — $359.4) million, and cash used in financing activities would decrease by $71.1 million (2003 — ($350.6) million).

ENBRIDGE INC.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

The method of consolidating EIF has been revised and the comparative amounts re-calculated to better reflect the attributes of the ECT preferred units. In the prior period the ECT preferred units were included in equity and consolidated on that basis, however because they are a preferred unit investment that has no voting rights, a stated par value and a fixed-term maturity, they have been reclassified from equity to liabilities. Therefore, the non-controlling interests increase from 27.7% to 58.1%, better reflecting their interest in the net assets of EIF.

The 2003 income reduction of $2.3 million and the $173.0 million gain reduction, as reported under US GAAP have been eliminated as a result of the change in consolidation method.

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,	2004			2003			2002

Earnings under U.S. GAAP
As reported		645.3			634.9			565.1
Stock-based compensation expense		(8.2	)		(7.9	)		(7.3	)
Included as an expense in the statement of earnings		4.2			1.9			—

Pro forma		641.3			628.9			557.8
Earnings per common share
As reported		3.86			3.84			3.53
Stock-based compensation expense		0.02			0.04			0.05

Pro forma		3.84			3.80			3.48
Diluted earnings per common share
As reported		3.83			3.80			3.49
Stock-based compensation expense		0.02			0.04			0.05

Pro forma		3.81			3.76			3.44

		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 consists of proportionately consolidated investments in pipelines that transport natural gas including the U.S. portion of the Alliance Pipeline, Vector Pipeline and a system of transmission and gathering pipelines in the Gulf of Mexico.

		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. 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, and the Company’s proportionately consolidated investment in Aux Sable, a natural gas fractionation and extraction business.

		International The Company’s International business consists of investments 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.

		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.

		The Company’s gas distribution activities within Gas Distribution and Services are conducted primarily through a wholly-owned subsidiary, Enbridge Gas Distribution Inc. (EGD). Prior to 2004, the fiscal year-end of EGD and certain smaller gas distribution subsidiaries was September 30 and their results were consolidated on a one

		quarter lag basis. In respect of 2003 and 2002, references to “December 31” mean the financial position of EGD as at September 30 and references to the “year ended December 31” mean the results of EGD for the year ended September 30. Starting in 2004, EGD changed its fiscal year end to December 31. Accordingly, the Company’s financial statements for the year ended December 31, 2004 include 15 months of results for EGD and other gas distribution subsidiaries.

		Regulation The Company’s Liquids Pipelines, Gas Pipelines, and certain Gas Distribution and Services businesses 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 for non rate-regulated entities.

		Revenue Recognition Generally, revenues are recorded when products have been delivered or services have been performed. However, certain of the Liquids Pipelines, Gas Pipelines and gas distribution operations within Gas Distribution and Services are subject to regulation and, accordingly, there are circumstances where revenues recognized do not match the cash tolls or the billed amounts.

		Certain Liquids Pipelines revenues are recognized under the terms of a committed long-term delivery contract. The Company records revenues based on the terms of the 30-year contract rather than the cash tolls received. On the Company’s main Canadian crude oil pipeline system, for rate-regulated operations, revenue is recognized in a manner that is consistent with the underlying agreements as approved by the regulatory authority.

		For rate-regulated operations in Gas Pipelines, transportation revenues include amounts related to expenses in the financial statements that are expected to be recovered from shippers in future tolls. No revenue is recognized in a given period for tolls received that do not relate to current period expenses. Differences between the recorded transportation revenue and actual toll receipts give rise to receivable or payable balances.

		A significant portion of Gas Distribution and Services operations are subject to rate-regulation and accordingly there are circumstances where the revenues recognized do not match the amounts billed. Revenue is recognized in a manner that is consistent with the underlying rate-setting mechanism as mandated by the regulators. This may give rise to regulatory assets and liabilities on the consolidated statement of financial position pending disposition by a decision of the regulators. Gas distribution revenues are recorded on the basis of regular meter readings and estimates of customer usage since the last meter reading to the end of the reporting period.

		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 the Company expects 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 Company has U.S. dollar operations, which are primarily self-sustaining except for certain financing and investing operations. The Company also holds a Euro equity investment in a foreign operation in Spain. These operations, which include those of proportionately consolidated U.S. dollar investments and the Euro 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.

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

		Inventory Inventory is primarily comprised of natural gas in storage held in EGD. Natural gas in storage is recorded in inventory at the prevailing 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.

		Intangibles and Goodwill Goodwill is not subject to amortization but is tested for impairment at least annually and written down to fair value if the criteria for impairment are met. Goodwill represents the excess of the purchase price over the fair value of net identifiable assets upon acquisition of a business. Intangible assets consist of long-term transportation contracts and are amortized on a straight-line basis over the expected life of the contracts. The depreciation rate for intangibles is 4%.

		Asset Retirement Obligations No material amount has been recorded for asset retirement obligations relating to the Company’s assets as it is not possible to make a reasonable estimate of the fair value of the liability due to the indeterminate timing and scope of the asset retirements. Management also believes it is reasonable to assume that all retirement costs associated with the regulated pipelines will be recovered through tolls in future periods.

		Depreciation expense for Gas Distribution and Services operations includes a provision for asset retirement obligations at rates approved by the regulator. Actual costs incurred are charged to accumulated depreciation.

		Deferred Amounts and Other Assets The Company defers certain charges, which the regulatory authorities permit to be recovered through future rates. Assets are realized and liabilities are settled based on the terms of the regulatory approval once 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 hedged items. Deferred financing charges are amortized on a straight-line basis, which approximates the effective interest method, over the life of the related debt and classified as interest expense. The Company recognizes revenues under the terms of a committed long-term delivery contract, which result in a long-term receivable.

		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 Gas Distribution and Services 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.

		Pension plan assets are measured at fair value. The expected return on pension plan assets is determined using market-related values. Market related values have been calculated using the fair value method. Adjustments arising from plan amendments and the transitional amounts recognized upon adoption of the accounting standard are amortized on a straight-line basis over the average remaining service period of the employees active at the date of amendment. The excess of the net actuarial gain or loss over ten per cent of the greater of the benefit obligation and the fair value of plan assets is amortized over the average remaining service period of the active employees.

		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 Gas Distribution and Services where the cost of providing these benefits is expensed as paid, consistent with the recovery of such costs in rates.

		The measurement date used to determine the plan assets and the accrued benefit obligation was September 30, 2004.

		Stock Based Compensation Stock options granted after January 1, 2003 are accounted for under the fair value method. Under this method, compensation expense is measured at fair value at the grant date using the Black-Scholes option pricing model and recognized over the vesting period with a corresponding credit to contributed surplus. Stock options granted prior to January 1, 2003 continue to be accounted for as capital transactions when the options are exercised, which does not give rise to compensation expense.

		Performance stock units (PSUs) are accounted for over the three-year term on a mark-to-market basis whereby a liability and expense are recorded based on the number of PSUs outstanding, the current market price of the Company’s shares and the Company’s current performance relative to the specified peer group.

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

		Recently Adopted Accounting Standards Asset Retirement Obligations Effective January 1, 2004, the Company adopted the new CICA standard for asset retirement obligations. This new standard requires that the fair value of asset retirement obligations associated with the retirement of long-lived assets is recognized in the period incurred. The fair value, which approximates the cost a third party would incur in performing the tasks necessary to retire such assets, is recognized at the present value of expected future cash flows and is added to the carrying value of the associated asset and depreciated over the asset’s useful life. The liability is accreted over time through periodic charges to earnings and is reduced by actual costs of decommissioning and reclamation.

		No material amount has been recorded for asset retirement obligations relating to the Company’s assets as it is not possible to make a reasonable estimate of the fair value of the liability due to the indeterminate timing and scope of the asset retirements. Management also believes it is reasonable to assume that all retirement costs associated with the regulated pipelines will be recovered through tolls in future periods.

		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 expired in 2004.

		Effective January 1, 2003, the Company early adopted revised requirements in the CICA standard for stock-based compensation. The standard 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 resulted in a charge to income, in the year of adoption, of $1.9 million.

		Preferred Securities Effective December 31, 2004, the Company early adopted amendments to the CICA standard on the disclosure and presentation of financial instruments. The amendments require the Company’s preferred securities to be classified wholly as debt rather than splitting the principal and payments components of the securities into debt and equity. The amendments were adopted retroactively and have resulted in financial statement impacts summarized in the table below. In December 2004, $350 million of preferred securities were redeemed.

		Impairment of Long-lived Assets Effective January 1, 2004, the Company adopted the new CICA standard for recognizing, measuring and disclosing impairment of long-lived assets held for use. The new standard has not had a significant impact on the Company’s financial results.

		Hedging Relationships Effective January 1, 2004, the Company adopted the new guideline 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 related to instruments recorded in the statement of financial position is to be recognized in income for the period. The new guideline has not had a significant impact on the Company’s financial results.

		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. At present, the standard has an exemption for rate-regulated operations and, as a result, has not had a significant impact on the Company’s financial results.

		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.

		Discontinued Operations In the second quarter of 2002, the Company sold its retail and commercial energy services business. Earnings from discontinued operations for the year ended December 31, 2002 were $242.3 million, which included a $240.0 million gain on the sale. During the year ended December 31, 2002, the discontinued operations earned revenues of $181.9 million, incurred tax expense of $34.6 million and were allocated interest expense of $12.1 million.

		The intangible assets, which are comprised of transportation contracts, will be amortized on the straight-line basis over their estimated useful life of 20 - 25 years. Factors that contributed to a purchase price that includes goodwill include the retention of key employees, which adds to the Company’s industry knowledge, and the potential to use these assets to accommodate the transportation needs of several proposed LNG re-gasification projects.

		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 of $145.8 million, $78.3 million was paid on the date of acquisition and $67.5 million, plus interest of $5.5 million, was paid in December 2004. This final payment triggered the vendor’s right to sell the remaining 10% to the Company at a cost of US$12.4 million. This right expires on December 31, 2005 and, if exercised, obligates the Company to buy the remaining interest.

		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.

		Other In 2004, the Company acquired interests in other businesses for a total of $17.5 million.

		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 Enbridge Midcoast Energy sale described in Note 4. The results of operations have been included in the consolidated statement of earnings for the period of ownership.

	In 2003, the Company invested $223.2 million in Alliance Pipeline Canada, Alliance Pipeline U.S., 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 less than the underlying net book value of the assets. This amount was 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 was allocated to property, plant and equipment and is being amortized over the economic life of the assets.

	Equity investments include $543.1 million (2003 — $536.4 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 is attributable to the value of property, plant and equipment within the investees based on estimated fair values and is amortized over the economic life of the assets.

	AltaGas Income Trust (AltaGas) During 2004, AltaGas issued additional trust units. Enbridge did not participate in this offering causing a dilution of ownership to approximately 36% and the recognition of an $8.0 million after tax dilution gain. Enbridge subsequently disposed of its investment in AltaGas. Net of underwriting fees, total cash proceeds from the disposition were $346.7 million, resulting in an after-tax gain of $97.8 million ($121.5 million pre-tax).

	The Partnership The Company owns 17.2% of EEM, which owns i-units, a class of limited partnership interest in EEP representing an 18.1% ownership in EEP. The Company also has a 2% general partner interest in EEP and a 6.5% direct interest for a combined 11.6% effective ownership in EEP. 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 $480.6 million (2003 — $478.8 million). The Company’s net investment in the Partnership, after deducting the non-controlling interest of $398.9 million (2003 — $396.4 million), is $331.3 million (2003 — $347.7 million).

	In 2004, EEP completed a public issue of partnership units and in 2003, EEP completed two public issuances of partnership units. As the Company elected not to participate in these offerings, its effective interest in EEP was reduced to 11.6% from 12.2% (2003 — 12.2% from 14.1%). This resulted in recognition of a dilution gain of $7.6 million (2003 — $20.3 million), net of tax and minority interest.

	Enbridge Income Fund The Company has 14,500,000 subordinated units of EIF and 38,023,750 preferred units of Enbridge Commercial Trust (ECT), a subsidiary of EIF, at December 31, 2004. The subordinated 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 38,023,750 preferred units are accounted for as a $380.2 million (2003 — $380.2 million) cost investment at December 31, 2004. 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, 2004 closing price of $13.94 per ordinary common unit (2003 — $12.89), is $530.1 million (2003 — $490.1 million).

	Noverco Noverco holds an approximate 10% reciprocal shareholding in the Company. As a result, the Company has a pro-rata interest of 3.2% (2003 — 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 (2003 — $135.7 million).

	The Company owns a cost investment in Noverco, of $181.4 million (2003 — $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%. The fair value of the investment approximates it carrying value as its return is based on a floating rate.

	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. The purchase price included $340.9 million representing the excess of purchase price over the underlying net book value of the assets. The excess is attributable to the value of property, plant and equipment within the investment and is being amortized over the economic life of the assets.

	Subsequent to the initial purchase, contingent payments of 10.5 million Euros ($16.9 million) were made due to CLH meeting minimum annual and cumulative volume targets. In addition, the remaining contingent consideration that may become payable is 74.3 million Euros ($121.0 million). Of this, 63.4 million Euros ($103.3 million) has been accrued at December 31, 2004.

	OCENSA Pipeline The Company owns a cost investment in the OCENSA Pipeline of $223.3 million (2003 — $223.3 million), which earns a fixed rate of return. The fair value of this investment is approximately $254.3 million (2003 — $270.0 million), estimated using year-end market information.

1.	Primarily commercial paper borrowings.
2.	Primarily commercial borrowings and drawdowns on credit facilities. Includes US$585.0 million (2003 — US$306.0 million).

	Short-term debt in the amount of $1,361.1 million (2003 — $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, 2005 through 2009 are $530.2 million, $400.0 million, $340.8 million, $602.0 million and $200.0 million, respectively.

	The Company has $200 million of 7.8% Preferred Securities outstanding. The Preferred Securities may be redeemed at the Company’s option, in whole or in part, after February 15, 2007, being the fifth anniversary of its issue. 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.

	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 and principal repayments on the Senior Notes are payable semi-annually each June 30 and December 31; principal repayments on the 7.877% Senior Notes commence June 2019. Principal repayments 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, 2005 through 2009 are $30.2 million, $43.4 million, $35.5 million, $36.1 million and $41.2 million, respectively.

	Non-controlling interests in EEM include third party interest in the investment of $398.9 million (2003 — $396.4 million) plus third party interests in distributions received from, and earnings of, EEM.

	The 4,000,000 4.82% Cumulative Redeemable Enbridge Gas Distribution Preferred Shares, Group 3 Series D are entitled to fixed, cumulative, preferential dividends. Subsequent to July 1, 2009, the Company may, at its option, redeem all or a portion of the outstanding preferred shares, equal to 500,000 or more, for $25.50 if the preferred shares are listed or $25.00 in all other circumstances in each case with all accrued and unpaid dividends to the redemption date. On July 1, 2009, and every five years thereafter, the preferred shares are convertible into cumulative, redeemable preference shares, Group 2, Series D. The Series D preferred shares would pay fixed cumulative dividends quarterly at rates selected with reference to the Government of Canada yield.

	The fair value based method to expense stock options has been applied on a prospective basis since January 1, 2003. Stock-based compensation expense from fixed stock options and performance-based options is recognized in earnings over the vesting period with a corresponding increase in contributed surplus. Contributed surplus is decreased and share capital is increased upon the exercise of these options.

	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, 2004, the Company may, at its option, redeem all or a portion of the outstanding preferred shares for $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.

	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 (2003 — 5.3 million shares), resulting from the investment in Noverco.

	The treasury stock method is used to determine the dilutive impact of stock options. This method assumes that any proceeds from the exercise of stock options would be used to purchase common shares at the average market price during the period.

	For the year ended December 31, 2004, 875,400 (2003 — nil, 2002 — 33,500) stock options with a weighted average exercise price of $51.47 (2003 — nil, 2002 — 46.70) were excluded from the diluted earnings per share calculation. Stock options are excluded when the exercise price exceeds the average share price in a respective period.

	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 its 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 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.

	The Company maintains two plans for long-term incentive compensation: the Incentive Stock Option Plan (2002) and the Performance Stock Unit Plan (2004). The Company’s Incentive Stock Option Plan includes fixed stock options and performance-based stock options. A maximum of 15 million common shares is reserved for issuance under this plan. The Company’s Performance Stock Unit Plan grants notional units equivalent to one Enbridge Inc. common share.

	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 October 1, 2014.

	At December 31, 2004, the exercise prices of outstanding performance-based options ranged from $31.35 to $46.30 (2003 — $31.35 to $46.30; 2002 — $31.35 to $46.30). Outstanding performance-based options will expire over a period ending no later than September 16, 2010. Vested performance-based options will expire in 2006.

	Performance Stock Units During the year ended December 31, 2004, the Company implemented a Performance Stock Unit (PSU) plan and granted 32,975 PSUs to the Company’s senior officers. Cash awards under the PSU plan may be paid out at the end of a three-year performance cycle. Awards are calculated by multiplying the number of units outstanding at the end of the performance period by the Company’s share price at the time and by a performance multiplier as determined by the Company’s total shareholder return over the three-year performance period relative to a specified peer group of companies. The performance multiplier ranges from 0, if the Company’s performance fails to meet threshold performance levels, to a maximum of 2, if the Company outperforms its peer group. Upon settlement, the number of PSUs outstanding is increased to include additional PSUs equal to the number of additional shares that would have been received had the PSUs been treated as shares enrolled in the Dividend Reinvestment Plan (DRIP) during the three-year period.

1.	Total stock-based compensation expense if the fair value based method to expense all outstanding stock options had been applied since January 1, 2002.
2.	Stock-based compensation recognized as an expense in the statement of earnings for options and performance stock units granted in 2004 and 2003 as a result of the adoption of the fair-valued based method January 1, 2003.

	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. In order to manage these exposures the Company utilizes derivative financial instruments to create offsetting financial positions to specific underlying or cash market physical 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, $275 million USD (2003 — $275 million USD) 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 an aggregate notional amount of $300 million (2003 — $300 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 the value of pipeline capacity that arise from capacity commitments to the Alliance and Vector pipelines. The Company also uses derivative instruments to fix the value of variable price exposures that arise from physical asset optimization and natural gas supply agreements.

	As a result of the Company’s ownership interest in Aux Sable Products L.P., it is exposed to 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 EGD, on behalf of its ratepayers, 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, 2004, the Company had entered into natural gas price swaps and options to manage the price for approximately 27%, or 34.9 billion cubic feet, of its forecast fiscal 2005 system gas supply.

	In addition, the Company has forward foreign exchange contracts with a notional principal of Canadian $214.0 million (2003 — $214.0 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 $28.8 million as at December 31, 2004 (2003 — $10.5 million).

	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, 2004 and 2003. A credit risk on derivative financial instruments amounted to $211.2 million at December 31, 2004 (2003 — $94.8 million) with no significant concentration with any single counterparty.

	Interest Rate Management The derivative instruments used to manage interest rate risk and the associated debt related to these instruments are as follows:

	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 fair value of other financial instruments reflect the Company’s best estimate and are based on the Company’s valuation techniques or models to estimate market values.

	Total Debt

	The fair value of debt does not include the effects of hedging. Non-recourse debt of joint ventures has a carrying value of $695.4 million (2003 — $786.6 million) and a fair value of $769.4 million (2003 — $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. Trade receivables in Gas Pipelines also consist primarily of amounts due from companies in the oil and gas industry and are collateralized by the products contained in the 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 $45.5 million at December 31, 2004 (2003 — $35.1 million).

	In 2004, income taxes paid amounted to $243.2 million (2003 — $202.9 million; 2002 — $105.2 million).

	Components of Future Income Taxes

	Accumulated future income taxes related to rate-regulated operations, which have not been recorded in the accounts amounted to $596.8 million at December 31, 2004 (2003 — $551.2 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, 2004, the Company has recognized the benefit of unused tax loss carryforwards of $596.4 million (2003 — $708.8 million). Unused tax loss carryforwards expire as follows: 2005 - $0.3 million; 2006 — $24.9 million; 2007 — $24.6 million; 2008 — $22.1 million, 2009 — $9.5 million 2010 — $4.6 million and 2011 and beyond — $510.4 million.

17.	P O S T - E M P L O Y M E N T B E N E F I T S

	Pension Plans The Company has three basic 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 benefit pension and/or defined contribution benefits to Canadian employees of Enbridge. The Enbridge U.S. pension plan provides non-contributory defined benefit pension benefits. The Company has four supplemental pension plans which provide pension benefits that exceed those benefits earned in the regulated plan.

	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 effective dates of the most recent actuarial valuations and the next required actuarial valuations for the basic plans are as follows:

	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.

	Defined Contribution Plans Contributions are generally based on the employee’s age, years of service and remuneration. For defined contribution pension benefits, pension costs equal amounts required to be contributed by the Company. Pension costs in respect of these plans during the year were $2.3 million (2003 — $2.0 million; 2002 — $2.3 million).

	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.

	The following tables detail the changes in the benefit obligation, the fair value of plan assets and the recorded asset or liability for the Company’s defined benefit pension plans and OPEB plans using the accrual method.

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

	Expected Rate of Return on Plan Assets