Overview

Enbridge Inc. (Enbridge or the Company) is a publicly traded energy transportation and distribution company. Enbridge conducts its business through five operating segments identified based on products and services offered: 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 Canadian common carrier pipeline and feeder pipelines that transport crude oil and other liquid hydrocarbons including the Enbridge System, the Athabasca System, Spearhead Pipeline, Southern Lights Pipeline and a proportionately consolidated investment in the Olympic Pipeline.

GAS PIPELINES

Gas Pipelines consists of proportionately consolidated investments in natural gas pipelines including the U.S. portion of the Alliance Pipeline, Vector Pipeline and 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), a publicly traded master limited partnership, and Enbridge Energy Management, L.L.C. (EEM) (collectively, the Partnership) as well as 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. EIF is a publicly traded income fund whose primary operations include a 50% interest in the Canadian portion of the Alliance Pipeline and a crude oil and liquids pipeline and gathering system.

GAS DISTRIBUTION AND SERVICES

Gas Distribution and Services consists of natural 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.

The Company's commodity marketing businesses are also included in Gas Distribution and Services. These businesses manage the Company's volume commitments on Alliance and Vector Pipelines as well as offer commodity storage, transport and supply management services.

INTERNATIONAL

The Company's International business consists of investments in two energy-delivery businesses, Oleoducto Central S.A. (OCENSA) in Colombia and, prior to its sale in June 2008, Compañía Logística de Hidrocarburos CLH, S.A. (CLH) in Spain.

CORPORATE

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

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

The consolidated financial statements of the Company are prepared in accordance with Canadian generally accepted accounting principles (Canadian GAAP). These accounting principles are different in some respects from United States generally accepted accounting principles (U.S. GAAP) and the significant differences that impact the Company's financial statements are described in Note 32. Amounts are stated in Canadian dollars unless otherwise noted.

The preparation of financial statements in conformity with Canadian GAAP 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. The most significant assets and liabilities where we must make estimates include: values of regulatory assets and liabilities (Note 4); depreciation rates of property, plant and equipment (Note 8); amortization rates of intangible assets (Note 12); measurement of goodwill (Note 13); valuation of share based compensation (Note 19); fair values of financial instruments (Note 21 and Note 22); income taxes (Note 24); post employment benefits (Note 25) and commitments and contingencies (Note 29). 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. EIF is consolidated in the accounts of the Company because it is a variable interest entity. The Company is the primary beneficiary of EIF through a combination of a 41.9% equity interest and a preferred unit investment. 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 according to their classification as held to maturity, loans and receivables or available for sale (see Financial Instruments). All long-term investments are assessed for impairment if the Company identifies an event indicative of possible impairment.

REGULATION

Certain of the Company's Liquids Pipelines, Gas Pipelines and Gas Distribution and Services businesses are subject to regulation by various authorities including, but not limited to, the National Energy Board (NEB), the Federal Energy Regulatory Commission (FERC), the Energy Resources Conservation Board in Alberta (ERCB), the New Brunswick Energy and Utilities Board (EUB) and the Ontario Energy Board (OEB). Regulatory bodies exercise statutory authority over matters such as construction, rates and ratemaking and agreements with customers. 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.

Regulatory assets represent amounts that are expected to be recovered from customers in future periods through rates. Regulatory liabilities represent amounts that are expected to be refunded to customers in future periods through rates. In the absence of rate regulation, the Company would not recognize regulatory assets or liabilities and the earnings impact would be recorded in the period the expenses are incurred or revenues are earned. Long-term regulatory assets are recorded in Deferred Amounts and Other Assets and current regulatory assets are recorded in Accounts Receivable and Other. Long-term regulatory liabilities are included in Other Long-Term Liabilities and current regulatory liabilities are recorded in Accounts Payable and Other. Regulatory assets are assessed for impairment if the Company identifies an event indicative of possible impairment (Note 4).

Allowance for funds used during construction (AFUDC) is included in the cost of property, plant and equipment and is depreciated over future periods as part of the total cost of the related asset. AFUDC includes both an interest component and, if approved by the regulator, a cost of equity component. In the absence of rate regulation, the Company would capitalize only the interest component; therefore, the capitalized equity component, the corresponding earnings during the construction phase and the subsequent depreciation would not be recognized.

Certain regulators prescribe the pool method of accounting for property, plant and equipment where similar assets with comparable useful lives are grouped and depreciated as a pool. When those assets are retired or otherwise disposed of, gains and losses are not reflected in earnings but are booked as an adjustment to accumulated depreciation. Entities not subject to rate regulation write off the net book value of the retired asset and include any resulting gain or loss in earnings.

With the approval of the regulator, Enbridge Gas Distribution (EGD) capitalizes a percentage of certain operating costs. EGD is authorized to charge depreciation and earn a return on the net book value of such capitalized costs in future years. In the absence of rate regulation, a portion of such costs may be charged to current earnings.

Contributions made to the defined benefit pension plan and the cost of providing post-employment benefits other than pensions (OPEB) for the regulated operations of Gas Distribution and Services are expensed as paid, consistent with the recovery of such costs in rates. Canadian GAAP requires costs and obligations for defined benefit pension plans and OPEB to be determined using the projected benefit method and charged to earnings as services are rendered.

REVENUE RECOGNITION

For businesses which are not rate-regulated, revenues are recorded when products have been delivered or services have been performed. Customer credit worthiness is assessed before agreements are signed.

For the rate-regulated portion of the Company's main Canadian crude oil pipeline system, revenue is recognized in a manner that is consistent with the underlying agreements as approved by the regulator. Certain Liquids Pipelines revenues are recognized under the terms of a committed 30-year delivery contract rather than the cash tolls received.

For rate-regulated operations in Gas Pipelines and Sponsored Investments, transportation revenues include amounts related to expenses recognized in the financial statements that are expected to be recovered from shippers in future tolls. Revenue is recognized in a given period for tolls received to the extent that expenses are incurred. 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. Revenue is recognized in a manner that is consistent with the underlying rate-setting mechanism as mandated by the regulator. Gas distribution revenues are recorded on the basis of regular meter readings and estimates of customer usage from the last meter reading to the end of the reporting period. For the non-regulated portion of Gas Distribution and Services operations, delivery or service performance only takes place when there is a sales contract in place specifying delivery volumes or services required and sales prices.

FINANCIAL INSTRUMENTS

The Company classifies financial assets as either held for trading, held to maturity, loans and receivables or available for sale. The Company classifies financial liabilities as either held for trading or other financial liabilities.

Financial assets and liabilities that are "held for trading" are measured at fair value with changes in fair value recognized in earnings in other investment income, except for derivatives that are designated as, and determined to be, effective hedging instruments, whose changes in fair value are recorded in Other Comprehensive Income (OCI).

Generally, the Company classifies equity investments in other entities that are not accounted for under the equity method or joint venture accounting as "available for sale". Financial assets that are available for sale are measured at fair value, with changes in those fair values recorded in OCI. Where actively quoted prices are not available for fair value measurement, these financial assets are measured at amortized cost. Dividends received from available for sale financial assets are recognized when the right to receive payment is established.

The Company assesses at each balance sheet date whether there is objective evidence that a financial asset is impaired. For investments classified as "available for sale", where no actively quoted market exists for the security, the Company internally values the expected discounted cash flows using observable market inputs and determines whether the decline below carrying value is other than temporary. If the decline is determined to be other than temporary, an impairment charge is recorded in earnings with an offsetting reduction to the carrying value of the investment.

Financial assets that are "held to maturity" and "loans and receivables" and financial liabilities that are "other financial liabilities" are measured at amortized cost using the effective interest method of amortization.

Cash and cash equivalents are designated as "held for trading" and are measured at carrying value which approximates fair value due to the short-term nature of these instruments. Accounts receivable and other are designated as "loans and receivables". Short-term borrowings, accounts payable and other, interest payable, long-term debt and non-recourse long-term debt are designated as "other financial liabilities".

Transaction Costs

Transaction costs are incremental costs directly related to the acquisition of a financial asset or the issuance of a financial liability. The Company incurs transaction costs primarily through the issuance of debt and classifies these costs with the related debt. These costs are amortized using the effective interest rate method over the life of the related debt instrument.

Hedges

The Company uses derivatives and non-derivative financial instruments to manage changes in commodity prices, foreign currency exchange rates and interest rates. Hedge accounting is optional and it requires the Company to document the hedging relationship and test the hedging item's effectiveness in offsetting changes in fair values or cash flows of the underlying hedged item on an ongoing basis. The Company presents the earnings and cash flow effects of hedging items with the hedged transaction.

Cash Flow Hedges

The Company uses cash flow hedges to manage changes in commodity prices, foreign currency exchange rates and interest rates. The effective portion of the change in the fair value of a cash flow hedging instrument is recorded in OCI and reclassified to earnings when the hedged item impacts earnings or to the carrying value of the related non-financial asset or liability. Any hedge ineffectiveness is recorded in current period earnings.

If a derivative instrument designated as a cash flow hedge ceases to be effective or is terminated, hedge accounting is discontinued and the gain or loss at that date is deferred in OCI and recognized concurrently with the related transaction. If a hedged anticipated transaction is no longer probable, the gain or loss is recognized immediately in earnings. Subsequent gains and losses from ineffective derivative instruments are recognized in earnings in the period they occur.

Fair Value Hedges

The Company may use fair value hedges to hedge the fair value of debt instruments or commodity positions. The change in the fair value of the hedging instrument is recorded in earnings with changes in the fair value of the hedged asset or liability that is designated as part of the hedging relationship. If a fair value hedge is discontinued or ceases to be effective, the hedged asset or liability ceases to be remeasured at fair value and the fair value adjustment is recognized in earnings over the remaining life of the hedged item.

Net Investment Hedges

The Company uses net investment hedges to manage the carrying values of U.S. dollar denominated foreign investments. The effective portion of the change in the fair value of the hedging instrument is recorded in OCI. Any ineffectiveness is recorded in current period earnings. Amounts recorded in Accumulated Other Comprehensive Income or Loss (AOCI) are recognized in earnings when there is a reduction of the hedged net investment resulting from a sale of ownership interests.

Non-Hedge Derivatives

If a derivative instrument is not an effective hedge for accounting purposes or is not designated as hedging item, changes in the fair value are recorded in current period earnings.

INCOME TAXES

For non-regulated operations, the liability method of accounting for income taxes is followed. Future income tax assets and liabilities are recorded 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.

The regulated activities of the Company recover income tax expense based on the taxes payable method when prescribed by regulators or in ratemaking agreements that are subject to regulatory approval. As a result, rates do not include the recovery of future income taxes related to temporary differences and the Company does not record future income tax assets or liabilities related to these differences. The Company expects that all unrecorded future income taxes will be recovered in rates when they become payable.

FOREIGN CURRENCY TRANSLATION

The Company's U.S. dollar operations are primarily self-sustaining. Self-sustaining operations 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 monthly average rates. Gains and losses arising on translation of these operations are included in the cumulative translation adjustment component of AOCI.

Monetary assets and liabilities of the Company that are denominated in foreign currencies are translated into its functional currency at the rates of exchange in effect at the period end date. Gains or losses on foreign exchange are recorded in the Consolidated Statements of Earnings.

CASH AND CASH EQUIVALENTS

Cash and cash equivalents include short-term 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 at the quarterly 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. The difference between the approved price and the actual cost of the gas purchased is deferred for future refund or collection as approved by the OEB. Other inventory, consisting primarily of commodities held in storage, is recorded at the lower of cost and net realizable value.

PROPERTY, PLANT AND EQUIPMENT

Expenditures for construction, expansion, major renewals and betterments are capitalized; maintenance and repair costs are expensed as incurred. Expenditures for project development are capitalized if they are expected to have a future benefit. The Company capitalizes interest incurred during construction. For rate-regulated assets, if approved, an allowance for equity funds used during construction (AEDC) is capitalized at rates authorized by the regulatory authorities. Depreciation of property, plant and equipment is provided on a straight-line basis over the estimated service lives of the assets commencing when the asset is placed in service.

IMPAIRMENT OF LONG-LIVED ASSETS

The Company reviews the carrying values of its long-lived assets at least annually or as events or changes in circumstances warrant. If it is determined that the carrying value of an asset exceeds the fair value and that the decline is other than temporary based on future cash flows, the assets are written down to fair value.

DEFERRED AMOUNTS AND OTHER ASSETS

Deferred amounts and other assets include costs which regulatory authorities have permitted, or are expected to permit, to be recovered through future rates, contractual receivables under the terms of long-term delivery contracts, derivative financial instruments as well as pension assets. Certain deferred amounts are amortized on a straight-line basis over various periods depending on the nature of the charges.

INTANGIBLE ASSETS

Intangible assets consist primarily of acquired long-term transportation contracts which are amortized on a straight-line basis over the expected lives of the contracts.

GOODWILL

Goodwill represents the excess of the purchase price over the fair value of net identifiable assets on acquisition of a business. Goodwill is not subject to amortization but is tested for impairment at least annually. For the purposes of impairment testing, reporting units are identified as business operations within an operating segment. Potential impairment is identified when the carrying value of a reporting unit, including allocated goodwill, exceeds its fair value. Goodwill impairment is measured as the excess of the carrying amount of the reporting unit's allocated goodwill over the implied fair value of the goodwill, based on the fair value of the assets and liabilities of the reporting unit.

ASSET RETIREMENT OBLIGATIONS

Asset retirement obligations (AROs) associated with the retirement of long-lived assets are measured at fair value and recognized as Other Long-Term Liabilities in the period when they can be reasonably determined. The fair value approximates the cost a third party would charge in performing the tasks necessary to retire such assets and is recognized at the present value of expected future cash flows. AROs are added to the carrying value of the associated asset and depreciated over the asset's useful life. The corresponding liability is accreted over time through charges to earnings and is reduced by actual costs of decommissioning and reclamation. The Company's estimates of retirement costs could change as a result of changes in cost estimates and regulatory requirements.

For certain of the Company's assets it is not possible to make a reasonable estimate of AROs due to the indeterminate timing and scope of the asset retirements.

Depreciation expense for Gas Distribution and Services operations includes a provision for AROs at rates approved by the regulator. Actual costs incurred are charged to accumulated depreciation in accordance with regulatory treatment.

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 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. Adjustments arising from plan amendments and the transitional amounts recognized on 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 or transition. The excess of the net actuarial gain or loss over 10% 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.

STOCK-BASED COMPENSATION

Stock options granted are recorded using the fair value method. Under this method, compensation expense is measured at fair value at the grant date and is recognized on a straight-line basis over the shorter of the vesting period or the period to early retirement eligibility with a corresponding credit to contributed surplus. Balances in contributed surplus are transferred to share capital when the options are exercised.

Performance Stock Units (PSUs) vest at the completion of a three-year term and Restricted Stock Units vest at the completion of a 35-month term; both are settled in cash. During the term, an expense is recorded based on the number of units outstanding and the current market price of the Company's shares with an offset to Other Long-Term Liabilities. The value of the PSU's is also dependent on the Company's performance relative to performance targets set out under the plan.

COMPARATIVE AMOUNTS

Where practical, or considered material to the reader, certain comparative amounts have been reclassified to conform with the current year's financial statement presentation.

2. CHANGES IN ACCOUNTING POLICIES

FINANCIAL INSTRUMENTS, COMPREHENSIVE INCOME AND HEDGING RELATIONSHIPS

Effective January 1, 2007, the Company adopted the Canadian Institute of Chartered Accountants (CICA) Handbook Section 1530 Comprehensive Income, Section 3251 Equity, Section 3855 Financial Instruments – Recognition and Measurement, Section 3861 Financial Instruments – Disclosure and Presentation and Section 3865 Hedges. In accordance with the transitional provisions in these new standards, these policies were adopted prospectively and accordingly, the prior periods were not restated. Prior period unrealized gains and losses related to the Company's foreign currency translation adjustments and net investment hedges are now included in AOCI.

Comprehensive Income and Equity

The new standards introduced comprehensive income, which consists of earnings and OCI. The cumulative changes in OCI are recorded in AOCI, a separate component of shareholders' equity. The cumulative translation adjustment, previously presented as a separate component of shareholders' equity, is now presented as a component of AOCI. The components of AOCI are presented in Note 20.

Financial Instruments

CICA Handbook Section 3855 established recognition and measurement criteria for financial instruments and requires that, generally, all financial instruments are recorded at fair value on initial recognition. Subsequent measurement depends on whether the instrument has been classified as "held to maturity", "held for trading", "available for sale" or "loans and receivables" as defined by Section 3855.

With the exception of recognizing derivative instruments, including hedge instruments, at fair value, the carrying value of the Company's financial instruments did not change. The methods by which the Company determines the fair value of its financial instruments also did not change as a result of adopting this standard.

Impact on Adoption

The adoption of the new standards resulted in the following adjustments on January 1, 2007:

Increase/(Decrease)		Assets		Liabilities and Equity
(millions of Canadian dollars)
Accounts receivable and other 1, 2		5.4		–
Deferred amounts and other assets 1, 2, 3, 4		55.3		–
Long-term investments 1		(57.3	)	–
Accounts payable and other 2		–		57.6
Long-term debt 3		–		(52.7	)
Other long-term liabilities 1, 2, 4		–		42.5
Future income taxes 1		–		(18.9	)
Non-controlling interests 1		–		(26.3	)
Accumulated other comprehensive income 1		–		48.2
Retained earnings 1		–		(47.0	)
		3.4		3.4

1. As a result of the new standards for cash flow hedges, the Company recognized unrealized net gains related to interest rate, foreign exchange and commodity hedges. The Company adjusted both deferred amounts and retained earnings for historical fair value adjustments related to certain cash flow hedges.
2. The Company recorded a regulatory liability due to the recognition of fixed price power contracts offset by unrealized financial instrument losses.
3. The Company reclassified unamortized deferred financing fees from deferred amounts and other assets to long-term debt as a result of adopting the new standards.
4. Relates to the recognition of gas purchase hedges for the regulated gas distribution businesses at January 1, 2007.

CAPITAL DISCLOSURES AND FINANCIAL INSTRUMENTS – DISCLOSURES AND PRESENTATION

Effective January 1, 2008, the Company adopted new accounting standards for Capital Disclosures (CICA Handbook Section 1535) and Financial Instruments – Disclosures and Presentation (CICA Handbook Sections 3862 and 3863). While the new standards did not change the Company's accounting policies, they resulted in additional disclosures.

Under Section 1535, the Company disclosed its objectives, policies and procedures for managing capital, summary quantitative data about what the Company manages as capital, whether the Company has complied with any externally imposed capital requirements and, if the Company has not complied with them, any consequences of non-compliance with these capital requirements.

Sections 3862 and 3863 replaced Section 3861 Financial Instruments – Disclosure and Presentation. Disclosure requirements are revised and enhanced, while presentation requirements remain essentially unchanged. The new disclosure requirements have expanded disclosure about the significance of financial instruments for the Company's financial position and performance, the nature and extent of risks arising from financial instruments to which the entity is exposed during the period and at the balance sheet date, and how the entity manages those risks.

INVENTORIES

The CICA issued Section 3031 Inventories effective January 1, 2008 which aligns accounting for inventories under Canadian GAAP with International Financial Reporting Standards (IFRS) and has replaced Section 3030. The adoption of the revised standard did not have a significant effect on the Company.

FUTURE ACCOUNTING POLICY CHANGES

Accounting for the Effects of Rate Regulation

In August 2007, the Canadian Accounting Standards Board (AcSB) published its decision with respect to rate regulated operations. The AcSB decided to retain much of the existing guidance related to rate-regulated operations; however, the exemption from the requirement to record future income taxes, as currently provided in CICA Handbook Section 3465 Income Taxes and the exemption from CICA Handbook Section 1100 Generally Accepted Accounting Principles will be removed, effective January 1, 2009. The Company will adopt these changes on January 1, 2009 and the principal effect will be the recognition of future income tax liabilities on the balance sheet, offset equally by regulatory assets (Note 4).

Goodwill and Intangible Assets

The CICA implemented revisions to standards dealing with goodwill and intangible assets effective for fiscal years beginning on or after October 1, 2008. Section 3064 Goodwill and Intangible Assets, which replaces Section 3062 Goodwill and Other Intangible Assets, gives guidance on the recognition of intangible assets as well as the recognition and measurement of internally developed intangible assets. This standard is not expected to materially impact the Company's financial statements.

Business Combinations

The CICA issued Section 1582 Business Combinations, which replaces Section 1581. This new standard aligns accounting for business combinations under Canadian GAAP with IFRS and is effective for business combinations entered into on or after January 1, 2011. The adoption of the revised standard is expected to impact the Company's financial statements only to the extent that business combinations are entered into after the effective date.

International Financial Reporting Standards

The AcSB confirmed in February 2008 that publicly accountable entities will be required to adopt IFRS for interim and annual financial statements for periods beginning on January 1, 2011. The Company has established a project plan for implementing IFRS which includes determining:

• Changes to accounting policies and implementation decisions;
• Disclosure requirements;
• Changes to information systems and accounting processes;
• Changes to internal controls over financial reporting and disclosure controls and procedures;
• Training requirements; and
• External stakeholder communications.

The impact of the adoption of IFRS on the Company's financial reporting is not yet determinable.

3. SEGMENTED INFORMATION

Year ended December 31, 2008		Liquids Pipelines		Gas Pipelines		Sponsored Investments		Gas Distribution and Services		International		Corporate	1	Consolidated
(millions of Canadian dollars)
Revenues		1,170.5		359.3		297.5		14,279.6		11.8		12.6		16,131.3
Commodity costs		–		–		–		(12,792.0	)	–		–		(12,792.0	)
Operating and administrative		(492.1	)	(117.2	)	(101.6	)	(554.4	)	(14.1	)	(32.8	)	(1,312.2	)
Depreciation and amortization		(180.8	)	(100.2	)	(78.1	)	(291.3	)	(0.8	)	(7.2	)	(658.4	)
		497.6		141.9		117.8		641.9		(3.1	)	(27.4	)	1,368.7
Income from equity investments		(0.2	)	–		148.4		4.7		25.0		(0.8	)	177.1
Other investment income and gain on sale of CLH		60.6		7.7		25.0		25.0		726.1		52.9		897.3
Interest and preferred share dividends		(111.4	)	(68.8	)	(59.9	)	(201.0	)	–		(116.6	)	(557.7	)
Non-controlling interest		(1.0	)	–		(46.5	)	(6.8	)	–		(1.4	)	(55.7	)
Income taxes		(117.6	)	(32.3	)	(73.1	)	(163.2	)	(139.8	)	17.1		(508.9	)
Earnings applicable to common shareholders		328.0		48.5		111.7		300.6		608.2		(76.2	)	1,320.8

Year ended December 31, 2007		Liquids Pipelines		Gas Pipelines		Sponsored Investments		Gas Distribution and Services		International		Corporate	1	Consolidated
(millions of Canadian dollars)
Revenues		1,090.9		321.3		270.3		10,217.9		9.8		9.2		11,919.4
Commodity costs		–		–		–		(9,009.5	)	–		–		(9,009.5	)
Operating and administrative		(426.5	)	(87.4	)	(79.2	)	(529.9	)	(14.2	)	(26.5	)	(1,163.7	)
Depreciation and amortization		(155.8	)	(83.5	)	(74.8	)	(276.3	)	(0.8	)	(5.7	)	(596.9	)
		508.6		150.4		116.3		402.2		(5.2	)	(23.0	)	1,149.3
Income from equity investments		(0.6	)	–		96.5		8.7		64.1		(0.9	)	167.8
Other investment income		15.5		23.4		38.8		25.7		39.1		52.6		195.1
Interest and preferred share dividends		(100.9	)	(64.2	)	(61.9	)	(207.1	)	–		(122.8	)	(556.9	)
Non-controlling interest		(1.3	)	–		(38.4	)	(5.7	)	–		(0.5	)	(45.9	)
Income taxes		(134.1	)	(39.9	)	(54.4	)	(44.4	)	(2.9	)	66.5		(209.2	)
Earnings applicable to common shareholders		287.2		69.7		96.9		179.4		95.1		(28.1	)	700.2

Year ended December 31, 2006		Liquids Pipelines		Gas Pipelines		Sponsored Investments		Gas Distribution and Services		International		Corporate	1	Consolidated
(millions of Canadian dollars)
Revenues		1,048.1		345.9		254.7		8,973.2		14.2		8.4		10,644.5
Commodity costs		–		–		–		(7,824.6	)	–		–		(7,824.6	)
Operating and administrative		(391.2	)	(96.0	)	(67.7	)	(483.6	)	(18.2	)	(27.5	)	(1,084.2	)
Depreciation and amortization		(153.4	)	(87.5	)	(71.9	)	(267.9	)	(0.9	)	(5.8	)	(587.4	)
		503.5		162.4		115.1		397.1		(4.9	)	(24.9	)	1,148.3
Income from equity investments		(0.2	)	–		111.5		16.8		52.2		–		180.3
Other investment income		3.2		9.2		2.9		12.9		45.2		34.4		107.8
Interest and preferred share dividends		(102.4	)	(73.3	)	(60.0	)	(193.8	)	–		(144.5	)	(574.0	)
Non-controlling interest		(1.6	)	–		(48.0	)	(4.4	)	–		(0.7	)	(54.7	)
Income taxes		(128.3	)	(37.1	)	(34.7	)	(54.9	)	(9.3	)	72.0		(192.3	)
Earnings applicable to common shareholders		274.2		61.2		86.8		173.7		83.2		(63.7	)	615.4

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

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.

TOTAL ASSETS

December 31,		2008		2007
(millions of Canadian dollars)
Liquids Pipelines		7,466.7		5,334.6
Gas Pipelines		2,736.1		2,043.9
Sponsored Investments		3,765.5		2,688.1
Gas Distribution and Services		7,631.3		7,287.3
International		357.4		908.6
Corporate		2,744.4		1,644.9
		24,701.4		19,907.4

ADDITIONS TO PROPERTY, PLANT AND EQUIPMENT

December 31,		2008		2007
(millions of Canadian dollars)
Liquids Pipelines		2,904.8		1,413.1
Gas Pipelines		136.4		200.4
Sponsored Investments		57.8		54.9
Gas Distribution and Services		478.2		479.8
International and Corporate		117.0		159.1
		3,694.2		2,307.3

GEOGRAPHIC INFORMATION

Revenues ¹

December 31,		2008		2007		2006
(millions of Canadian dollars)
Canada		12,447.8		8,337.0		7,968.7
United States		3,671.8		3,572.6		2,661.6
Other		11.7		9.8		14.2
		16,131.3		11,919.4		10,644.5

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

PROPERTY, PLANT AND EQUIPMENT

December 31,		2008		2007
(millions of Canadian dollars)
Canada		12,338.3		10,031.2
United States		4,049.8		2,564.4
Other		1.5		2.0
		16,389.6		12,597.6

4. FINANCIAL STATEMENT EFFECTS OF RATE REGULATION

GENERAL INFORMATION ON RATE REGULATION AND ITS ECONOMIC EFFECTS

A number of businesses within the Company are subject to regulation where the rates approved by the regulator are designed to recover the costs of providing the products and services referred to as the cost of service toll methodology. The Company's significant regulated businesses and related accounting impacts are described below.

Enbridge System

The primary business activities of the Enbridge System are subject to regulation by the NEB. Tolls are based on a cost of service methodology and are based on agreements with customers which are filed with the NEB for approval.

The incentive tolling settlement (ITS) is effective from January 1, 2005 to December 31, 2009 and defines the methodology for calculation of tolls and the revenue requirement on the core component of the Enbridge System in Canada. Toll adjustments, for variances from requirements defined in the ITS, are filed annually with the regulator for approval.

Athabasca Pipeline

Athabasca Pipeline is regulated by the ERCB. Tolls are established based on long-term transportation agreements with individual shippers and taxes are recorded using the taxes payable method.

Vector Pipeline

Vector Pipeline is an interstate natural gas pipeline with a FERC approved tariff establishing rates, terms and conditions governing its service to customers. Rates are determined using a cost of service methodology. Tariff changes may only be implemented upon approval by the FERC. Tolls include a return on equity component of 11.04% (2007 – 10.75%; 2006 – 10.75%) after tax.

Alliance Pipeline

The U.S. portion of the Alliance Pipeline (Alliance) is regulated by the FERC and the Canadian portion of the pipeline is regulated by the NEB. Shippers on Alliance entered into 15-year transportation contracts expiring in December 2015, with a cost of service toll methodology. Toll adjustments are filed annually with the regulator. The tolls include a return on equity component of 10.88% (2007 – 10.88%; 2006 – 10.85%) after tax for the U.S. portion and 11.26% (2007 – 11.26%; 2006 – 11.25%) after tax for the Canadian portion. Alliance tolls are based on a deemed 70% debt and 30% equity structure.

Enbridge Gas Distribution

EGD's gas distribution operations are regulated by the OEB. EGD's rates are based on a revenue per customer cap incentive regulation (IR) methodology which adjusts revenues, and consequently rates, annually and relies on an annual process to forecast volume and customer additions. Unlike the cost of service methodology used in prior years, the concepts of rate base and return on rate base are not relevant under IR.

EGD's rate of return on common equity embedded in rates was 8.39% (2007 – 8.39%; 2006 – 8.74%) after tax based on a 36% (2007 – 36%; 2006 – 35%) deemed common equity component of capital for regulatory purposes.

Enbridge Gas New Brunswick

Enbridge Gas New Brunswick (EGNB) is regulated by the EUB and follows a cost of service tolling methodology. An application for rate adjustments is filed annually for EUB approval. EGNB's rate of return on rate base was 9.71% (2007 – 9.70%; 2006 – 9.78%) after tax and the approved rate of return on equity was 13.00% (2007 – 13.00%; 2006 – 13.00%) after tax, based on equity which is capped at 50%.

FINANCIAL STATEMENT EFFECTS

Accounting for rate-regulated entities has resulted in recording the following regulatory assets and liabilities:

							Estimated Settlement Period		Earnings Impact 1
December 31,			2008		2007		(years)		2008		2007		2006
(millions of Canadian dollars)
Regulatory Assets/(Liabilities)
Liquids Pipelines
Enbridge System tolling deferrals 2			113.6		143.4		1		(29.8	)	(22.8	)	(6.1	)
Power purchase arrangements 3			(20.9	)	(23.8	)	1-3		2.9		(23.8	)	–
Gas Pipelines
Deferred transportation revenue 4			266.7		181.4		15-17		1.1		5.9		9.8
Transportation revenue adjustment 5			6.7		4.1		1		0.9		(2.6	)	(1.4	)
Sponsored Investments
Deferred transportation revenue 4			79.8		65.6		17		5.9		7.7		7.3
Gas Distribution and Services
EGNB regulatory deferral 6			132.7		117.7		32		10.1		10.3		12.4
Class action lawsuit settlement 7			20.1		22.0		4		(1.2	)	–		13.5
Ontario hearing cost 8			5.3		8.1		2		(1.8	)	(0.7	)	(1.7	)
Purchased gas variance 9			(75.2	)	(141.1	)	1		43.8		(8.8	)	(99.3	)
Unaccounted for gas variance 10			0.6		6.1		1		(3.6	)	11.4		(9.4	)
Transactional services deferral 11			(6.5	)	(8.8	)	1		–		–		–

1. The effect of a number of the Company's businesses being subject to rate regulation increased / (decreased) after tax reported earnings by the identified amounts.
2. Tolls on the Enbridge System are calculated in accordance with the ITS, System Expansion Program (SEP) II and the Terrace agreements and are established each year based on capacity, the allowed revenue requirement and the Terrace agreement. Where actual volumes shipped on the pipeline do not result in collection of the annual revenue requirement, a receivable is recognized and incorporated into tolls in the subsequent year. Recovery in the subsequent year, in whole or in part, is dependent upon realizing shipping volumes consistent with tolling model forecasts. Under/over collection are rolled into subsequent years. In addition, other tolling deferrals are recorded in accordance with the various agreements.
3. The power purchase arrangements liability represents the fair value of fixed price contracts and related financial instruments used to manage the mix of fixed and floating power costs (Note 21). Under rate regulation any fair value changes are passed to shippers through tolls. In the absence of rate regulation, these changes would impact earnings in the year incurred.
4. Deferred transportation revenue is related to the cumulative difference between GAAP depreciation expense of Alliance and Vector Pipelines and depreciation expense included in the regulated transportation rates. The Company expects to recover this difference over a number of years when depreciation rates in the transportation agreements are expected to exceed the GAAP depreciation rates, for Alliance US beginning in 2009 and Alliance Canada beginning in 2012 and ending in 2025 and for Vector beginning in 2008 and ending in 2023. This regulatory asset is not included in the rate base.
5. The transportation revenue adjustment is the cumulative difference between actual expenses of Alliance Pipeline US and estimated expenses included in transportation rates. The transportation revenue adjustment is recoverable under the long-term transportation agreements and is not included in the rate base.
6. A regulatory deferral account captures the difference between EGNB's distribution revenues and its cost of service revenue requirement during the development period. The regulatory deferral account balance will be amortized over a recovery period approved by the EUB, currently expected to end after 2040, commencing at the end of the development period which is expected to be 2010.
7. Class action lawsuit settlement deferral represents amounts paid towards the settlement of a class action lawsuit related to late payment penalties. Pursuant to an OEB decision in February 2008, these amounts will be recovered from customers over a five-year period commencing in 2008. In the absence of rate regulation these costs would be expensed as incurred.
8. Ontario hearing costs are incurred by EGD for the rate hearing process. EGD has historically been granted OEB approval for recovery of such hearing costs, generally within two years. In the absence of rate regulation these costs would be expensed as incurred.
9. Purchased gas variance is the difference between the actual cost and the approved cost of gas reflected in rates. EGD has historically been granted approval for recovery or required refund of this variance within the year. In the absence of rate regulation the actual cost of gas sold would be recognized in earnings in the year sold.
10. Unaccounted for gas variance represents the difference between the total gas distributed by EGD and the amount of gas billed or billable to ratepayers, to the extent it is different from the approved gas variance. EGD has deferred unaccounted for gas variance and has historically been granted approval for recovery or required refund of this amount in the subsequent year. In the absence of rate regulation this variance would be included in cost of sales.
11. Transactional services deferral represents the ratepayer portion of excess earnings generated from optimization of storage and pipeline capacity. EGD has historically been required to refund the amount to ratepayers in the following year. There would be no change in the treatment of this item in the absence of rate regulation.

OTHER ITEMS AFFECTED BY RATE REGULATION

Future Income Taxes

In the absence of rate regulation, future income tax liabilities of $532.9 million (2007 – $517.1 million) associated with certain assets, primarily property, plant and equipment, would be recorded.

The Company has recorded net future income tax liabilities of $67.7 million (2007 – $24.0 million) related to certain regulatory asset/liability deferral accounts identified above. Accumulated future income tax liabilities of $54.5 million (2007 – $55.6 million) related to the remaining regulatory deferral accounts have not been recognized at December 31, 2008. In the absence of rate regulation, regulatory deferrals would not be recorded nor would the associated future income tax liabilities. As a result of these tax impacts, earnings during the year would decrease by $15.0 million (2007 – increase by $62.2 million).

Allowance For Funds Used During Construction and Other Capitalized Costs

With the pool method prescribed by regulators, it is not possible to identify the carrying value of the equity component of AFUDC or its effect on depreciation. Similarly, gains or losses on the retirement of specific fixed assets in any given year cannot be identified or quantified.

Operating Cost Capitalization

EGD entered into a consulting contract relating to asset management initiatives. The majority of the costs are being capitalized to gas mains in accordance with regulatory approval. At December 31, 2008, $93.7 million (2007 – $82.2 million) was included in gas mains, which are depreciated over the average service life of 25 years. In the absence of rate regulation, the majority of these costs would be charged to current earnings.

Pension Plans

Had pension costs and obligations been recognized at EGD, the net pension asset would have increased by $156.1 million at December 31, 2008 (2007 – $153.3 million) and earnings would have increased by $3.1 million (2007 – decreased by $1.1 million).

Post-Employment Benefits Other than Pensions

In the absence of rate regulation, the cost of such benefits is accrued during the years employees render service. Had these costs been accrued at EGD, the net OPEB liability would have increased by $75.5 million (2007 – $70.8 million) and earnings would have decreased by $5.5 million (2007 – $5.8 million).

5. DISPOSITION and ACQUISITION

DISPOSITION

On June 17, 2008, the Company sold its 25% investment in CLH for total proceeds of $1.38 billion (876 million euros), including a dividend receivable of $17.3 million (10.9 million euros), net of transaction costs. The sale of CLH resulted in a gain of $694.6 million. Earnings generated by the CLH investment were $24.7 million (2007 – $65.6 million; 2006 – $54.5 million) for the year ended December 31, 2008, and are included in the International operating segment. Operating cash flows generated by the CLH investment were $11.5 million for the year ended December 31, 2008 (2007 – $58.4 million; 2006 – $56.2 million).

ACQUISITION

On February 1, 2006, Enbridge acquired a 65% common share interest in the Olympic Pipe Line Company for $112.7 million in cash.

(millions of Canadian dollars)
Fair Value of Assets Acquired:
Property, plant and equipment			107.0
Other assets			5.0
Future income taxes			(6.1	)
Other liabilities			(17.0	)
			88.9
Goodwill			23.8
			112.7
Purchase Price:
Cash, net of $1.6 million cash acquired			112.7
Deposit paid in 2005			(11.3	)
			101.4

6. ACCOUNTS RECEIVABLE AND OTHER

December 31,		2008		2007
(millions of Canadian dollars)
Trade receivables		1,088.4		1,332.4
Unbilled revenues		569.8		453.0
Regulatory assets		144.6		183.7
Taxes receivable		133.3		17.6
GST receivable		74.6		78.7
Short-term portion of derivative assets		65.3		79.5
Prepaid expenses and deposits		28.4		20.2
Transfer fees		22.3		28.9
Due from affiliates		18.3		75.0
Dividends receivable		13.3		12.2
Other		164.2		107.5
		2,322.5		2,388.7

7. INVENTORY

December 31,		2008		2007
(millions of Canadian dollars)
Gas		674.3		599.2
Other commodities		170.4		110.2
		844.7		709.4

8. PROPERTY, PLANT AND EQUIPMENT

December 31, 2008		Weighted Average Depreciation Rate		Cost		Accumulated Depreciation		Net
(millions of Canadian dollars)
Liquids Pipelines
Pipeline		2.4%		3,161.9		1,359.6		1,802.3
Pumping equipment, buildings, tanks and other		3.7%		3,025.7		1,027.8		1,997.9
Land and right-of-way		2.5%		69.9		19.7		50.2
Under construction		–		3,856.9		–		3,856.9
				10,114.4		2,407.1		7,707.3
Gas Pipelines
Pipeline		3.6%		2,169.0		588.7		1,580.3
Land and right-of-way		2.8%		48.6		11.3		37.3
Metering and other		5.5%		168.7		28.9		139.8
Under construction		–		333.5		–		333.5
				2,719.8		628.9		2,090.9
Sponsored Investments
Pipeline		4.4%		1,362.9		276.7		1,086.2
Other		8.7%		129.0		16.1		112.9
				1,491.9		292.8		1,199.1
Gas Distribution and Services
Gas mains		3.7%		2,943.7		804.1		2,139.6
Gas services		4.1%		2,290.5		739.4		1,551.1
Regulating and metering equipment		3.7%		619.1		177.3		441.8
Storage		2.7%		246.5		67.3		179.2
Computer technology		19.1%		158.3		62.5		95.8
Other		4.5%		541.6		124.8		416.8
Under construction		–		26.7		–		26.7
				6,826.4		1,975.4		4,851.0
International and Corporate
Wind turbines and other		4.9%		552.0		34.0		518.0
Land and right-of-way		4.0%		1.8		–		1.8
Under construction		–		21.5		–		21.5
				575.3		34.0		541.3
				21,727.8		5,338.2		16,389.6

December 31, 2007		Weighted Average Depreciation Rate		Cost		Accumulated Depreciation		Net
(millions of Canadian dollars)
Liquids Pipelines
Pipeline		2.2%		2,688.4		1,259.9		1,428.5
Pumping equipment, buildings, tanks and other		3.7%		2,566.6		912.1		1,654.5
Land and right-of-way		1.8%		41.5		18.5		23.0
Under construction		–		1,546.4		–		1,546.4
				6,842.9		2,190.5		4,652.4
Gas Pipelines
Pipeline		3.7%		1,656.5		390.4		1,266.1
Land and right-of-way		2.7%		38.8		7.6		31.2
Metering and other		4.6%		101.6		16.0		85.6
Under construction		–		272.6		–		272.6
				2,069.5		414.0		1,655.5
Sponsored Investments
Pipeline		4.2%		1,402.8		284.1		1,118.7
Other		7.6%		108.7		13.9		94.8
				1,511.5		298.0		1,213.5
Gas Distribution and Services
Gas mains		3.3%		2,748.9		708.7		2,040.2
Gas services		3.6%		2,224.0		676.4		1,547.6
Regulating and metering equipment		3.7%		581.9		158.0		423.9
Storage		2.7%		246.4		61.0		185.4
Computer technology		19.4%		185.2		81.6		103.6
Other		4.6%		310.6		106.5		204.1
Under construction		–		143.1		–		143.1
				6,440.1		1,792.2		4,647.9
International and Corporate
Other		8.1%		113.0		37.3		75.7
Under construction		–		352.6		–		352.6
				465.6		37.3		428.3
				17,329.6		4,732.0		12,597.6