Notes to Consolidated Statements

Overview

Enbridge Inc. (Enbridge or the Company) is a publicly traded energy transportation and distribution company. 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 Canadian common carrier pipeline and feeder pipelines that transport crude oil and other liquid hydrocarbons including the Enbridge System, the Athabasca System, Spearhead 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) 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, Compañía Logística de Hidrocarburos CLH, S.A. (CLH) in Spain and Oleoducto Central S.A. (OCENSA) in Colombia.

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 27. 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. 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 financial assets (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), 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. 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.

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 into the rate base. 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 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 pension costs and obligations for defined benefit pension plans to be determined using the projected benefit method and charged to earnings as services are rendered.

The cost of providing post-employment benefits other than pensions (OPEB) for the regulated operations of Gas Distribution and Services is expensed when paid, consistent with the recovery of such costs in rates.

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. Certain operations are subject to regulation and, accordingly, there are circumstances where revenues recognized do not match the cash tolls or the billed amounts, resulting in the recognition of regulatory assets and liabilities.

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, except for derivatives that are designated as, and determined to be, effective hedging instruments, whose fair value is recorded in Other Comprehensive Income (OCI).

Financial assets that are "available for sale" are measured at fair value with changes in those fair values recorded in OCI. 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.

Other investments in entities which are not subsidiaries or joint ventures, and where the Company does not exercise significant influence, are classified as held to maturity, loans and receivables or available for sale. "Available for sale" investments are measured at fair value with changes in those fair values recorded in OCI. Where actively quoted prices are not available, these investments are carried at amortized cost. "Held to maturity" investments and "loans and receivables" are measured at amortized cost.

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. 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 and euro 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

The Company does not use derivative instruments for speculative purposes. However, 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. The Company also holds a self-sustaining euro equity investment in CLH. 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.

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 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.

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 and written down to fair value if impairment occurs.

ASSET RETIREMENT OBLIGATIONS

The fair value of asset retirement obligations (AROs) associated with the retirement of long-lived assets are recognized as 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, a liability and expense are recorded based on the number of units outstanding and the current market price of the Company's shares. The value of the PSU's is also dependent on the Company's current performance relative to performance targets set out under the plan.

COMPARATIVE AMOUNTS

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.

The adoption of the new standards did not impact the Company's earnings or cash flows.

Comprehensive Income and Equity

The new standards introduce comprehensive income, which consists of earnings and OCI. The Company's consolidated financial statements now include a Statement of Comprehensive Income. The Company's OCI is primarily comprised of the effective portion of changes in unrealized gains and losses related to cash flow hedges; the Company's share of the OCI of equity investees; and unrealized foreign exchange gains and losses related to self-sustaining foreign investments and the net investment hedges of those foreign investments.

The Company now presents a Consolidated Statement of Shareholders' Equity, which includes the change for each component of shareholders' equity. 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 17.

Financial Instruments

CICA Handbook Section 3855 establishes recognition and measurement criteria for financial instruments. The new standard 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 has not changed. The methods by which the Company determines the fair value of its financial instruments have also not changed 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:

(millions of dollars) Increase/(Decrease)	Assets	Liabilities and Equity
Accounts Receivable and Other1,2	5.4	-
Deferred Amounts and Other Assets1,2,3,4	55.3	-
Long-Term Investments1	(57.3)	-
Accounts Payable and Other2	-	57.6
Long-Term Debt3	-	(52.7)
Other Long-Term Liabilities1,2,4	-	42.5
Future Income Taxes1	-	(18.9)
Non-Controlling Interests1	-	(26.3)
Accumulated Other Comprehensive Income1	-	48.2
Retained Earnings1	-	(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.

FUTURE ACCOUNTING POLICY CHANGES

Capital Disclosures and Financial Instruments – Disclosures and Presentation

Effective January 1, 2008, the Company will adopt new accounting standards for Capital Disclosures (CICA Handbook Section 1535) and Financial Instruments – Disclosures and Presentation (CICA Handbook Sections 3862 and 3863).

Under Section 1535, the Company will disclose its objectives, policies and procedures for managing capital, any 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.

The new Sections 3862 and 3863 replace Section 3861 Financial Instruments – Disclosure and Presentation. Disclosure requirements are revised and enhanced, while presentation requirements remain essentially unchanged. The new disclosure requirements will expand 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). This standard is not expected to materially impact the Company's financial statements.

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.

3. 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. 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 set based on agreements with customers and 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 10.75% (2006 – 10.75%) after tax.

Alliance Pipeline

The US 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% (2006 – 10.85%) after tax for the US portion and 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 set under a cost of service methodology with revenues charged to recover EGD's forecast costs and to earn a rate of return on common equity. Applications for changes to rates are made annually and are submitted for approval by the OEB.

Forecast costs include gas commodity and transportation, operation and maintenance, depreciation, municipal taxes, interest and income taxes. The rate base is the average investment in permitted assets used in gas distribution, storage and transmission and an allowance for working capital. EGD's 2007 approved rate of return on rate base was 7.58% (2006 – 7.74%) after tax, and the approved rate of return on common equity was 8.39% (2006 – 8.74%) after tax based on a 36% (2006 – 35%) deemed common equity.

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 9.70% (2006 – 9.78%) after tax and the approved rate of return on equity was 13.00% (2006 – 13.00%) after tax, based on equity which is capped at 50%.

REGULATORY RISK AND UNCERTAINTIES AFFECTING RECOVERY OR SETTLEMENT

The recognition of regulatory assets and liabilities is based on the actions, or an expectation of the future actions, of the regulator. To the extent that the regulator's actions differ from the Company's expectations, the timing and amount of recovery or settlement of regulatory balances could differ significantly from those recorded.

FINANCIAL STATEMENT EFFECTS

To recognize the actions or expected actions of the regulator, the timing and recognition of certain revenues and expenses may differ from that otherwise expected for non rate-regulated entities.

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

				Earnings Impact1
(millions of dollars) December 31,	2007	2006	Estimated Settlement Period (years)	2007	2006
Regulatory Assets/(Liabilities)
Liquids Pipelines
Enbridge System tolling deferrals2	143.4	166.2	1	(22.8)	(6.1)
Power purchase arrangements3	(23.8)	-	1–3	(23.8)	-
Gas Pipelines
Deferred transportation revenue4	181.4	203.8	16–18	5.9	9.8
Transportation revenue adjustment5	4.1	9.3	1	(2.6)	(1.4)
Sponsored Investments
Deferred transportation revenue4	65.6	47.4	18	7.7	7.3
Gas Distribution and Services
EGNB regulatory deferral6	117.7	101.8	33	10.3	12.4
Class action lawsuit settlement7	22.0	22.0	2	-	13.5
Ontario hearing cost8	8.1	9.2	2	(0.7)	(1.7)
Purchased gas variance9	(141.1)	(127.4)	1	(8.8)	(99.3)
Unaccounted for gas variance10	6.1	(11.7)	1	11.4	(9.4)
Transactional services deferral11	(8.8)	(7.5)	1	-	-

1. Represents the effect of rate regulation on after tax reported earnings.
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. However, recovery is dependent on volumes shipped since each shipper is only responsible for their pro-rata share of the increase in tolls. In addition, other tolling deferrals occur in accordance with the various agreements.
3. The power purchase arrangements liability is the fair value of fixed price contracts and related financial instruments used to manage the mix of fixed and floating power costs (see Note 18).
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 beginning in 2011 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 commencing at the end of the development period, which is currently expected to end after 2040.
7. Class action lawsuit settlement deferral represents amounts paid towards the settlement of a class action lawsuit related to late payment penalties. This amount is expected to be recovered in future periods.
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.
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.
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.
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.

OTHER ITEMS AFFECTED BY RATE REGULATION

Future Income Taxes

In the absence of rate regulation, future income tax liabilities of $517.1 million (2006 – $584.0 million) associated with certain assets, primarily property, plant and equipment, would be recorded.

The Company has recorded net future income tax liabilities of $24.0 million (2006 – $32.9 million) related to certain regulatory asset/liability deferral accounts identified above. Accumulated future income tax assets of $55.6 million (2006 – $64.7 million) related to the remaining regulatory deferral accounts have not been recognized at December 31, 2007. 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 increase by $62.2 million (2006 – $65.0 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, 2007, $82.2 million (2006 – $66.4 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, the net pension asset would have increased by $153.3 million at December 31, 2007 (2006 – $157.1 million) and earnings would have decreased by $1.1 million (2006 – $0.5 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, the net OPEB liability would have increased by $70.8 million (2006 – $67.1 million) and earnings would have decreased by $5.8 million (2006 – $5.5 million).

4. SEGMENTED INFORMATION

(millions of dollars) Year ended December 31, 2007	Liquids Pipelines	Gas Pipelines	Sponsored Investments	Gas Distribution and Services	International	Corporate1	Consolidated
Revenues	1,090.9	321.3	270.3	10,227.1	9.8	-	11,919.4
Commodity costs	-	-	-	(9,009.5)	-	-	(9,009.5)
Operating and administrative	(426.5)	(87.4)	(79.2)	(535.9)	(14.2)	(20.5)	(1,163.7)
Depreciation and amortization	(155.8)	(83.5)	(74.8)	(277.0)	(0.8)	(5.0)	(596.9)
	508.6	150.4	116.3	404.7	(5.2)	(25.5)	1,149.3
Income from equity investments	(0.6)	-	96.5	8.8	64.1	(1.0)	167.8
Other investment income	15.5	23.4	38.8	28.0	39.1	50.3	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)	(6.2)	-	-	(45.9)
Income taxes	(134.1)	(39.9)	(54.4)	(44.1)	(2.9)	66.2	(209.2)
Earnings applicable to common shareholders	287.2	69.7	96.9	184.1	95.1	(32.8)	700.2

(millions of dollars) Year ended December 31, 2006	Liquids Pipelines	Gas Pipelines	Sponsored Investments	Gas Distribution and Services	International	Corporate1	Consolidated
Revenues	1,048.1	345.9	254.7	8,981.6	14.2	-	10,644.5
Commodity costs	-	-	-	(7,824.6)	-	-	(7,824.6)
Operating and administrative	(391.2)	(96.0)	(67.7)	(485.8)	(18.2)	(25.3)	(1,084.2)
Depreciation and amortization	(153.4)	(87.5)	(71.9)	(269.1)	(0.9)	(4.6)	(587.4)
	503.5	162.4	115.1	402.1	(4.9)	(29.9)	1,148.3
Income from equity investments	(0.2)	-	111.5	17.0	52.2	(0.2)	180.3
Other investment income	3.2	9.2	2.9	17.8	45.2	29.5	107.8
Interest and preferred share dividends	(102.4)	(73.3)	(60.0)	(197.8)	-	(140.5)	(574.0)
Non-controlling interest	(1.6)	-	(48.0)	(5.1)	-	-	(54.7)
Income taxes	(128.3)	(37.1)	(34.7)	(55.8)	(9.3)	72.9	(192.3)
Earnings applicable to common shareholders	274.2	61.2	86.8	178.2	83.2	(68.2)	615.4

(millions of dollars) Year ended December 31, 2005	Liquids Pipelines	Gas Pipelines	Sponsored Investments	Gas Distribution and Services	International	Corporate1	Consolidated
Revenues	881.0	364.3	249.0	6,947.1	11.7	-	8,453.1
Commodity costs	-	-	-	(5,728.4)	-	-	(5,728.4)
Operating and administrative	(311.4)	(95.5)	(60.1)	(549.3)	(17.5)	(23.8)	(1,057.6)
Depreciation and amortization	(145.6)	(94.3)	(71.5)	(257.3)	(1.2)	(5.4)	(575.3)
	424.0	174.5	117.4	412.1	(7.0)	(29.2)	1,091.8
Income from equity investments	0.8	-	48.6	8.9	58.5	-	116.8
Other investment income	0.4	5.9	27.3	30.6	39.7	38.5	142.4
Interest and preferred share dividends	(96.5)	(81.9)	(61.8)	(178.8)	-	(127.1)	(546.1)
Non-controlling interest	(2.1)	-	(21.2)	(3.8)	(0.5)	-	(27.6)
Income taxes	(97.5)	(38.7)	(45.5)	(90.2)	(3.3)	53.9	(221.3)
Earnings applicable to common shareholders	229.1	59.8	64.8	178.8	87.4	(63.9)	556.0

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

(millions of dollars) December 31,	2007	2006
Liquids Pipelines	5,334.6	4,004.4
Gas Pipelines	2,043.9	2,297.0
Sponsored Investments	2,688.1	2,841.5
Gas Distribution and Services	8,355.7	7,635.4
International	908.6	917.2
Corporate	576.5	683.8
	19,907.4	18,379.3

ADDITIONS TO PROPERTY, PLANT AND EQUIPMENT

(millions of dollars) December 31,	2007	2006	2005
Liquids Pipelines	1,413.1	428.8	258.6
Gas Pipelines	200.4	110.8	10.1
Sponsored Investments	54.9	33.4	15.5
Gas Distribution and Services	609.4	611.1	434.0
International and Corporate	29.5	23.4	5.9
	2,307.3	1,207.5	724.1

GEOGRAPHIC INFORMATION

Revenues¹

(millions of dollars) December 31,	2007	2006	2005
Canada	8,337.0	7,968.7	6,747.5
United States	3,572.6	2,661.6	1,693.9
Other	9.8	14.2	11.7
	11,919.4	10,644.5	8,453.1

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

Property, Plant and Equipment

(millions of dollars) December 31,	2007	2006
Canada	10,031.2	8,859.7
United States	2,564.4	2,401.8
Other	2.0	3.2
	12,597.6	11,264.7

5. ACQUISITIONS

On February 1, 2006, Enbridge acquired a 65% common share interest in the Olympic Pipeline Company for $112.7 million in cash. In 2005, the Company acquired interests in five other businesses for a total of $106.6 million, including $6.8 million paid in common shares of the Company.

(millions of dollars) Year ended December 31,	Olympic 2006	Combined 2005
Fair Value of Assets Acquired:
Property, plant and equipment	107.0	66.6
Intangible assets	-	25.7
Other assets	5.0	0.7
Future income taxes	(6.1)	(16.3)
Other liabilities	(17.0)	(0.9)
	88.9	75.8
Goodwill	23.8	30.8
	112.7	106.6
Purchase Price:
Cash (2006, net of $1.6 million cash acquired)	112.7	88.6
Contingent consideration	-	11.2
Shares issued	-	6.8
Deposit paid in 2005	(11.3)	-
	101.4	106.6

6. PROPERTY, PLANT AND EQUIPMENT

(millions of dollars) December 31, 2007	Weighted Average Depreciation Rate	Cost	Accumulated Depreciation	Net
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	-	495.7	-	495.7
		6,792.7	1,792.2	5,000.5
International and Corporate – Other	8.1%	113.0	37.3	75.7
		17,329.6	4,732.0	12,597.6

(millions of dollars) December 31, 2006	Weighted Average Depreciation Rate	Cost	Accumulated Depreciation	Net
Liquids Pipelines
Pipeline	2.3%	2,781.6	1,241.3	1,540.3
Pumping Equipment, Buildings, Tanks and Other	3.7%	2,501.3	874.1	1,627.2
Land and Right-of-Way	1.7%	40.1	18.4	21.7
Under Construction	-	304.8	-	304.8
		5,627.8	2,133.8	3,494.0
Gas Pipelines
Pipeline	3.7%	1,999.7	397.0	1,602.7
Land and Right-of-Way	2.7%	46.3	8.0	38.3
Metering and Other	4.5%	128.0	20.1	107.9
Under Construction	-	64.2	-	64.2
		2,238.2	425.1	1,813.1
Sponsored Investments
Pipeline	4.4%	1,372.8	219.2	1,153.6
Other	5.2%	83.8	9.6	74.2
		1,456.6	228.8	1,227.8
Gas Distribution and Services
Gas Mains	4.2%	2,342.2	531.3	1,810.9
Gas Services	4.5%	1,933.6	523.6	1,410.0
Regulating and Metering Equipment	3.9%	624.5	153.9	470.6
Storage	2.7%	270.3	60.2	210.1
Computer Technology	18.1%	346.6	195.3	151.3
Other	2.6%	426.5	112.1	314.4
Under Construction	-	308.7	-	308.7
		6,252.4	1,576.4	4,676.0
International and Corporate – Other	7.0%	86.3	32.5	53.8
		15,661.3	4,396.6	11,264.7

7. JOINT VENTURES

Enbridge has joint venture interests in the following entities:

December 31,		Net Assets
(millions of dollars)	Ownership Interest	2007	2006
Liquids Pipelines
Olympic Pipeline	65%	97.8	111.1
Other	30% – 50%	54.8	58.5
Gas Pipelines
Alliance Pipeline US	50%	364.3	422.7
Vector Pipeline	60%	408.4	442.3
Enbridge Offshore Pipelines – various joint ventures	22% – 75%	441.3	517.4
Sponsored Investments
Alliance Pipeline Canada	50%	354.8	357.7
Other	33% – 50%	69.2	56.4
Gas Distribution and Services
Aux Sable	42.7%	150.6	178.7
Other	42.7% – 70%	49.7	55.3
		1,990.9	2,200.1

The following summarizes the impact of proportionately consolidating the joint ventures on the consolidated financial statements of Enbridge:

(millions of dollars) Year ended December 31,	2007	2006	2005
Earnings
Revenues	844.5	939.4	1,402.5
Commodity costs	(132.9)	(184.8)	(608.2)
Operating and administrative	(207.6)	(257.2)	(320.7)
Depreciation and amortization	(152.9)	(164.8)	(162.3)
Interest expense	(106.4)	(110.8)	(117.1)
Other investment income	6.6	7.3	4.6
Proportionate share of earnings	251.3	229.1	198.8
Cash Flows
Cash provided by operations	312.0	318.3	271.1
Cash used in investing activities	(131.9)	(59.5)	(13.4)
Cash used in financing activities	(183.9)	(258.9)	(268.0)
Proportionate share of decrease in cash and cash equivalents	(3.8)	(0.1)	(10.3)

(millions of dollars) Year ended December 31,	2007	2006
Financial Position
Current assets	146.0	178.7
Property, plant and equipment, net	2,913.1	3,224.6
Deferred amounts and other assets	277.6	288.5
Current liabilities	(139.8)	(151.8)
Long-term debt	(1,181.6)	(1,315.4)
Other long-term liabilities	(24.4)	(24.5)
Proportionate share of net assets	1,990.9	2,200.1

8. LONG TERM INVESTMENTS

(millions of dollars) Year ended December 31,	2007	2006
Equity Investments
Liquids Pipelines
Chicap Pipeline	22.8%	17.2	21.5
Sponsored Investments
The Partnership	15.1%	944.8	1,105.5
Gas Distribution and Services
Noverco Common Shares	32.1%	11.6	37.0
Other		1.5	1.4
International
Compañía Logística de Hidrocarburos CLH, S.A.	25.0%	626.4	662.2
Corporate		16.1	17.1
Other Investments
Gas Distribution and Services
Noverco Preferred Shares		181.4	181.4
Fuel Cell Energy		25.0	25.0
International
Oleoducto Central S.A.		223.3	223.3
Corporate
Value Creation		29.0	25.0
		2,076.3	2,299.4

Equity investments include the unamortized excess of the purchase price over the underlying net book value of the investee's assets at the purchase date of $581.1 million at December 31, 2007 (2006 – $617.5 million). 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. Consolidated retained earnings at December 31, 2007 includes undistributed earnings from equity investments of $5.0 million (2006 – $10.4 million).

THE PARTNERSHIP

The Company has a combined 15.1% ownership in EEP, through a 2.0% general partner interest, a 4.2% interest in Class B units, a 6.4% interest in Class C units and a 2.5% interest in EEP via a 17.2% investment in EEM, which owns 14.6% of EEP via its 100% interest in EEP's i-units. The Company recorded investment income from EEP of $130.4 million (2006 – $111.5 million) including dilution gains.

Although 82.8% of EEM is widely held, the Company has voting control and; therefore, consolidates EEM, including its investment in EEP of $456.4 million (2006 – $545.0 million). Net of non-controlling interest in EEM, the book value of the Company's investment in EEP is $566.7 million (2006 – $654.3 million.)

In the second quarter of 2007, EEP issued Class A and Class C partnership units. As Enbridge did not fully participate in these offerings, dilution gains net of tax and non-controlling interest of $11.8 million resulted and Enbridge's ownership interest in the Partnership decreased from 16.6% to 15.1%.

In 2006, the Company acquired 5.4 million Class C units of EEP for $280.2 million. The Class C units have the same voting rights as Class A and B units and are entitled to quarterly distributions equal to those paid to Class A and B unitholders. Prior to August 15, 2009, distributions are paid in additional Class C units, where Class C units are valued at the market value of Class A units. After August 15, 2009, distributions will be paid in cash and, subject to the approval of existing Class A and Class B unitholders, Class C units will convert into Class A units on a one-to-one basis. If approval of the conversion is not received, the Class C units will receive cash distributions equal to 115% of those paid to Class A unitholders.

NOVERCO

The Company owns a preferred share investment in Noverco of $181.4 million (2006 – $181.4 million), which is entitled to a cumulative preferred dividend based on the average yield of Government of Canada bonds maturing in greater than 10 years plus 4.34%. The fair value of the investment approximates its carrying value as its return is based on a floating rate.

The Company also owns an equity investment in the common shares of Noverco of $11.6 million (2006 – $37.0 million). Noverco owns an approximate 9.5% (2006 – 9.5%) reciprocal shareholding in the shares of the Company. As a result, the Company has an indirect pro-rata interest of 3.1% (2006 – 3.2%) in its own shares. Both the equity investment in Noverco and shareholders' equity have been reduced by the reciprocal shareholding of $154.3 million (2006 – $135.7 million). Noverco records dividends paid by the Company as dividend income and the Company eliminates these dividends from the earnings of Noverco. The Company records its pro-rata share of dividends paid by the Company to Noverco as a reduction of dividends paid and an increase in the Company's investment in Noverco. In 2007, the Company recorded equity investment earnings of $8.5 million (2006 – $16.8 million) related to its interest in Noverco.

In 2005, the Company reclassified $51.2 million in dividends paid to Noverco representing the reciprocal portion of dividends paid to Noverco from September 1, 1997 to December 31, 2004. The reclassification increased equity investments and retained earnings by $51.2 million.

CLH

The Company owns a 25% equity interest in CLH of $626.4 million (2006 – $662.2 million), a refined products transportation and storage company in Spain. In 2007, the Company recorded equity investment income from CLH of $64.1 million (2006 – $52.3 million).

OCENSA

The Company owns an investment in OCENSA, a crude oil export pipeline in Colombia of $223.3 million (US$160.2 million) (2006 – $223.3 million; US$160.2 million), which earns a fixed rate of return. The fair value of this investment is approximately $198.0 million (US$200.4 million) (2006 – $245.9 million; US$211.0 million), estimated using year-end market information.

9. DEFERRED AMOUNTS AND OTHER ASSETS

(millions of dollars) Year ended December 31,	2007	2006
Regulatory deferrals	428.2	395.9
Contractual receivables	152.0	142.8
Long-term portion of derivative financial instruments	329.0	205.1
Pension asset	72.3	56.0
Deferred financing charges (Note 2)	-	52.7
Affiliate long-term note receivable (US$130.0 million) (Note 23)	128.5	-
Other	72.0	72.0
	1,182.0	924.5

At December 31, 2007, deferred amounts of $42.3 million (2006 – $146.8 million) were subject to amortization and are presented net of accumulated amortization of $23.2 million (2006 – $67.6 million). Amortization expense in 2007 was $3.6 million (2006 – $10.1 million; 2005 – $12.5 million).

10. INTANGIBLE ASSETS

(millions of dollars) December 31, 2007	Weighted Average Amortization Rate	Cost	Accumulated Amortization	Net
Transportation agreements	4.2%	241.8	36.3	205.5
Customer lists	7.1%	8.3	1.8	6.5
		250.1	38.1	212.0

(millions of dollars) December 31, 2007	Weighted Average Amortization Rate	Cost	Accumulated Amortization	Net
Transportation agreements	4.2%	261.5	28.4	233.1
Customer lists	7.1%	9.8	1.4	8.4
		271.3	29.8	241.5

Amortization expense of $10.4 million was recorded for the year ended December 31, 2007 (2006 – $11.0 million; 2005 – $11.1 million).

11. GOODWILL

(millions of dollars)	Liquids Pipelines	Gas Pipelines	Sponsored Investments	Gas Distribution and Services	Consolidated
Balance at January 1, 2006	-	29.9	308.1	29.2	367.2
Olympic Pipeline acquisition	23.8	-	-	-	23.8
Foreign exchange and other	0.7	-	-	3.2	3.9
Balance at December 31, 2006	24.5	29.9	308.1	32.4	394.9
Foreign exchange and other	(6.2)	(4.6)	-	3.9	(6.9)
Balance at December 31, 2007	18.3	25.3	308.1	36.3	388.0

12. DEBT

(millions of dollars) December 31,	Weighted Average Interest Rate	Maturity	2007	2006
Liquids Pipelines
Debentures	8.20%	2024	200.0	200.0
Medium-term notes	5.62%	2009 – 2036	824.6	824.6
Other (US$365.0 million; 2006 – nil)1			516.5	131.0
Gas Distribution and Services
Debentures	11.06%	2009 – 2024	485.0	585.0
Medium-term notes	5.69%	2008 – 2036	1,865.0	1,665.0
Other			9.4	8.2
Corporate
U.S.dollar term notes
(US$1,354.3 million; 2006 – US$417.0 million)	5.69%	2014 – 2022	1,341.2	485.9
Medium-term notes	5.72%	2008 – 2035	1,900.0	2,094.9
Preferred securities			-	200.0
Other (US$317.0 million; 2006 – US$348.4 million)2			1,252.2	1,396.4
Deferred debt issue costs (Note 2)			(59.7)	-
Total Debt			8,334.2	7,591.0
Current Maturities			(605.2)	(537.0)
Long-Term Debt			7,729.0	7,054.0

1. Primarily credit facility draws.
2. Primarily commercial paper borrowings.

Short-term debt of $1,764.8 million (2006 – $1,519.1 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, 2008 through 2012 are $605.2 million, $455.0 million, $600.9 million, $151.1 million and $251.1 million, respectively. The Company's debentures and medium-term notes bear interest at fixed rates.

On February 15, 2007, the Company redeemed $200.0 million of 7.8% Preferred Securities for $25.00 per security plus accrued and unpaid interest.

FAIR VALUE OF DEBT

	2007		2006
(millions of dollars) December 31,	Carrying Amount	Fair Value	Carrying Amount	Fair Value
Liquids Pipelines	1,541.1	1,642.5	1,155.6	1,301.6
Gas Distribution and Services	2,359.4	2,571.0	2,258.2	2,613.8
Corporate	4,493.4	4,640.7	4,177.2	4,294.0

The fair value of debt does not include the effects of hedging.

INTEREST EXPENSE

(millions of dollars) Year ended December 31,	2007	2006	2005
Long-term debt	439.5	403.4	382.8
Non-recourse long-term debt	102.0	104.9	112.1
Commercial paper and other short-term debt	54.5	60.3	40.6
Short-term borrowings	15.2	19.1	12.7
Capitalized	(61.2)	(20.6)	(9.0)
	550.0	567.1	539.2

In 2007, total interest paid was $607.3 million (2006 – $563.3 million; 2005 – $537.1 million).

INTEREST RATE MANAGEMENT

The impact on effective interest rates of derivative instruments used to manage interest rate risk and the debt related to these instruments are as follows:

(millions of dollars) December 31, 2007	Maturity	Effective Interest Rate1	Notional Amounts
Liquids Pipelines
Floating to fixed interest swap (commercial paper)	2029	6.0%	25.4
Corporate
Floating to fixed interest swap (commercial paper)	2008 – 2009	4.5%	750.0
Floating to fixed interest swap (commercial paper)	2008 – 2009	4.3%	US$186.6

1. After giving effect to the derivative financial instruments.

CREDIT FACILITIES

(millions of dollars) December 31, 2007	Expiry Dates	Total Facility	Available	Drawdowns
Liquids Pipelines	2008 – 2009	794.1	433.4	360.7
Gas Distribution and Services	2008 – 2009	1,006.9	1,000.0	6.9
Corporate	2009 – 2012	3,842.9	3,842.9	-
		5,643.9	5,276.3	367.6

Credit facilities carry a weighted average standby fee of 0.062% per annum on the unused portion and drawdowns bear interest at market rates. Certain credit facilities serve as a backstop to the commercial paper programs and the Company has the option to extend the facilities, which are currently set to mature from 2009 to 2012.

13. NON RECOURSE DEBT

(millions of dollars) December 31,	Weighted Average Interest Rate	Maturity	2007	2006
Gas Pipelines
Long-term credit facilities (US$1.9 million; 2006 – US$6.0 million)	5.26%	2012	1.9	6.9
Senior notes (US$441.8 million; 2006 – US$469.5 million)	6.74%	2015 – 2025	436.5	547.1
Capital lease obligations	11.24%	2013 – 2020	39.9	49.6
Sponsored Investments
Credit facilities	5.12%	2010 – 2012	141.5	94.4
Medium term notes	4.69%	2009 – 2014	190.0	190.0
Senior notes	6.85%	2015 – 2025	707.7	733.7
Fair value increment on senior notes acquired			43.3	48.2
Gas Distribution and Services
Term debt (US$15.7 million; 2006 – US$5.8 million)	6.3%	2008 – 2010	15.5	6.8
Capital lease obligations	12.0%	2016 – 2021	4.9	5.4
Deferred debt issue costs (Note 2)			(11.7)	-
Total Non-Recourse Debt			1,569.5	1,682.1
Current Maturities			(61.1)	(60.1)
Non-Recourse Long-Term Debt			1,508.4	1,622.0

Long-term debt maturities on non-recourse borrowings for the years ending December 31, 2008 through 2012 are $61.1 million, $168.3 million, $176.8 million, $68.6 million and $118.4 million, respectively. The medium-term notes and senior notes bear interest at fixed rates.

Certain assets of Alliance Pipeline Canada are pledged as collateral to Alliance Pipeline Canada's lenders and to the lenders to Alliance Pipeline US. As well, certain assets of Alliance Pipeline US are pledged as collateral to Alliance Pipeline US's lenders and to the lenders to Alliance Pipeline Canada.

Not including the effects of hedging, non-recourse debt has a fair value of $1,634.8 million (2006 – $1,786.6 million).

14. NON CONTROLLING INTERESTS

(millions of dollars) December 31,	2007	2006
EEM	335.1	398.5
EGD Preferred Shares	100.0	100.0
EIF	155.9	167.3
EGNB	48.8	39.8
Other	10.7	9.6
	650.5	715.2

Non-controlling interest in EEM represents the 82.8% of the listed shares of EEM not held by the Company.

The Company owns 100% of the common shares of EGD; however, the 4,000,000 4.82% Cumulative Redeemable EGD Preferred Shares held by a third party are entitled to a claim on the assets of EGD prior to the common shareholder. Subsequent to July 1, 2009, EGD may, at its option, redeem all or a portion of the outstanding preferred shares for $25.00 plus all accrued and unpaid dividends to the redemption date. The preferred shares have no fixed maturity date.

Non-controlling interest in EIF represents 58.1% of voting units which are held by public unitholders. Non-controlling interest in EGNB represents 29.2% held by third parties.

15. SHARE CAPITAL

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

COMMON SHARES

December 31,	2007		2006		2005
(millions of dollars; number of common shares in millions)	Number of Shares	Amount	Number of Shares	Amount	Number of Shares	Amount
Balance at beginning of year	351.8	2,416.1	348.9	2,343.8	346.2	2,282.4
Common shares issued	15.0	566.4	-	-	-	-
Exercise of stock options	1.2	26.3	2.4	53.9	2.1	40.0
Dividend Reinvestment and Share Purchase Plan	0.5	17.7	0.5	18.4	0.4	14.6
Issued for business acquisition	-	-	-	-	0.2	6.8
Balance at end of year	368.5	3,026.5	351.8	2,416.1	348.9	2,343.8

PREFERRED SHARES

The 5.0 million 5.5% Cumulative Redeemable Preferred Shares, Series A are entitled to fixed, cumulative, quarterly preferential dividends of $1.375 per share per year. The Company may, at its option, redeem all or a portion of the outstanding preferred shares for $25.00 per share plus all accrued and unpaid dividends.

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 11.1 million shares (2006 – 10.6 million shares), resulting from the Company's reciprocal 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.

(number of common shares in millions) December 31,	2007	2006	2005
Weighted average shares outstanding	355.3	340.0	337.4
Effect of dilutive options	3.0	3.3	3.8
Diluted weighted average shares outstanding	358.3	343.3	341.2

For the year ended December 31, 2007, 1,158,200 anti-dilutive stock options (2006 – 1,548,900; 2005 – nil) with a weighted average exercise price of $38.26 (2006 – $36.47) were excluded from the diluted earnings per share calculation.

DIVIDEND REINVESTMENT AND SHARE PURCHASE PLAN

Under the Dividend Reinvestment and Share Purchase Plan, registered shareholders may reinvest dividends in common shares of the Company and make additional optional cash payments to purchase common shares, 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 Company's Board of Directors. 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.

16. STOCK OPTION AND STOCK UNIT PLANS

The Company maintains four plans for mid to long-term incentive compensation: the Incentive Stock Option (ISO) Plan, Performance Based Stock Option (PBSO) Plan, the Performance Stock Unit (PSU) Plan and the Restricted Stock Unit (RSU) Plan. A maximum of 30 million common shares were reserved for issuance under the 2002 ISO plan, of which 14.7 million have been issued to date. In 2007, a new reserve of 16.5 million shares was approved and established for the 2007 ISO and PBSO plans. The PSU and RSU plans grant notional units as if a unit was one Enbridge common share and are payable in cash.

INCENTIVE STOCK OPTIONS

Key employees are granted ISOs to purchase common shares at the market price on the grant date. ISOs vest in equal annual installments over a four-year period and expire 10 years after the issue date. Compensation expense recorded for the year ended December 31, 2007 for ISOs is $9.0 million (2006 – $10.5 million; 2005 – $5.5 million).

Outstanding Incentive Stock Options

December 31,	2007		2006		2005
(options in thousands; exercise price in dollars)	Number	Weighted Average Exercise Price	Number	Weighted Average Exercise Price	Number	Weighted Average Exercise Price
Options at beginning of year	9,186	24.97	9,434	22.09	9,650	19.86
Options granted	1,158	38.26	1,595	36.41	1,533	31.70
Options exercised	(1,046)	19.21	(1,698)	19.38	(1,617)	17.51
Options cancelled or expired	(61)	32.97	(145)	28.81	(132)	26.39
Options at end of year	9,237	27.24	9,186	24.97	9,434	22.09
Options vested	5,865	22.87	5,323	20.54	5,248	18.74

The total intrinsic value of ISOs exercised during the year ended December 31, 2007 was $19.1 million (2006 – $27.8 million; 2005 – $21.3 million) and cash received on exercise was $20.1 million (2006 – $32.9 million; 2005 – $28.3 million). Intrinsic value represents the difference between the Company's share price and the exercise price, multiplied by the number of options. The total intrinsic value of ISOs outstanding and vested at December 31, 2007 was $94.2 million and $85.5 million, respectively.

Incentive Stock Option Characteristics

	Options Outstanding			Options Vested
(options in thousands; exercise price in dollars) December 31, 2007 Exercise Price	Number	Weighted Average Remaining Life (years)	Weighted Average Exercise Price	Number	Weighted Average Exercise Price
10.00 – 14.99	441	2.2	13.28	441	13.28
15.00 – 19.99	1,276	2.4	18.29	1,276	18.29
20.00 – 24.99	2,160	4.6	21.28	2,160	21.28
25.00 – 29.99	1,365	6.0	25.74	972	25.74
30.00 – 34.99	1,370	7.1	31.79	648	31.73
35.00 – 38.26	2,625	8.5	37.25	368	36.47
	9,237	5.9	27.24	5,865	22.87

Weighted average assumptions used to determine the fair value of the ISOs using the Black Scholes option pricing model are as follows:

Year ended December 31,	2007	2006	2005
Fair value per option (dollars)	6.16	6.30	5.31
Valuation assumptions1
Expected option term (years)	6	8	8
Expected volatility	18.10%	19.00%	16.00%
Expected dividend yield	3.22%	3.23%	3.17%
Risk-free interest rate	4.11%	4.16%	4.40%

1. The expected option term and the expected volatility are based on historical information.

As of December 31, 2007, unrecognized compensation cost related to non-vested share based compensation arrangements granted under the ISO plan was $8.5 million. The cost is expected to be recognized over a period of 2.3 years.

PERFORMANCE BASED STOCK OPTIONS

PBSOs are granted to executive officers and become exercisable when both performance targets and time vesting requirements have been met. PBSOs were granted on September 16, 2002 and August 15, 2007. All performance targets and time vesting requirements for the 2002 PBSO grant have been met. The 2002 PBSO grant will expire on September 16, 2010. The 2007 PBSO grant performance targets are based on the Company's share price. Time vesting requirements for the 2007 PBSO grant are fulfilled evenly over a five-year term, ending August 15, 2012. Under the 2007 PBSO plan performance vesting targets must be met by February 15, 2014 otherwise the options expire. If targets are met by February 15, 2014, the options are exercisable until August 15, 2015. Compensation expense recorded for the year ended December 31, 2007 for PBSOs was $0.7 million.

Outstanding Performance Based Stock Options

December 31,	2007		2006		2005
(options in thousands; exercise price in dollars)	Number	Weighted Average Exercise Price	Number	Weighted Average Exercise Price	Number	Weighted Average Exercise Price
Options at beginning of year	1,379	23.15	2,105	21.57	2,555	20.68
Options granted	2,345	36.57	-	-	-	-
Options exercised	(136)	23.15	(645)	18.00	(450)	16.51
Options cancelled	-	-	(81)	23.15	-	-
Options at end of year	3,588	31.92	1,379	23.15	2,105	21.57
Options vested	1,243	23.15	1,119	23.15	1,457	20.87

The total intrinsic value of PBSOs exercised during the year ended December 31, 2007 was $1.9 million (2006 – $11.4 million; 2005 – $7.8 million) and cash received on exercise was $3.1 million (2006 – $11.6 million; 2005 – $7.4 million). The total intrinsic value of PBSOs outstanding and vested at December 31, 2007 is $19.8 million and $17.8 million, respectively.

Performance Based Stock Option Characteristics

	Options Outstanding			Options Vested
(options in thousands; exercise price in dollars) December 31, 2007 Exercise Price	Number	Weighted Average Remaining Life (years)	Weighted Average Exercise Price	Number	Weighted Average Exercise Price
23.15	1,243	2.7	23.15	1,243	23.15
36.57	2,345	7.6	36.57	-	-
	3,588	5.9	31.92	1,243	23.15

Assumptions used to determine the fair value of the PBSOs using the Bloomberg barrier option valuation model are as follows:

Year ended December 31,	2007
Fair value per option (dollars)	3.40
Valuation assumptions1
Expected option term (years)	8
Expected volatility	13.60%
Expected dividend yield	3.57%
Risk-free interest rate	4.38%

1. The expected option term and the expected volatility are based on historical information.

As of December 31, 2007, unrecognized compensation cost related to non-vested share based compensation arrangements granted under the PBSO plan was $7.3 million. The cost is expected to be recognized over a period of 4.6 years.

PERFORMANCE STOCK UNITS

The Company has a PSU Plan for senior officers where cash awards are paid following 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 current share price and by a performance multiplier. 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 performs within the highest range of its performance targets. The performance multiplier for the 2005 and 2006 grants is based on the Company's total shareholder return over the three-year performance period relative to a specified peer group of companies. The 2007 grant derives the performance multiplier through a calculation of the Company's Price/Earnings ratio relative to a specified peer group of companies and the Company's growth in earnings per share relative to targets established at the time of grant.

Compensation expense recorded for the year ended December 31, 2007 for PSUs was $3.0 million (2006 – $4.1 million; 2005 – $2.5 million). An estimated performance multiplier of 0.73, 1.0 and 1.0 was used to calculate the expense based upon historical performance for the 2005, 2006 and 2007 grants, respectively.

Outstanding Performance Stock Units

December 31,	2007	2006	2005
Units at beginning of year	328,716	200,652	67,688
Units granted	137,200	117,900	130,130
Units cancelled	(2,384)	-	(3,265)
Units matured	(209,827)	-	-
Dividend reinvestment	13,911	10,164	6,099
Units at end of year	267,616	328,716	200,652

Of the PSUs outstanding at December 31, 2007, 125,777 units have a performance period ending December 31, 2008 and 141,839 units have a performance period ending December 31, 2009. The total intrinsic value of PSUs outstanding at December 31, 2007 is $10.7 million.

RESTRICTED STOCK UNITS

Enbridge has a RSU plan where cash awards are granted to certain non-executive employees of the Company. After the thirty-five month maturity period, RSU holders receive cash equal to the Company's current share price for each RSU held. Compensation expense recorded for the year ended December 31, 2007 for RSUs was $7.1 million (2006 – $0.8 million; 2005 – nil).

Outstanding Restricted Stock Units

December 31,	2007	2006
Units at beginning of year	183,253	-
Units granted	276,875	181,882
Units cancelled	(18,627)	-
Dividend reinvestment	15,120	1,371
Units at end of year	456,621	183,253

The total intrinsic value of RSUs outstanding at December 31, 2007 is $18.3 million.

As of December 31, 2007, unrecognized compensation expense related to non-vested units granted under the PSU and RSU plans was $15.5 million, expected to be recognized over a period of 1.7 years.

17. COMPONENTS OF ACCUMULATED OTHER COMPREHENSIVE INCOME/(LOSS)

(millions of dollars)	Cash Flow Hedges	Equity Investees	Non-Controlling Interests	Cumulative Translation Adjustment	Net Investment Hedges	Total
Balance at January 1, 2006	-	-	-	(486.7)	428.1	(58.6)
Tax impact	-	-	-	-	(113.2)	(113.2)
	-	-	-	(486.7)	314.9	(171.8)
Changes during the period	-	-	-	87.6	(49.0)	38.6
Tax impact	-	-	-	-	(2.6)	(2.6)
	-	-	-	87.6	(51.6)	36.0
Balance at December 31, 2006	-	-	-	(399.1)	263.3	(135.8)
Adjustment on adoption (Note 2)	79.4	(57.3)	26.3	-	-	48.4
Tax impact	(20.3)	20.1	-	-	-	(0.2)
	59.1	(37.2)	26.3	-	-	48.2
Changes during the period	94.8	(29.2)	4.9	(447.1)	193.9	(182.7)
Tax impact	(5.1)	9.4	-	-	(19.0)	(14.7)
	89.7	(19.8)	4.9	(447.1)	174.9	(197.4)
Balance at December 31, 2007	148.8	(57.0)	31.2	(846.2)	438.2	(285.0)

18. FINANCIAL INSTRUMENTS & RISK MANAGEMENT

DERIVATIVE FINANCIAL INSTRUMENTS USED FOR RISK MANAGEMENT

Enbridge's earnings are subject to movements in interest rates, foreign exchange rates and commodity prices (collectively, market price risk). The Company uses derivative financial instruments for market price risk management purposes. The following summarizes the types of market price risks to which the Company is exposed, and the risk management instruments to mitigate them.

Foreign Exchange

The Company has exposure to foreign currency exchange rates, primarily arising from its U.S. dollar and euro denominated investments, where both carrying values and earnings are subject to foreign exchange rate variability. The Company uses long dated par forward contracts and cross currency swaps to manage a portion of the foreign exchange exposure related to both changes in carrying values of its equity investments and cash flows from other investments. In addition, the Company also uses short term foreign exchange forward contracts to manage exposure related to foreign currency denominated receivables and payables.

Interest Rate Risk

The Company is exposed to interest rate fluctuations on the cost of variable rate debt. Floating to fixed interest rate swaps, collars and forward rate agreements are used to hedge against the effect of future interest rate movements. The Company is also exposed to fluctuations in interest rates ahead of anticipated fixed rate debt issuances. The Company may enter into treasury locks or forward starting interest rate swaps to hedge a portion of the interest cost of these future debt issues.

Commodity Price Risk

The Company may use natural gas price swaps, futures and options to manage the value of commodity purchases and sales that arise from capacity commitments on the Alliance and Vector pipelines. The Company may also uses natural gas, power, crude oil and natural gas liquids swaps or options to fix the value of variable price exposures that arise from other commodity usage, storage, transportation and supply agreements.

The Company's regulated Liquids Pipelines segment uses a fixed price contract and related financial instrument to manage the mix of fixed and floating power costs. The Company recognizes the fair value of the fixed price contract, the fair value of the financial instrument and a regulatory liability that will be recognized over the life of the fixed price contract. At December 31, 2007, the Company recognized a liability of $3.5 million for unrealized financial instrument losses, an asset of $27.3 million related to the fixed price power contract and a regulatory liability of $23.8 million.

FAIR VALUE OF FINANCIAL INSTRUMENTS USED FOR RISK MANAGEMENT

Derivatives

The fair values of derivatives have been estimated using year-end market information. These fair values approximate the amount the Company would receive or pay to terminate the contracts. The current portion of derivatives is included in Accounts Receivable and Other and Accounts Payable and Other, while the long-term portion is included in Deferred Amounts and Other Assets and Other Long-Term Liabilities.

December 31,	2007			2006
millions of dollars unless otherwise noted)	Notional Principal or Quantity	Fair Value Receivable/ (Payable)	Maturity	Notional Principal or Quantity	Fair Value Receivable/ (Payable)	Maturity
Foreign exchange
U.S. cross currency swaps	138.0	46.7	2013 – 2022	307.3	(0.5)	2007 – 2022
Euro cross currency swaps	447.6	27.4	2008 – 2019	447.6	(9.9)	2007 – 2019
Forwards (cumulative exchange amounts)	2,608.0	226.3	2008 – 2022	1,536.7	231.3	2007 – 2022
Interest rates
Interest rate swaps/collars	1,117.0	(8.6)	2008 – 2029	1,947.3	(17.2)	2007 – 2029
Energy commodities
Energy commodity (bcf)	452.9	(43.5)	2008 – 2010	100.1	(12.9)	2007 – 2011
Natural gas supply (bcf)	0.7	(1.1)	2008	29.1	(26.6)	2007
Power (MW/H)	57.0	20.6	2008 – 2024	25.8	(8.3)	2007 – 2024

Derivative Instruments used as Cash Flow Hedges

(millions of dollars unless otherwise noted) December 31, 2007	Notional Principal or Quantity	Fair Value Receivable/ (Payable)	Maturity
Foreign exchange
U.S. cross currency swaps	138.0	46.7	2013 – 2022
Forwards (cumulative exchange amounts)	1,761.4	138.1	2008 – 2022
Interest rates
Interest rate swaps/collars	1,117.0	(8.6)	2008 – 2029
Energy commodities
Energy commodity (bcf)	43.6	3.2	2008 – 2010
Natural gas supply (bcf)	0.5	(1.0)	2008
Power (MW/H, net)	2.0	(2.1)	2008 – 2017

The Company estimates that $1.3 million of AOCI related to cash flow hedges will be reclassified to earnings in the next 12 months.

Derivative and Other Financial Instruments used as Net Investment Hedges

(millions of dollars unless otherwise noted) December 31, 2007	Notional Principal or Quantity	Fair Value Receivable/ (Payable)	Maturity
Foreign exchange
Euro cross currency swaps	447.6	27.4	2008 – 2019
Forwards (cumulative exchange amounts)	749.9	187.0	2013 – 2020

The Company has also designated a US$300 million medium-term note and US$317 million of commercial paper as hedges of certain US dollar investments.

Fair Value Hedges

As at December 31, 2007, the Company did not have any outstanding fair value hedges.

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 to settle these instruments at the reporting date. 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 reflects the Company's best estimates of market value based on generally accepted valuation techniques or models and supported by observable market prices and rates.

Unrealized Gains and Losses on Non-Hedging Derivatives

The Company does not use derivative instruments for speculative purposes; however, if a derivative instrument is not an effective hedge for accounting purposes or is not designated as a hedging item, changes in the fair value are recorded in current period earnings. The Company had an unrealized loss of $32.3 million (after tax) for the year ended December 31, 2007 on certain non-qualifying derivative instruments related to fixed price commodity purchases and sales.

CREDIT RISK

Entering into derivative financial instruments can give rise to credit 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 enters into risk management transactions only with institutions that possess high investment grade credit ratings. Credit risk relating to derivative counterparties is mitigated by credit exposure limits, contractual and collateral requirements and netting arrangements. The Company has no significant concentration with any single counterparty. The Company has credit risk of $267.8 million (2006 – $267.3 million; 2005 – $352.4 million) related to its derivative counterparties.

Credit risk also arises from trade receivables, which is mitigated by credit exposure limits, contractual and collateral requirements and netting arrangements. Credit risk in the Gas Distribution and Services segment is mitigated by the large and diversified customer base and the ability to recover an estimate for doubtful accounts through the ratemaking process.

19. INCOME TAXES

INCOME TAX RATE RECONCILIATION

(millions of dollars unless otherwise noted) Year ended December 31,	2007	2006	2005
Earnings before income taxes	916.3	814.6	784.2
Combined statutory income tax rate	33.9%	34.4%	35.2%
Income taxes at statutory rate	310.6	280.2	276.0
Increase/(decrease) resulting from:
Legislated tax changes	(62.8)	(63.0)	1.2
Future income taxes related to regulated operations	(5.8)	(10.5)	(15.3)
Non-taxable items, net	(18.5)	(21.4)	(44.1)
Lower foreign tax rates	(6.4)	(6.7)	(9.6)
Large Corporations Tax in excess of surtax	-	-	15.1
Other	(7.9)	13.7	(2.0)
Income Taxes	209.2	192.3	221.3
Effective income tax rate	22.8%	23.6%	28.2%

In 2007, income taxes paid amounted to $226.2 million (2006 – $182.6 million; 2005 – $150.3 million).

COMPONENTS OF FUTURE INCOME TAXES

(millions of dollars) December 31,	2007	2006
Future Income Tax Liabilities
Differences in accounting and tax bases of property, plant and equipment	608.6	639.8
Differences in accounting and tax bases of investments	337.0	375.6
Other comprehensive income	42.4	-
Other	101.8	201.7
	1,089.8	1,217.1
Future Income Tax Assets
Loss carryforwards	222.0	257.9
Other	78.9	96.8
	300.9	354.7
Total Net Future Income Tax Liability	788.9	862.4

Net future income tax liability of $788.9 million (2006 – $862.4 million) includes future income tax liabilities of $975.6 million (2006 – $1,062.5) net of future tax assets of $186.7 million (2006 – $200.1 million).

At December 31, 2007, the Company has recognized the benefit of unused tax loss carryforwards of $665.1 million (2006 – $760.6 million). Unused tax loss carryforwards expire as follows: 2009 – $0.4 million; 2014 – $2.6 million; 2015 – $6.3 million and 2019 and beyond – $655.8 million.

GEOGRAPHIC COMPONENTS OF PRETAX EARNINGS AND INCOME TAXES

(millions of dollars) December 31,	2007	2006	2005
Earnings before income taxes
Canada	511.1	430.7	487.3
United States	210.2	237.8	150.5
Other	195.0	146.1	146.4
	916.3	814.6	784.2
Current income taxes
Canada	152.7	204.3	106.9
United States	11.9	0.1	-
Other	3.8	8.9	6.3
	168.4	213.3	113.2
Future income taxes
Canada	(36.3)	(112.0)	49.4
United States	77.1	91.0	58.7
	40.8	(21.0)	108.1
Current and future income taxes	209.2	192.3	221.3

20. POST EMPLOYMENT BENEFITS

PENSION PLANS

The Company has three basic pension plans which provide either defined benefit or defined contribution pension benefits, or both to employees of the Company. The Liquids Pipelines and Gas Distribution and Services pension plans provide Company funded defined benefit pension and/or defined contribution benefits to Canadian employees of Enbridge. The Enbridge U.S. pension plan provides Company funded defined benefit pension benefits for U.S. based employees. The Company has four supplemental pension plans which provide pension benefits in excess of the basic plans for certain employees.

The measurement date used to determine the plan assets and the accrued benefit obligation was September 30, 2007.

Defined Benefit Plans

Benefits payable from the defined benefit plans are based on members' years of service and final average remuneration. These benefits are partially inflation indexed after a member's retirement. Contributions 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 Filed Actuarial Valuation	Effective Date of Next Required Actuarial Valuation
Liquids Pipelines	December 31, 2006	December 31, 2009
Enbridge U.S.	December 31, 2006	December 31, 2007
Gas Distribution and Services	December 31, 2006	December 31, 2009

The defined benefit pension plan costs have been determined based on management's best estimates and assumptions 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 plans, pension costs equal amounts required to be contributed by the Company. Pension costs in respect of these plans during the year were $3.6 million (2006 – $3.0 million; 2005 – $2.4 million).

POST-EMPLOYMENT BENEFITS OTHER THAN PENSIONS

Post-employment benefits other than pensions primarily include supplemental health, dental, health spending account 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.

	OPEB		Pension Benefits
(millions of dollars)	2007	2006	2007	2006
Change in accrued benefit obligation
Benefit obligation at beginning of year	193.2	191.6	1,109.0	1,039.3
Service cost	4.7	5.2	43.8	37.5
Interest cost	10.1	10.0	57.9	54.2
Amendments	-	-	0.1	2.9
Employee's contributions	0.4	0.4	-	-
Actuarial loss/(gain)	(10.2)	(7.7)	(46.4)	17.3
Benefits paid	(6.7)	(6.2)	(42.2)	(42.5)
Effect of exchange rate changes	(8.1)	(0.1)	(21.8)	0.3
Benefit obligation at end of year	183.4	193.2	1,100.4	1,109.0
Change in plan assets
Fair value of plan assets at beginning of year	50.2	43.3	1,227.1	1,191.1
Actual return on plan assets	1.7	1.5	104.8	78.8
Employer's contributions	8.1	11.0	44.1	0.7
Employee's contributions	0.4	0.4	-	-
Benefits paid	(6.7)	(6.2)	(42.2)	(42.5)
Other	-	-	(1.5)	(1.1)
Effect of exchange rate changes	(5.9)	0.2	(22.4)	0.1
Fair value of plan assets at end of year	47.8	50.2	1,309.9	1,227.1
Funded Status
Benefit obligation	(183.4)	(193.2)	(1,100.4)	(1,109.0)
Fair value of plan assets	47.8	50.2	1,309.9	1,227.1
Overfunded/(Underfunded) status at end of year	(135.6)	(143.0)	209.5	118.1
Contribution after measurement date	1.0	0.4	-	16.7
Unamortized prior service cost	-	-	12.8	15.5
Unamortized transitional obligation/(asset)	12.1	13.4	(17.6)	(19.8)
Unamortized net loss	32.9	46.0	13.5	93.1
Net amount recognized at end of year	(89.6)	(83.2)	218.2	223.6

The amounts recognized include all of the Company's plans; however, the Gas Distribution and Services plans are funded through regulated rates on a cash basis and are not recorded as net pension assets or liabilities. Excluding Gas Distribution and Services plans, the Company's plans using the accrual method provide for a net pension asset of $64.9 million (2006 – $66.4 million) and a net OPEB liability of $18.8 million (2006 – $17.0 million). The pension asset is recorded on the balance sheet in Deferred Amounts and Other Assets while the pension liability is recorded in Other Long-Term Liabilities, with the current portion for each recorded in working capital accounts.

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,	2007	2006	2005	2007	2006	2005
Discount rate	5.71%	5.37%	5.30%	5.65%	5.27%	5.24%
Average rate of salary increases				5.00%	5.00%	4.44%

NET PENSION PLAN AND OPEB COSTS RECOGNIZED

(millions of dollars) Year ended December 31,	2007	2006	2005
Benefits earned during the year	52.1	45.7	32.3
Interest cost on projected benefit obligations	68.0	64.2	63.2
Actual return on plan assets	(106.5)	(80.3)	(162.9)
Difference between actual and expected return on plan assets	19.9	(3.4)	87.3
Amortization of prior service costs	2.0	2.0	2.3
Amortization of transitional obligation	(0.9)	(0.8)	0.2
Amortization of actuarial loss	13.9	15.3	9.6
Amount charged to EEP	(11.3)	(10.5)	(10.2)
Pension and OPEB cost recognized	37.2	32.2	21.8

The table reflects the pension and OPEB cost for all of the Company's benefit plans on an accrual basis. Using the cash basis for Gas Distribution and Services rate regulated plans and the accrual method for all other plans, the Company's pension cost was $23.4 million (2006 – $20.1 million; 2005 – $11.6 million), and its OPEB cost was $6.9 million for 2007 (2006 – $7.0 million; 2005 – $5.9 million).

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,	2007	2006	2005	2007	2006	2005
Discount rate	5.37%	5.30%	6.21%	5.27%	5.24%	6.26%
Average rate of salary increases				5.00%	4.44%	4.00%
Average rate of return on pension plan assets	4.50%	4.50%	4.50%	7.31%	7.31%	7.31%

MEDICAL COST TREND RATES

The assumed rates for the next year used to measure the expected cost of benefits 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 and Dental	5%	5%	2008
U.S. Plan	10%	5%	2013

A one percent increase in the assumed medical and dental care trend rate would result in an increase of $27.3 million in the accumulated post-employment benefit obligations and an increase of $2.4 million in benefit and interest costs. A one percent decrease in the assumed medical and dental care trend rate would result in a decrease of $22.0 million in the accumulated post-employment benefit obligations and a decrease of $1.9 million in benefit and interest costs.

MAJOR CATEGORIES OF PLAN ASSETS

	OPEB				Pension Benefits
	2007			2006	2007			2006
(millions of dollars) Year ended December 31,	Target	Actual	Amount	Actual	Target	Actual	Amount	Actual
Equity securities	-	-	-	-	60%	60.7%	794.9	61.1%
Fixed income securities	100%	85.4%	40.8	86.9%	40%	33.5%	438.6	34.0%
Other	-	14.6%	7.0	13.1%	-	5.8%	76.4	4.9%
Total Assets	100%	100%	47.8	100%	100%	100%	1,309.9	100%

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

EXPECTED RATE OF RETURN ON PLAN ASSETS

	OPEB		Pension Benefits
Year ended December 31,	2007	2006	2007	2006
Canadian Plans	4.50%	4.50%	7.25%	7.25%
U.S. Plan	4.50%	4.50%	7.75%	7.25%

The Company manages the investment risk of its pension funds by setting a long term asset mix policy for each 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 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

	OPEB		Pension Benefits
(millions of dollars) Year ended December 31,	2007	2006	2007	2006
Total contributions	8.1	11.0	44.1	0.7
Contributions expected to be paid in 2008	6.9	7.4	25.9	19.8

BENEFITS EXPECTED TO BE PAID BY THE COMPANY

(millions of dollars) Year ended December 31,	2008	2009	2010	2011	2012	2013 – 2017
Expected future benefit payments	50.0	52.3	55.0	57.5	60.6	354.8

21. OTHER INVESTMENT INCOME

(millions of dollars) Year ended December 31,	2007	2006	2005
Interest income	32.7	29.3	28.3
Gain on reduction of EEP ownership interest	33.9	-	24.5
Noverco preferred dividends income	15.8	15.6	16.8
OCENSA investment income	24.7	26.8	29.0
Net foreign currency gains	26.2	13.3	6.8
Allowance for equity funds used during construction	15.1	1.5	0.9
Hurricane insurance recoveries	14.6	6.0	-
Other	32.1	15.3	36.1
	195.1	107.8	142.4

22. CHANGES IN OPERATING ASSETS AND LIABILITIES

(millions of dollars) Year ended December 31,	2007	2006	2005
Accounts receivable and other	(502.1)	3.9	(441.4)
Inventory	159.5	134.1	(215.7)
Deferred amounts and other assets	(134.6)	(67.3)	(90.2)
Accounts payable and other1	503.8	43.5	394.8
Interest payable	(5.9)	12.5	(1.4)
	20.7	126.7	(353.9)

1. Changes in construction payable are included in investing activities.

23. RELATED PARTY TRANSACTIONS

EEP does not have employees and uses the services of the Company for managing and operating its businesses. Vector Pipeline contracts the services of Enbridge to operate the pipeline. Amounts for these services, which are charged at cost in accordance with service agreements, are:

(millions of dollars) Year ended December 31,	2007	2006	2005
EEP	267.1	244.9	184.7
Vector Pipeline	4.8	4.1	4.1
	271.9	249.0	188.8

EGD, a subsidiary of the Company, has contracts for gas transportation services from Alliance Pipeline and Vector Pipeline. EGD is charged market prices for these services:

(millions of dollars) Year ended December 31,	2007	2006	2005
Alliance Pipeline Canada	21.3	23.6	22.9
Alliance Pipeline US	15.1	14.1	17.5
Vector Pipeline	25.0	27.3	29.2
	61.4	65.0	69.6

CustomerWorks Limited Partnership (CustomerWorks), a joint venture, provided customer care services to EGD under an agreement having a five-year term which expired in 2007 and was not renewed. EGD was charged market prices for these services. CustomerWorks also rented an automated billing system from Enbridge Commercial Services Inc. (ECS), a subsidiary of the Company. Amounts charged by/(to) CustomerWorks are as follows:

(millions of dollars) Year ended December 31,	2007	2006	2005
EGD	26.3	108.5	103.6
ECS	(1.8)	(8.1)	(8.7)
	24.5	100.4	94.9

Enbridge Gas Services (US) Inc., a subsidiary of the Company, purchases and sells gas at prevailing market prices with Enbridge Marketing (US) Inc., a subsidiary of EEP. Amounts paid/(recovered) are as follows:

(millions of dollars) Year ended December 31,	2007	2006	2005
Purchases	43.5	29.2	48.1
Sales	(4.1)	(6.3)	(4.7)
	39.4	22.9	43.4

Enbridge Gas Services Inc., a subsidiary of the Company, has transportation commitments through 2015 on Alliance Pipeline Canada and Vector Pipeline. Amounts paid are as follows:

(millions of dollars) Year ended December 31,	2007	2006	2005
Alliance Pipeline Canada	8.5	8.3	9.1
Vector Pipeline	0.6	0.6	0.7
	9.1	8.9	9.8

Enbridge Gas Services (US) Inc., has transportation commitments through 2015 on Alliance Pipeline US and Vector Pipeline. Amounts paid are as follows:

(millions of dollars) Year ended December 31,	2007	2006	2005
Alliance Pipeline US	6.6	6.9	7.1
Vector Pipeline	15.6	16.5	9.5
	22.2	23.4	16.6

Tidal Energy Marketing Inc., a subsidiary of the Company, purchases and sells commodities at prevailing market prices with EEP and a subsidiary of EEP as follows:

(millions of dollars) Year ended December 31,	2007	2006	2005
Purchases	4.6	17.0	9.7
Sales	(5.5)	(6.7)	-
	(0.9)	10.3	9.7

RECEIVABLE FROM AFFILIATE

The receivable from affiliate of $128.5 million (2006 – $158.8 million included in Accounts Receivable and Other), included in Deferred Amounts and Other Assets, initially resulted from the sale of Enbridge Midcoast Energy to EEP. During 2007, the original loan receivable was repaid and a new loan was entered into. The loan, denominated in U.S. dollars, bears interest at 8.4% and matures in 2017. Interest income related to the note was $10.0 million, $11.8 million and $11.7 million, in 2007, 2006 and 2005, respectively. The fair value of the receivable approximates its carrying value.

The Company also provides limited consulting and other services to investees as required. Market prices are charged for these services where they are reasonably determinable or at cost when required by regulatory agreement. Where no market price exists, a cost-based price is charged. The Company may also purchase consulting and other services from affiliates with prices being determined on the same basis as services provided by the Company. The Company and affiliates invoice on a monthly basis and amounts are due and paid on a quarterly basis.

24. COMMITMENTS AND CONTINGENCIES

ENBRIDGE GAS DISTRIBUTION INC.

Bloor Street Incident

The Company was charged under both the Ontario Technical Standards and Safety Act (TSSA) and the Ontario Occupational Health and Safety Act (OHSA) in connection with an explosion that occurred on Bloor Street West in Toronto on April 24, 2003. On October 25, 2007, all of the TSSA and OHSA charges laid against the Company were dismissed by the Ontario Court of Justice. On November 22, 2007 EGD was served with a Notice of Appeal by the Crown seeking a new trial before a different judge. The maximum possible fine upon conviction on all charges would have been approximately $5.0 million in the aggregate.

The Company 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 majority of the civil actions have been settled and the Company does not expect the outstanding civil actions to result in any material financial impact.

Harper Gardens Incident

In February 2007, an explosion and fire occurred at a residence on Harper Gardens in Toronto. The home was destroyed and a resident of the home was killed. A gas fitter in the home at the time of the explosion was seriously burned. Several public authorities are investigating the incident. EGD has also been named as defendant in civil actions related to the explosion, but does not expect these actions to result in any material financial impact.

Remediation of Discontinued Manufactured Gas Plant Sites

EGD may incur future costs due to claims relating to alleged coal tar contamination at or near former manufactured gas plant (MPG) sites. In October 2002, a claim was filed for $55.0 million in damages relating to a certain MPG site. EGD filed a statement of defence in June 2003 denying liability. Although the Company 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 may be recovered through rates. As such, EGD does not believe the outcome will have any material financial impact.

GST Overpayment

In December 2007, EGD discovered that it had remitted excess GST to the Canada Revenue Agency (CRA). In respect of certain months within the 2003 to 2005 calendar year periods, the amount of such overpayment is approximately $40 million and is included in accounts receivable. EGD expects that it will recover the overpayment from CRA.

CAPLA CLAIM

The Canadian Alliance of Pipeline Landowners' Associations (CAPLA) and two individual landowners have commenced a class action against the Company and TransCanada PipeLines Limited. The claim relates to restrictions in the National Energy Board Act on crossing the pipeline and the landowners' use of land within a 30-metre control zone on either side of the pipeline easements. The Plaintiffs filed a motion to establish a cause of action which is one of the requirements to have the motion certified as a class action under the Class Proceedings Act (Ontario). The motion was dismissed by the Ontario District Court in late 2006. The Plantiff appealed the decision and the appeal was heard by the Ontario Court of Appeal on December 18, 2007. The decision of the Court of Appeal has not been released. The Company believes it has a sound defence and intends to defend the claim. Since the outcome is indeterminable, the Company has made no provision at this time for any potential liability.

ENBRIDGE ENERGY COMPANY, INC.

Enbridge Energy Company, Inc. (EEC), a subsidiary of the Company, is the general partner of EEP. EEC's former subsidiary Enbridge Midcoast Energy Inc. (Midcoast) has been assessed by the U.S. Internal Revenue Service (IRS) for US$4.5 million in taxes, interest and penalties for its 1999 through 2001 taxation years. Midcoast has paid all amounts and has filed a claim for refund of the full amount. The IRS has challenged Midcoast's tax treatment of its 1999 acquisition of several partnerships that owned a natural gas pipeline system in Kansas (these assets were sold to EEP in 2002 and subsequently sold by EEP in 2007). The IRS position, if sustained, could decrease the U.S. tax basis for the pipeline assets, which could reduce Enbridge's earnings by up to approximately US$60.0 million, although the immediate cash tax impact would be significantly less. Enbridge believes the tax treatment of the acquisition and related tax deductions claimed were appropriate. Enbridge initiated proceedings in U.S. District Court (Houston) in 2006 to litigate this matter.

OTHER TAX MATTERS

Enbridge and its subsidiaries maintain tax liabilities related to uncertain tax positions. While fully supportable in the Company's view, these tax positions, if challenged by tax authorities, may not be fully sustained on review.

OTHER LITIGATION

The Company and its subsidiaries are subject to various other legal actions and proceedings which arise in the normal course of business. While the final outcome of such actions and proceedings cannot be predicted with certainty, Management believes that the resolution of such actions and proceedings will not have a material impact on the Company's consolidated financial position or results of operations.

COMMITMENTS

The Company has signed contracts for the purchase of pipe and other materials totaling $947.6 million, to be used in the construction of several Liquids Pipelines projects including the Southern Lights project, the Waupisoo Pipeline, the Alberta Clipper project, the Southern Access Expansion and Extension projects, the Hardisty Terminal project as well as the Line 4 Extension project.

25. GUARANTEES

EEC, as the general partner of 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 is subject to recourse with respect to US$124.0 million of EEP's long-term debt at December 31, 2007 (2006 – US$155.0 million).

The Company has also agreed to indemnify EEM for any tax liability related to EEM's formation, management of EEP and ownership of i-units of EEP. The Company has not made any significant payment under these tax indemnifications. The Company does not believe there is a material exposure at this time.

In the normal course of conducting business, Enbridge enters into a wide variety of agreements which provide for indemnification to third parties. Enbridge cannot reasonably estimate the maximum potential amounts that could become payable to third parties under these agreements; however, historically, Enbridge has not made any significant payments under these indemnification provisions. While many of these agreements may specify a maximum potential exposure, or a specified duration to the indemnification obligation, there are circumstances where the amount and duration are unlimited. Examples where such indemnification obligations have been issued include:

Sale Agreements for Assets or Businesses

• breaches of representations, warranties or covenants;
• loss or damages to property;
• environmental liabilities;
• changes in laws;
• valuation differences;
• litigation; and
• contingent liabilities.

Provision of Services and Other Agreements

• breaches of representations, warranties or covenants;
• changes in laws;
• intellectual property rights infringement; and
• litigation.

When disposing of assets or businesses, the Company may indemnify the purchaser for certain tax liabilities incurred while the Company owned the assets or for a misrepresentation related to taxes that result in a loss to the purchaser. Similarly, the Company may indemnify the purchaser of assets for certain tax liabilities related to those assets.

26. SUBSEQUENT EVENT

On February 13, 2008 Enbridge announced it is evaluating strategic alternatives for monetizing its investment in CLH. Earnings generated by the CLH investment in 2007 were $65.6 million (2006 – $54.5 million; 2005 – $61.6 million) and cash flows were $58.2 million (2006 – $56.2 million; 2005 – $36.5 million). The book value of the CLH investment at December 31, 2007 was $626.4 million which does not include unrealized foreign exchange gains and related unrealized net investment hedge gains of $32.9 million recorded in AOCI.

27. UNITED STATES ACCOUNTING PRINCIPLES

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

EARNINGS AND COMPREHENSIVE INCOME

(millions of dollars) Year ended December 31,	2007	2006	2005
Earnings under Canadian GAAP	707.1	622.3	562.9
Stock based compensation1	-	-	(16.6)
Earnings under U.S. GAAP	707.1	622.3	546.3
Other comprehensive income/(loss) under Canadian GAAP	(197.4)	36.0	(32.0)
Unrealized net gain/(loss) on cash flow hedges3	-	(64.2)	72.3
Underfunded pension adjustment (net of tax)4	23.3	-	-
Comprehensive income under U.S. GAAP	533.0	594.1	586.6
Earnings per common share under U.S. GAAP	1.97	1.81	1.65
Diluted earnings per common share under U.S. GAAP	1.95	1.79	1.63

FINANCIAL POSITION

	2007		2006
(millions of dollars) December 31,	Canada	United States	Canada	United States
Assets
Cash and cash equivalents3,6	166.7	214.4	139.7	347.0
Accounts receivable and other1,3,4,6	2,388.7	3,118.4	2,045.6	2,920.0
Inventory3,6	709.4	817.3	868.9	1,005.0
	3,264.8	4,150.1	3,054.2	4,272.0
Property, plant and equipment, net3,6	12,597.6	17,999.4	11,264.7	15,628.4
Long-term investments3,6	2,076.3	1,253.1	2,299.4	1,368.8
Deferred amounts and other assets2,3,4,5,6	1,182.0	1,653.5	924.5	1,540.5
Intangible assets6	212.0	302.4	241.5	348.0
Goodwill6	388.0	725.1	394.9	803.2
Future income taxes6	186.7	187.3	200.1	200.1
	19,907.4	26,270.9	18,379.3	24,161.0
Liabilities and Shareholders' Equity
Short-term borrowings	545.6	545.5	807.9	807.9
Accounts payable and other1,3,4,6	2,213.8	3,195.1	1,723.8	2,818.6
Interest payable6	89.1	109.8	95.1	108.4
Current maturities and short-term debt6	605.2	632.7	537.0	537.0
Current portion of non-recourse debt3,6	61.1	60.9	60.1	83.2
	3,514.8	4,544.0	3,223.9	4,355.1
Long-term debt4	7,729.0	10,600.5	7,054.0	7,054.0
Non-recourse long-term debt3,6	1,508.4	1,508.4	1,622.0	4,029.6
Other long-term liabilities3,5,6	253.9	479.2	91.1	310.8
Future income taxes2,3,4,5,6	975.6	1,545.7	1,062.5	1,696.4
Non-controlling interests6	650.5	2,355.2	715.2	2,163.9
	14,632.2	21,033.0	13,768.7	19,609.8
Shareholders' Equity
Preferred shares	125.0	125.0	125.0	125.0
Common shares	3,026.5	3,026.5	2,416.1	2,416.1
Contributed surplus	25.7	-	18.3	-
Retained earnings	2,537.3	2,504.4	2,322.7	2,242.8
Additional paid in capital	-	69.6	-	62.2
Foreign currency translation adjustment4	-	-	(135.8)	-
Accumulated other comprehensive loss4,5	(285.0)	(333.3)	-	(159.2)
Reciprocal shareholding	(154.3)	(154.3)	(135.7)	(135.7)
	5,275.2	5,237.9	4,610.6	4,551.2
	19,907.4	26,270.9	18,379.3	24,161.0

1. Stocked based Compensation

   Effective January 1, 2006, the Company adopted Financial Accounting Standard 123 Revised 2004 (FAS 123R) Share Based Payment, on a modified prospective basis for U.S. GAAP purposes. FAS 123R requires the use of the fair value method to measure compensation expense for the Company's Fixed Stock Options (FSOs) and PBSOs issued after January 1, 2006, as well as for the portion of awards for which the requisite service has not been performed that are outstanding as of January 1, 2006. FAS 123R also requires the use of the fair value method for awards settled in cash, including the company's PSUs and RSUs.

   The Company had previously adopted the fair value recognition provisions of the former FAS 123, Share Based Payment, effective January 1, 2003, resulting in the recognition of stock based compensation expense using the fair value method for FSOs and PBSOs issued subsequent to that date.

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. At December 31, 2007, a deferred tax liability of $572.7 million (2006 – $648.7 million) is recorded for U.S. GAAP purposes and reflects the difference between the carrying value and the tax basis of property, plant and equipment. Regulated companies following the taxes payable method are not required to record this additional tax liability under Canadian GAAP. To recover the additional deferred income taxes recorded under U.S. GAAP through the ratemaking process, it would be necessary to record incremental revenue of $785.6 million (2006 – $926.7 million).

3. Accounting for Joint Ventures

   U.S. GAAP requires the Company's investments in joint ventures to be accounted for using the equity method. However, under an accommodation of the U.S. Securities and Exchange Commission, accounting for jointly controlled investments need not be reconciled from Canadian to U.S. GAAP if the joint venture is jointly controlled by all parties having an equity interest in the entity. Joint ventures in which all owners do not share joint control are reconciled to U.S. GAAP. The different accounting treatment affects only display and classification and not earnings or shareholders' equity.

4. Accumulated Other Comprehensive Loss

   The only Canadian – U.S. GAAP difference in accumulated other comprehensive loss is the underfunded status of the pension and OPEB plans. The Company estimates that approximately $1.3 million related to pension and OPEB plans at December 31, 2007 will be reclassified into earnings during the next twelve months.

   Financial instruments are now recognized in Canadian GAAP in substantially the same manner as U.S. GAAP. As a result of the change in Canadian accounting, certain comparative balances have been reclassified for U.S. GAAP purposes, including the recognition of regulated non-financial instruments and offsetting regulatory liabilities as well as OCI from equity investees. In addition, transaction costs arising from the issuance of debt are now recorded net against the related long-term debt. For U.S. GAAP, these transaction costs are reclassified to deferred amounts and other assets.

5. Pension Funding Status

   The Company adopted FAS 158, Employers' Accounting for Defined Pension and Other Postretirement Plans, effective December 31, 2006. FAS 158 requires an employer to recognize the overfunded or underfunded status of a defined benefit post retirement plan or OPEB as an asset or liability and to recognize changes in the funded status in the period in which they occur through comprehensive income. FAS 158 adjustments resulted in an increase in the net liability of $73.1 million (2006 – $110.1 million) for the underfunded status of the plans, a decrease in deferred tax liability of $24.8 million (2006 – $38.5 million) and an increase in accumulated other comprehensive loss of $48.3 million (2006 – $71.6 million). As required by FAS 158, the Company will change the measurement date of its defined benefit pension plan from September 30 to December 31, effective the year ended 2008.

6. Consolidation of a Limited Partnership

   Effective January 1, 2006, the Company adopted, without restatement of prior periods, EITF 04-5, Determining Whether a General Partner, or the General Partners as a Group, Controls a Limited Partnership or Similar Entity When the Limited Partners Have Certain Rights. As a result of adopting EITF 04-5, the Company is consolidating its 15.1% interest in Enbridge Energy Partners for U.S. GAAP purposes, resulting in an increase to both assets and liabilities of $5,932.7 million (2006 – $5,084.8 million) and no changes to equity and earnings.

7. Uncertain Tax Positions

   On January 1, 2007, the Company adopted FASB Interpretation No. 48 (FIN 48), Accounting for Uncertainty in Income Taxes, an Interpretation of FASB Statement No. 109. FIN 48 addresses the threshold for recognizing a tax position in the financial statements. The adoption of FIN 48 did not have an impact on the consolidated financial statements.

NEW ACCOUNTING STANDARDS

Fair Value Measurements

In September 2006, the FASB issued Statement No. 157, Fair Value Measurements. The Statement defines fair value, establishes a framework for measuring fair value in the context of GAAP and expands the disclosure surrounding fair value measurement. In January 2008, the FASB deferred the implementation of this standard indefinitely for all non-financial assets and non-financial liabilities, except those that are recognized or disclosed at fair value in the financial statements on a recurring basis until January 1, 2009. The requirements of this standard will be effective for the Company beginning on January 1, 2008.

Fair Value Option for Assets and Liabilities

In February 2007, the FASB issued Statement No. 159, Fair Value Option for Financial Assets and Liabilities. This standard provides companies with an option to measure, at specified election dates, certain financial assets and liabilities at fair value. Changes in fair value are recognized in earnings. The requirements of this standard will be effective for the Company beginning on January 1, 2008.

Management does not expect the adoption of these standards to significantly impact the financial statements.