Exhibit 99.6

ENBRIDGE INC.

CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2009

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MANAGEMENT'S REPORT

TO THE SHAREHOLDERS OF ENBRIDGE INC.

Financial Reporting

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

The Board of Directors and its committees are responsible for all aspects related to governance of the Company. The Audit, Finance & Risk Committee of the Board, composed of directors who are unrelated and independent, has a specific responsibility to oversee management’s efforts to fulfil its responsibilities for financial reporting and internal controls related thereto. The Committee meets with management, internal auditors and independent auditors to review the consolidated financial statements and the internal controls as they relate to financial reporting. The Audit, Finance & Risk Committee reports its findings to the Board for its consideration in approving the consolidated financial statements for issuance to the shareholders.

Internal Control over Financial Reporting

Management is also responsible for establishing and maintaining adequate internal control over financial reporting. The Company’s internal control over financial reporting includes policies and procedures to facilitate the preparation of relevant, reliable and timely information, to prepare consolidated financial statements for external reporting purposes in accordance with generally accepted accounting principles and provide reasonable assurance that assets are safeguarded.

Management assessed the effectiveness of the Company’s internal control over financial reporting as of December 31, 2009, based on the framework established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).  Based on this assessment, management concluded that the Company maintained effective internal control over financial reporting as of December 31, 2009.

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

“signed”	“signed”
Patrick D. Daniel	J. Richard Bird
President & Chief Executive Officer	Executive Vice President &
	Chief Financial Officer

February 18, 2010

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Independent Auditors’ Report	PricewaterhouseCoopers LLP Chartered Accountants 111 5 Avenue SW, Suite 3100 Calgary, Alberta Canada T2P 5L3 Telephone +1 (403) 509 7500 Facsimile +1 (403) 781 1825

To the Shareholders of

Enbridge Inc.

We have completed integrated audits of Enbridge Inc.’s 2009, 2008 and 2007 consolidated financial statements and of its internal control over financial reporting as at December 31, 2009.  Our opinions, based on our audits, are presented below.

Consolidated financial statements

We have audited the accompanying consolidated statements of financial position of Enbridge Inc. as at December 31, 2009 and December 31, 2008, and the related consolidated statements of earnings, comprehensive income, shareholders’ equity and cash flows for each of the years in the three year period ended December 31, 2009.  These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits of the Company’s financial statements as at December 31, 2009 and December 31, 2008, and for each of the years in the three year period ended December 31, 2009 in accordance with Canadian generally accepted auditing standards and the standards of the Public Company Accounting Oversight Board (United States).  Those standards require that we plan and perform an audit to obtain reasonable assurance about whether the financial statements are free of material misstatement.  An audit of financial statements includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements.  A financial statement audit also includes assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of the Company as at December 31, 2009 and December 31, 2008, and the results of its operations and its cash flows for each of the years in the three year period ended December 31, 2009 in accordance with Canadian generally accepted accounting principles.

Internal control over financial reporting

We have also audited Enbridge Inc.’s internal control over financial reporting as at December 31, 2009, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).  The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control Over Financial Reporting.  Our responsibility is to express an opinion on the effectiveness of the Company’s internal control over financial reporting based on our audit.

We conducted our audit of internal control over financial reporting in accordance with the standards of the Public Company Accounting Oversight Board (United States).  Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects.  An audit of internal control over financial reporting includes obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exits, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we consider necessary in the circumstances.  We believe that our audit provides a reasonable basis for our opinion.

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“PricewaterhouseCoopers” refers to PricewaterhouseCoopers LLP, an Ontario limited liability partnership, or, as the context requires, the PricewaterhouseCoopers global network or other member firms of the network, each of which is a separate legal entity.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally

 accepted accounting principles.  A company’s internal control over financial reporting includes those policies and procedures

that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements.  Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as at December 31, 2009 based on criteria established in Internal Control — Integrated Framework issued by the COSO.

Chartered Accountants

Calgary, Alberta, Canada

February 18, 2010

Comments by Auditors for U.S. Readers on Canada – U.S. Reporting Differences

In the United States, reporting standards for auditors require the addition of an explanatory paragraph (following the opinion paragraph) when there is a change in accounting principles that has a material effect on the comparability of the Company’s financial statements, such as the changes described in notes 3 to the consolidated financial statements. Our report to the shareholders dated February 18, 2010 is expressed in accordance with Canadian reporting standards, which do not require a reference to such a change in accounting principles in the Independent Auditors’ Report when the change is properly accounted for and adequately disclosed in the financial statements.

Chartered Accountants

Calgary, Alberta, Canada

February 18, 2010

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CONSOLIDATED STATEMENTS OF EARNINGS

(millions of Canadian dollars, except per share amounts)

Year ended December 31,	2009	2008		2007
Revenues
Commodity sales	9,720	13,432		9,536
Transportation and other services	2,746	2,699		2,383
	12,466	16,131		11,919
Expenses
Commodity costs	9,011	12,792		9,009
Operating and administrative	1,430	1,312		1,164
Depreciation and amortization	764	658		597
	11,205	14,762		10,770
	1,261	1,369		1,149
Income from Equity Investments	198	177		168
Other Investment Income (Note 28)	678	198		195
Interest Expense (Note 16)	(597)	(551	)	(550)
Gain on Sale of Investments (Note 6)	365	700		-
	1,905	1,893		962
Non-Controlling Interests	(37)	(56	)	(46)
	1,868	1,837		916
Income Taxes (Note 26)	(306)	(509	)	(209)
Earnings	1,562	1,328		707
Preferred Share Dividends	(7)	(7	)	(7)
Earnings Applicable to Common Shareholders	1,555	1,321		700
Earnings per Common Share (Note 20)	4.27	3.67		1.97
Diluted Earnings per Common Share (Note 20)	4.25	3.64		1.95

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

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CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(millions of Canadian dollars)

Year ended December 31,	2009	2008		2007
Earnings	1,562	1,328		707
Other Comprehensive Income/(Loss)
Change in unrealized gain/(loss) on cash flow hedges, net of tax	(54)	(127	)	97
Change in unrealized gain/(loss) on net investment hedges,net of tax	151	(160	)	175
Reclassification to earnings of realized gain/(loss) on cash flow hedges, net of tax	114	(1	)	(7)
Reclassification to earnings of unrealized cash flow hedges, net of tax (Note 6)	(20)	-		-
Other comprehensive income/(loss) from equity investees,net of tax	(24)	49		(20)
Non-controlling interests in other comprehensive income	72	(101	)	92
Change in foreign currency translation adjustment	(815)	658		(534)
Other Comprehensive Income/(Loss)	(576)	318		(197)
Comprehensive Income	986	1,646		510

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

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CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY

(millions of Canadian dollars, except per share amounts)

Year ended December 31,	2009	2008		2007
Preferred Shares (Note 20)	125	125		125
Common Shares (Note 20)
Balance at beginning of year	3,194	3,027		2,416
Common shares issued	4	-		567
Dividend reinvestment and share purchase plan	143	131		18
Shares issued on exercise of stock options	38	36		26
Balance at End of Year	3,379	3,194		3,027
Contributed Surplus
Balance at beginning of year	38	26		18
Stock-based compensation	19	14		9
Options exercised	(3)	(2	)	(1)
Balance at End of Year	54	38		26
Retained Earnings
Balance at beginning of year	3,383	2,537		2,323
Earnings applicable to common shareholders	1,555	1,321		700
Common share dividends declared	(555)	(489	)	(453)
Dividends paid to reciprocal shareholder	17	14		14
Cumulative impact of change in accounting policy (Note 3)	-	-		(47)
Balance at End of Year	4,400	3,383		2,537
Accumulated Other Comprehensive Income/(Loss) (Note 22)
Balance at beginning of year	33	(285	)	(136)
Other comprehensive income/(loss)	(576)	318		(197)
Cumulative impact of change in accounting policy (Note 3)	-	-		48
Balance at End of Year	(543)	33		(285)
Reciprocal Shareholding (Note 11)
Balance at beginning of year	(154)	(154	)	(136)
Participation in common shares issued	-	-		(18)
Balance at End of Year	(154)	(154	)	(154)
Total Shareholders’ Equity	7,261	6,619		5,276
Dividends Paid per Common Share	1.48	1.32		1.23

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

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CONSOLIDATED STATEMENTS OF CASH FLOWS

(millions of Canadian dollars)

Year ended December 31,	2009	2008	2007
Operating Activities
Earnings	1,562	1,328	707
Depreciation and amortization	764	658	597
Unrealized (gain)/loss on derivative instruments	(204)	(120)	32
Allowance for equity funds used during construction	(135)	(59)	(15)
Equity earnings in excess of cash distributions	(9)	(82)	(35)
Gain on reduction of ownership interest	-	(12)	(34)
Gain on sale of investments (Note 6)	(365)	(700)	-
Future income taxes	218	258	41
Goodwill and asset impairment losses	11	23	-
Non-controlling interests	37	56	46
Other	(105)	48	19
Changes in operating assets and liabilities (Note 29)	243	(26)	4
	2,017	1,372	1,362
Investing Activities
Long-term investments	(359)	(659)	(20)
Affiliate loans, net	(145)	-	15
Proceeds on sale of investments (Note 6)	535	1,383	-
Sale of property, plant and equipment	87	-	-
Settlement of hedges	6	(47)	-
Additions to property, plant and equipment (Note 4)	(3,225)	(3,545)	(2,231)
Additions to intangible assets	(95)	(91)	(68)
Change in construction payable	(110)	106	75
	(3,306)	(2,853)	(2,229)
Financing Activities
Net change in short-term borrowings	(366)	329	(262)
Net change in commercial paper and credit facility draws	632	751	337
Debenture and term note issues	1,500	498	1,342
Debenture and term note repayments	(516)	(602)	(635)
Net change in Southern Lights project financing	343	1,238	-
Non-recourse debt issues	106	38	57
Non-recourse debt repayments	(172)	(65)	(59)
Distributions to non-controlling interests	(33)	(10)	(18)
Common shares issued	36	29	584
Preferred share dividends	(7)	(7)	(7)
Common share dividends	(414)	(359)	(435)
	1,109	1,840	904
Effect of translation of foreign denominated cash and cash equivalents	(35)	16	(10)
Increase/(Decrease) in Cash and Cash Equivalents	(215)	375	27
Cash and Cash Equivalents at Beginning of Year	542	167	140
Cash and Cash Equivalents at End of Year1	327	542	167
Supplementary Cash Flow Information
Income taxes paid (Note 26)	205	161	226
Interest paid (Note 16)	656	607	607

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

1 Cash and cash equivalents consists of $184 million (2008 - $68 million; 2007 - $79 million) of cash and $143 million (2008 - $474 million; 2007 - $88 million) of short-term investments and includes restricted cash of $59 million (2008 - $81 million; 2007 - $64 million).

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CONSOLIDATED STATEMENTS OF FINANCIAL POSITION

(millions of Canadian dollars)

December 31,	2009	2008
Assets
Current Assets
Cash and cash equivalents	327	542
Accounts receivable and other (Note 7)	2,484	2,322
Inventory (Note 8)	784	845
	3,595	3,709
Property, Plant and Equipment, net (Note 9)	18,850	16,157
Long-Term Investments (Note 11)	2,312	2,492
Deferred Amounts and Other Assets (Note 12)	2,425	1,318
Intangible Assets (Note 13)	488	458
Goodwill (Note 14)	372	389
Future Income Taxes (Note 26)	127	178
	28,169	24,701
Liabilities and Shareholders’ Equity
Current Liabilities
Short-term borrowings (Note 16)	508	874
Accounts payable and other (Note 15)	2,463	2,411
Interest payable	104	102
Current maturities of long-term debt (Note 16)	601	534
Current maturities of non-recourse long-term debt (Note 17)	113	185
	3,789	4,106
Long-Term Debt (Note 16)	11,581	10,155
Non-Recourse Long-Term Debt (Note 17)	1,393	1,474
Other Long-Term Liabilities (Note 18)	1,207	259
Future Income Taxes (Note 26)	2,211	1,291
	20,181	17,285
Non-Controlling Interests (Note 19)	727	797
Shareholders’ Equity
Share capital
Preferred shares (Note 20)	125	125
Common shares (Note 20)	3,379	3,194
Contributed surplus	54	38
Retained earnings	4,400	3,383
Accumulated other comprehensive income/(loss) (Note 22)	(543)	33
Reciprocal shareholding (Note 11)	(154)	(154)
	7,261	6,619
Commitments and Contingencies (Note 31)
	28,169	24,701

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

Approved by the Board of Directors:
“signed"	“signed"
David A. Arledge	David A. Leslie
Chair	Director

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NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

1.GENERAL BUSINESS DESCRIPTION

Enbridge Inc. (Enbridge or the Company) is a publicly traded energy transportation and distribution company. Enbridge conducts its business through four operating segments identified based on products and services offered: Liquids Pipelines, Natural Gas Delivery and Services, Sponsored Investments, and Corporate. These operating segments are strategic business units established by senior management to facilitate the achievement of the Company’s long-term objectives, to aid in resource allocation decisions and to assess operational performance.

LIQUIDS PIPELINES

Liquids Pipelines includes the operation and construction of the Enbridge crude oil mainline system and feeder pipelines that transport crude oil and other liquid hydrocarbons. Liquids Pipelines consists of crude oil, natural gas liquids (NGLs) and refined products pipelines and terminals in Canada and the United States.

NATURAL GAS DELIVERY AND SERVICES

Natural Gas Delivery and Services consists of natural gas utility operations, investments in natural gas pipelines, the Company’s commodity marketing businesses and international activities.

The core of the Company’s natural gas utility operations is Enbridge Gas Distribution Inc. (EGD) which serves residential, commercial, industrial and transportation customers, primarily in central and eastern Ontario as well as northern New York State. This business segment also includes natural gas distribution activities in Quebec and New Brunswick.

Investments in natural gas pipelines include the Company’s interests in the United States portion of Alliance Pipeline (Alliance Pipeline US), Vector Pipeline and transmission and gathering pipelines in the Gulf of Mexico.

This segment also includes the Company’s investment in Aux Sable, a natural gas fractionation and extraction business.

The commodity marketing businesses manage the Company’s volume commitments on Alliance and Vector Pipelines as well as perform commodity storage, transport and supply management services, as principal and agent.

SPONSORED INVESTMENTS

Sponsored Investments includes the Company’s 27.0% ownership interest in Enbridge Energy Partners, L.P. (EEP), Enbridge’s funding of 66.7% of the United States segment of the Alberta Clipper Project through EEP and Enbridge Energy, L.P. (EELP) and a 72% economic interest (41.9% voting interest) in Enbridge Income Fund (EIF). Enbridge manages the day-to-day operations of, and develops and assesses opportunities for each of these investments, including both organic growth and acquisition opportunities.

EEP transports crude oil and other liquid hydrocarbons through common carrier and feeder pipelines and transports, gathers, processes and markets natural gas and NGLs. EIF is a publicly traded income fund whose primary operations include a crude oil and liquids pipeline and gathering system, a 50% interest in the Canadian portion of Alliance Pipeline and partial interests in several green energy investments.

CORPORATE

Corporate consists of new business development activities and investing and financing activities, including general corporate investments and financing costs not allocated to the business segments. Corporate also includes the Company’s investments in green energy projects.

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2.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 consolidated financial statements are described in Note 33. 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 consolidated financial statements. Significant estimates and assumptions used in preparation of the consolidated financial statements include, but are not limited to: carrying value of regulatory assets and liabilities (Note 5); depreciation rates and carrying value of property, plant and equipment (Note 9); amortization rates of intangible assets (Note 13); measurement of goodwill (Note 14); valuation of share based compensation (Note 21); fair values of financial instruments (Notes 23 and 24); income taxes (Note 26); post employment benefits (Note 27); and commitments and contingencies (Note 31). Actual results could differ from these estimates.

Subsequent events have been evaluated through to February 18, 2010, the date on which the consolidated financial statements were approved by the Board of Directors and were available to be issued.

BASIS OF PRESENTATION

The consolidated financial statements include the accounts of Enbridge Inc., its subsidiaries and its proportionate share of the accounts of joint ventures. EIF is consolidated in the accounts of the Company because it is a variable interest entity. The Company is the primary beneficiary of EIF through a combination of a 41.9% equity interest and a preferred unit investment. Investments in entities which are not subsidiaries or joint ventures, but over which the Company exercises significant influence, are accounted for using the equity method. Other investments are accounted for according to their classification as held to maturity, loans and receivables or available for sale (see Financial Instruments).

REGULATION

Certain of the Company’s Liquids Pipelines and Natural Gas Delivery and Services businesses are subject to regulation by various authorities including, but not limited to, the National Energy Board (NEB), the Federal Energy Regulatory Commission (FERC), the Energy Resources Conservation Board in Alberta (ERCB), the New Brunswick Energy and Utilities Board (EUB) and the Ontario Energy Board (OEB). Regulatory bodies exercise statutory authority over matters such as construction, rates and ratemaking and agreements with customers. To recognize the economic effects of the actions of the regulator, the timing of recognition of certain revenues and expenses in these operations may differ from that otherwise expected under GAAP 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 generally not recognize regulatory assets or liabilities and the earnings impact would be recorded in the period the expenses are incurred or revenues are earned. Long-term regulatory assets are recorded in Deferred Amounts and Other Assets and current regulatory assets are recorded in Accounts Receivable and Other. Long-term regulatory liabilities are included in Other Long-Term Liabilities and current regulatory liabilities are recorded in Accounts Payable and Other. Regulatory assets are assessed for impairment if the Company identifies an event indicative of possible impairment.

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.

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

Prior to January 1, 2009, contributions made to the defined benefit pension plan and the cost of providing post-employment benefits other than pensions (OPEB) for the regulated operations of EGD were expensed as paid, consistent with the recovery of such costs in rates. Canadian GAAP requires costs and obligations for defined benefit pension plans and OPEB to be determined using the projected benefit method and charged to earnings as services are rendered. Effective January 1, 2009, the Company began recording a net pension asset and a net OPEB liability with an offsetting regulatory liability and asset related to the contributions to the defined benefit plan and the cost of OPEB for the regulated operations in Natural Gas Delivery and Services (Note 3). There was no impact to earnings or cash flows as a result of this change.

REVENUE RECOGNITION

For businesses which are not rate-regulated, revenues are recorded when products have been delivered or services have been performed and the amount of revenue can be reliably measured. Customer credit worthiness is assessed prior to agreement signing as well as throughout the contract duration.

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 Sponsored Investments and in natural gas pipelines included in Natural Gas Delivery and Services, transportation revenues include amounts related to expenses recognized 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 a regulatory asset or liability.

For natural gas utility rate-regulated operations in Natural Gas Delivery and Services, revenue is recognized in a manner consistent with the underlying rate-setting mechanism as mandated by the regulator. Natural gas utilities 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.

FINANCIAL INSTRUMENTS

The Company classifies financial assets and financial liabilities as held for trading, available for sale, loans and receivables, held to maturity, other financial liabilities or derivatives in qualifying hedging relationships. All financial instruments are initially recorded at fair value on the consolidated statement of financial position. Subsequent measurement of the financial instrument is based on its classification.

Held for Trading

Financial assets and liabilities that are classified as held for trading are measured at fair value with changes in fair value recognized in earnings in Commodity Costs, Other Investment Income and Interest Expense. The Company has classified Cash and Cash Equivalents and its non-qualifying derivative instruments as held for trading.

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Available for Sale

Financial assets that are available for sale are measured at fair value, with changes in those fair values recorded in Other Comprehensive Income (OCI) unless actively quoted prices are not available for fair value measurement, in which case available for sale assets are measured at cost. Generally, the Company classifies equity investments in other entities that do not trade on an actively quoted market as available for sale. Dividends received from available for sale financial assets are recognized in earnings when the right to receive payment is established.

Loans and Receivables

Loans and receivables, which include Accounts Receivable and Other and long-term notes receivable, are measured at amortized cost using the effective interest rate method, net of any impairment losses recognized.

Held to Maturity

The Company has classified certain investments which are non-derivative financial assets as held to maturity. Held to maturity investments are measured at amortized cost using the effective interest rate method.

Other Financial Liabilities

Other financial liabilities are recorded at amortized cost using the effective interest rate method and include Short-term Borrowings, Accounts Payable and Other, Interest Payable, Long-term Debt and Non-recourse Long-term Debt.

Derivatives in Qualifying Hedging Relationships

The Company uses derivative financial instruments to manage changes in commodity prices, foreign exchange rates, interest rates and certain compensation tied to its share price. Hedge accounting is optional and 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. Derivatives in qualifying hedging relationships are categorized as cash flow hedges, fair value hedges and net investment hedges.

Cash Flow Hedges

The Company uses cash flow hedges to manage changes in commodity prices, foreign exchange rates, interest rates and certain compensation tied to its share price. The effective portion of the change in the fair value of a cash flow hedging instrument is recorded in OCI and is reclassified to earnings when the hedged item impacts earnings or to the carrying value of the related non-financial asset. 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 in which 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, otherwise required to be carried at cost or amortized cost, ceases to be remeasured at fair value and the cumulative fair value adjustment to the carrying value of the hedged item 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 United States dollar denominated foreign operations. The effective portion of the change in the fair value of the hedging

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instrument is recorded in OCI. Any ineffectiveness is recorded in current period earnings. Amounts recorded in Accumulated Other Comprehensive Income/Loss (AOCI) are recognized in earnings when there is a reduction of the hedged net investment resulting from a disposal of the foreign operation.

Impairment

With respect to available for sale instruments, the Company assesses at each balance sheet date whether there is objective evidence that a financial asset is impaired. If there is determined to be objective evidence of impairment, the Company internally values the expected discounted cash flows using observable market inputs and determines whether the decline below carrying value is other than temporary. If the decline is determined to be other than temporary, an impairment charge is recorded in earnings with an offsetting reduction to the carrying value of the asset.

With respect to loans and receivables, the Company assesses the assets for impairment when it no longer has a reasonable assurance of timely collection. If evidence of impairment is noted, the Company reduces the value of the loan or receivable to its estimated realizable amount, determined using discounted expected future cash flows.

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.

INCOME TAXES

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 (Note 3).

FOREIGN CURRENCY TRANSLATION

The Company’s foreign operations are primarily self-sustaining. The financial statements of self-sustaining foreign operations are translated into Canadian dollars using the current rate method. Under this method, assets and liabilities are translated using period-end exchange rates and revenues and expenses are translated using monthly average rates. Gains and losses arising on translation of these operations are included in the cumulative translation adjustment component of AOCI.

Transactions denominated in foreign currencies are translated into Canadian dollars using the exchange rate prevailing at the date of transaction. Monetary assets and liabilities denominated in foreign currencies are translated to Canadian dollars using the rate of exchange in effect at the balance sheet date whereas non-monetary assets and liabilities are translated at the rate of exchange in effect on the date of the transaction. Exchange gains and losses resulting from translation are included in the Statement of Earnings in the period that they arise.

CASH AND CASH EQUIVALENTS

Cash and cash equivalents include short-term investments with a term to maturity of three months or less when purchased.Cash and cash equivalents include amounts in trust and proportionately consolidated cash from joint ventures.

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 distribution 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 fair value as measured at the spot price less costs to sell (Note 3).

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PROPERTY, PLANT AND EQUIPMENT

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

IMPAIRMENT OF LONG-LIVED ASSETS

The Company reviews the carrying values of its long-lived assets as events or changes in circumstances warrant. If it is determined that the carrying value of an asset exceeds the undiscounted cash flows expected from the asset, the asset is written down to fair value.

DEFERRED AMOUNTS AND OTHER ASSETS

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

INTANGIBLE ASSETS

Intangible assets consist primarily of acquired long-term transportation contracts and software costs, which are amortized on a straight-line basis over their expected lives (Note 3).

GOODWILL

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

ASSET RETIREMENT OBLIGATIONS

Asset retirement obligations (AROs) associated with the retirement of long-lived assets are measured at fair value and recognized as Other Long-term Liabilities in the period when they can be reasonably determined. The fair value approximates the cost a third party would charge to perform 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.

POST-EMPLOYMENT BENEFITS

The Company maintains pension plans which provide defined benefit and defined contribution pension benefits.

Defined benefit pension plan costs are determined using actuarial methods and are funded through contributions determined using the projected benefit method, which incorporates management’s best estimate of future salary levels, other cost escalations, retirement ages of employees and other actuarial factors. Pension cost is charged to earnings as services are rendered and includes:

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·Cost of pension plan benefits provided in exchange for employee services rendered during the year;

·Amortization of the initial net transitional asset, prior service costs and amendments on a straight-line basis over the expected average remaining service period of the active employee group covered by the plans;

·Interest cost of pension plan obligations;

·Expected return on pension fund assets; and

·Amortization of cumulative unrecognized net actuarial gains and losses, in excess of 10% of the greater of the accrued benefit obligation or the fair value of plan assets, over the expected average remaining service life of the active employee group covered by the plans.

Actuarial gains and losses arise from the difference between the actual and expected rate of return on plan assets for that period or from changes in actuarial assumptions used to determine the accrued benefit obligation, including discount rate or salary inflation experience.

Pension plan assets are measured at fair value. The expected return on pension plan assets is determined using market related values and assumptions on the specific asset mix within the pension plan. The market related values reflect estimated return on investments consistent with long-term historical averages for similar assets.

For defined contribution plans, contributions made by the Company are expensed in the period in which the contribution occurs.

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 in which employees render service.

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 (RSUs) vest at the completion of a 35-month term. Both PSUs and RSUs are settled in cash. During the vesting term, an expense is recorded based on the number of units outstanding and the current market price of the Company’s shares with an offset to Other Long-Term Liabilities. The value of the PSUs is also dependent on the Company’s 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.

3.CHANGES IN ACCOUNTING POLICIES

ACCOUNTING FOR THE EFFECTS OF RATE REGULATION

Effective January 1, 2009, the Company adopted revisions to the Canadian Institute of Chartered Accountants (CICA) Handbook Section 1100, Generally Accepted Accounting Principles and Section 3465, Income Taxes. In accordance with the transitional provisions in these revised standards, the revisions to Section 1100 were adopted prospectively and accordingly, prior periods were not restated, while the revisions to Section 3465 were applied retrospectively without restatement of prior periods. The adoption of the revised standards did not impact the Company’s earnings or cash flows.

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Generally Accepted Accounting Principles

The revised standard no longer provides an exemption for rate-regulated entities to measure assets and liabilities on a basis other than in accordance with primary sources of Canadian GAAP. As a result, for the pension plans and OPEB included in EGD, the Company recognized post-employment benefit assets and liabilities for the amount of benefits expected to be included in future rates and recovered from, or paid to, customers. In addition, the Company reclassified certain EGD reserves for future removal and site restoration.

Pension Plans and OPEB

On adoption of the revised standard at January 1, 2009, the Company recognized a net pension asset of $157 million and a net OPEB liability of $75 million, with an offsetting long-term net pension regulatory liability and long-term net OPEB regulatory asset, respectively. At December 31, 2009, the Company had a net pension asset of $140 million and a net OPEB liability of $80 million, with an offsetting long-term net pension regulatory liability and a long-term net OPEB regulatory asset, respectively.

Future Removal and Site Restoration Reserves

At January 1, 2009, on adoption of the revised standard, the Company reclassified amounts collected for future removal and site restoration of $657 million, which were previously netted against Property, Plant and Equipment, to a long-term regulatory liability. At December 31, 2009, this long-term regulatory liability was $710 million.

Income Taxes

The revised standard removes the exemption for rate-regulated entities to recognize future income taxes to the extent they were expected to be included in regulator-approved future rates and recovered from or refunded to future customers. As a result, on January 1, 2009, the Company recognized a future income tax liability of $816 million on regulatory assets, primarily property, plant and equipment, with an offsetting long-term regulatory asset. A regulatory asset has been recognized as the associated future income tax liability is expected to be recoverable in future rates. At December 31, 2009, the Company had a future income tax liability of $829 million related to regulatory assets with an offsetting long-term regulatory asset.

INTANGIBLE ASSETS

Effective January 1, 2009, the Company adopted CICA Handbook Section 3064, Goodwill and Intangible Assets, which establishes standards for the recognition, measurement, presentation and disclosure of goodwill and intangible assets. As a result of adopting this standard, the Company reclassified certain software costs from Property, Plant and Equipment to Intangible Assets. This standard has been applied retrospectively and affects presentation only.

As a result of adopting this standard, on January 1, 2009, the Company reclassified $233 million of net software costs from Property, Plant and Equipment to Intangible Assets. At December 31, 2009, the Company had $289 million of net software costs recorded in Intangible Assets.

COMMODITY INVENTORY

Effective January 1, 2009, the Company changed its accounting policy for inventory held by its energy marketing businesses and began measuring commodity inventory at fair value, as measured at the spot price less costs to sell, rather than lower of cost or net realizable value. This measurement basis is a more relevant measurement for commodity inventory used for marketing purposes and better matches the commodity inventory with the derivatives used to “lock in” the margin. This change in accounting policy has been accounted for retrospectively and did not result in restatements of the comparative Consolidated Statements of Earnings, Comprehensive Income, Shareholders’ Equity or Cash Flows for the years ended December 31, 2008 and 2007 and the comparative Consolidated Statement of Financial Position as at December 31, 2008 as the amounts were considered immaterial.

INVENTORIES

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

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Company.

CAPITAL DISCLOSURES AND FINANCIAL INSTRUMENTS — DISCLOSURES AND PRESENTATION

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

FINANCIAL INSTRUMENTS, COMPREHENSIVE INCOME AND HEDGING RELATIONSHIPS

Effective January 1, 2007, the Company adopted CICA Handbook Section 1530, Comprehensive Income, Section 3251, Equity, Section 3855, Financial Instruments — Recognition and Measurement, Section 3861, Financial Instruments — Disclosure and Presentation (subsequently replaced by Sections 3862 and 3863 adopted by the Company on January 1, 2008) and Section 3865, Hedges. In accordance with the transitional provisions in these new standards, these policies were adopted retrospectively without restatement. 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 cumulative impact of adopting these changes in 2007 was an increase to AOCI of $48 million.

FUTURE ACCOUNTING POLICY CHANGES

Business Combinations

The CICA issued Handbook Section 1582, Business Combinations, which replaces Section 1581. This new standard aligns accounting for business combinations under Canadian GAAP with IFRS. The standard requires assets and liabilities acquired in a business combination to be measured at fair value at the acquisition date. The standard also requires acquisition-related costs, such as advisory or legal fees, incurred to effect a business combination to be expensed in the period in which they are incurred. The adoption of this standard will impact the accounting treatment of future business combinations. The revised standard is effective for business combinations occurring on or after January 1, 2011; however, earlier application is permitted.

Consolidated Financial Statements and Non-Controlling Interests

The CICA issued Handbook Sections 1601, Consolidated Financial Statements and 1602, Non-controlling Interests, which together replace the former consolidated financial statements standard. Under the revised standards, non-controlling interests will be classified as a component of equity, and earnings and comprehensive income will be attributed to both the parent and non-controlling interest. The adoption of these standards is not expected to have a material impact to the Company’s consolidated financial statements. The revised standards are effective January 1, 2011. Should the Company early adopt Section 1582, it would also be required to adopt Sections 1601 and 1602 at the same time.

4.SEGMENTED INFORMATION

		Natural Gas
(millions of Canadian dollars)	Liquids	Delivery and	Sponsored
Year ended December 31, 2009	Pipelines	Services	Investments	Corporate	Consolidated
Revenues	1,333	10,776	313	44	12,466
Commodity costs	-	(9,011)	-	-	(9,011)
Operating and administrative	(565)	(709)	(113)	(43)	(1,430)
Depreciation and amortization	(230)	(419)	(88)	(27)	(764)
	538	637	112	(26)	1,261
Income from equity investments	-	10	188	-	198
Other investment income and gain on sale of investments	161	370	13	499	1,043
Interest and preferred share dividends	(144)	(257)	(56)	(147)	(604)
Non-controlling interests	(2)	(7)	(28)	-	(37)
Income taxes	(108)	(118)	(88)	8	(306)
Earnings applicable to common shareholders	445	635	141	334	1,555

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			Natural Gas
(millions of Canadian dollars)	Liquids		Delivery and		Sponsored
Year ended December 31, 2008	Pipelines		Services		Investments		Corporate		Consolidated
Revenues	1,170		14,650		298		13		16,131
Commodity costs	-		(12,792	)	-		-		(12,792	)
Operating and administrative	(492	)	(685	)	(102	)	(33	)	(1,312	)
Depreciation and amortization	(181	)	(392	)	(78	)	(7	)	(658	)
	497		781		118		(27	)	1,369
Income from equity investments	-		30		148		(1	)	177
Other investment income and gain on sale of investments	61		759		25		53		898
Interest and preferred share dividends	(111	)	(270	)	(60	)	(117	)	(558	)
Non-controlling interests	(1	)	(7	)	(47	)	(1	)	(56	)
Income taxes	(118	)	(335	)	(73	)	17		(509	)
Earnings applicable to common shareholders	328		958		111		(76	)	1,321

			Natural Gas
(millions of Canadian dollars)	Liquids		Delivery and		Sponsored
Year ended December 31, 2007	Pipelines		Services		Investments		Corporate		Consolidated
Revenues	1,091		10,549		270		9		11,919
Commodity costs	-		(9,009	)	-		-		(9,009	)
Operating and administrative	(427	)	(632	)	(79	)	(26	)	(1,164	)
Depreciation and amortization	(156	)	(360	)	(75	)	(6	)	(597	)
	508		548		116		(23	)	1,149
Income from equity investments	(1	)	73		97		(1	)	168
Other investment income and gain on sale of investments	16		88		38		53		195
Interest and preferred share dividends	(101	)	(271	)	(62	)	(123	)	(557	)
Non-controlling interests	(1	)	(6	)	(38	)	(1	)	(46	)
Income taxes	(134	)	(88	)	(54	)	67		(209	)
Earnings applicable to common shareholders	287		344		97		(28	)	700

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

TOTAL ASSETS

(millions of Canadian dollars)
December 31,	2009	2008
Liquids Pipelines	10,763	7,467
Natural Gas Delivery and Services	11,207	10,724
Sponsored Investments	3,860	3,766
Corporate	2,339	2,744
	28,169	24,701

ADDITIONS TO PROPERTY, PLANT AND EQUIPMENT1

(millions of Canadian dollars)
December 31,	2009	2008
Liquids Pipelines	2,662	2,898
Natural Gas Delivery and Services	440	544
Sponsored Investments	41	53
Corporate	217	109
	3,360	3,604

1  Includes AEDC

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GEOGRAPHIC INFORMATION

Revenues1

(millions of Canadian dollars)
Year ended December 31,	2009	2008	2007
Canada	9,503	12,459	8,346
United States	2,963	3,672	3,573
	12,466	16,131	11,919

2Revenues are based on the country of origin of the product or services sold.

Property, Plant and Equipment

(millions of Canadian dollars)
December 31,	2009	2008
Canada	15,101	12,107
United States	3,749	4,050
	18,850	16,157

5.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 products and services to customers, referred to as the cost of service toll methodology. The Company’s significant regulated businesses and related accounting impacts are described below.

Enbridge System

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

The incentive tolling settlement (ITS) was 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. Surcharges are also determined for a number of system expansion components and are added to the base toll determined for the core system. Discussions and negotiations continue with the Canadian Association of Petroleum Producers (CAPP) and a representative shipper group for an extension to the 2005 ITS which will support a competitive toll structure. The Company anticipates it will reach a settlement by the end of the first quarter of 2010. In the event that a settlement cannot be reached, the Company could file a cost of service application.

Athabasca Pipeline

Athabasca Pipeline is regulated by the ERCB. Tolls are established based on long-term transportation agreements with individual shippers.

Vector Pipeline

Vector Pipeline is an interstate natural gas pipeline in the United States with a FERC approved tariff that establishes 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 for the year ended December 31, 2009 include an after-tax return on equity (ROE) component of 11.07% (2008 - 11.04%; 2007 - 10.75%).

Alliance Pipeline

The United States portion of the Alliance Pipeline is regulated by the FERC and the Canadian portion of the pipeline is regulated by the NEB. Shippers on the Alliance Pipeline are subject to 15-year transportation contracts that expire in December 2015, with a cost of service toll methodology. Toll adjustments are filed

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annually with the regulator. The tolls for the year ended December 31, 2009 include an after-tax ROE component of 10.88% (2008 - 10.88%; 2007 - 10.88%) for the United States portion and 11.26% (2008 - 11.26%; 2007 - 11.26%) for the Canadian portion. Alliance Pipeline tolls are based on a deemed 70% debt and 30% equity structure.

Enbridge Gas Distribution

EGD’s gas distribution operations are regulated by the OEB. EGD’s rates are based on a revenue per customer cap incentive regulation (IR) methodology, expiring in December 2012, which adjusts revenues, and consequently rates, annually and relies on an annual process to forecast volume and customer additions.

EGD’s after-tax rate of return on common equity embedded in rates was 8.39% for the year ended December 31, 2009 (2008 - 8.39%; 2007 - 8.39%) based on a 36% (2008 - 36%; 2007 - 36%) deemed common equity component of capital for regulatory purposes.

Enbridge Gas New Brunswick

Enbridge Gas New Brunswick (EGNB) is regulated by the EUB and follows a cost of service tolling methodology. An application for rate adjustments is filed annually for EUB approval. EGNB’s after-tax ROE was 13.00% (2008 - 13.00%; 2007 - 13.00%) based on equity which is capped at 50%.

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FINANCIAL STATEMENT EFFECTS

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

					Estimated
					Settlement
(millions of Canadian dollars)					Period	Earnings Impact1
December 31,	2009		2008		(years)	2009		2008		2007
Regulatory Assets/(Liabilities)
Liquids Pipelines
Future income taxes2	504		-		-	49		-		-
Enbridge System tolling deferrals3	98		114		1	(16	)	(30	)	(23	)
Power purchase arrangements4	(2	)	(21	)	1-3	(19	)	3		(24	)
	600		93			14		(27	)	(47	)
Natural Gas Delivery and Services
Future income taxes2	227		-		-	(11	)	-		-
Deferred transportation revenue5	185		267		14-16	(6	)	1		6
EGNB regulatory deferral6	155		133		31	15		10		10
Class action lawsuit settlement7	20		20		3	-		(1	)	-
Shared savings mechanism8	14		8		1	-		-		-
Ontario hearing costs9	6		5		2	-		(2	)	(1	)
Transportation revenue adjustment10	3		7		1	(2	)	1		(3	)
Unaccounted for gas variance11	10		1		1	6		(4	)	11
Future removal and site restoration
reserves12	(710	)	-		-	6		-		-
Purchased gas variance13	(227	)	(75	)	1	-		-		-
Pension plans and OPEB, net14	(60	)	-		-	(2	)	-		-
Earnings sharing deferral15	(25	)	(6	)	1	-		-		-
Transactional services deferral16	(14	)	(7	)	1	-		-		-
	(416	)	353			6		5		23
Sponsored Investments
Future income taxes2	98		-		-	(11	)	-		-
Deferred transportation revenue5	91		80		16	5		6		8
	189		80			(6	)	6		8
	373		526			14		(16	)	(16	)

1The effect of a number of the Company’s businesses being subject to rate regulation increased/(decreased) after-tax reported earnings by the identified amounts.

2This regulatory asset is an offsetting balance to a future income tax liability recognized on adoption of a revised accounting standard (Note 3). The future income tax liability primarily relates to future income taxes associated with property, plant and equipment. The balance has been recognized as a regulatory asset since the flow-through treatment of taxes for rate-setting purposes would ensure eventual recovery of these balances as the temporary differences reverse. The recovery period will depend on the period in which the future income tax amounts reverse. In the absence of rate regulation, the liability method of accounting for income taxes would be utilized and future income tax expense would be recorded.

3Tolls on the Enbridge System are calculated in accordance with the ITS, System Expansion Program (SEP), Terrace, Southern Access, Line 4 and the Alberta Clipper agreements and are established each year based on capacity and the allowed revenue requirement. Where actual volumes shipped on the pipeline do not result in collection of the annual revenue requirement, a regulatory asset is recognized and incorporated into tolls in the subsequent year. Recovery in the subsequent year, in whole or in part, is dependent upon realizing shipping volumes consistent with tolling model forecasts. Under or over collections are rolled into subsequent years. In addition, other tolling deferrals are recorded in accordance with the various agreements.

4The power purchase arrangements liability represents the fair value of fixed price contracts and related financial instruments used to manage the mix of fixed and floating power costs (Note 23). Under rate regulation any fair value changes are passed to shippers through tolls. In the absence of rate regulation, these changes would impact earnings in the year incurred.

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5Deferred transportation revenue is related to the cumulative difference between Canadian GAAP depreciation expense for 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 Canadian GAAP depreciation rates: for Alliance Pipeline US beginning in 2009, for Alliance Pipeline Canada beginning in 2011 and ending in 2025 and for Vector Pipeline beginning in 2008 and ending in 2023. This regulatory asset is not included in the rate base.

6A regulatory deferral account captures the cumulative difference between EGNB’s distribution revenues and its cost of service revenue requirement during the development period. The regulatory deferral account balance is expected to be amortized over a recovery period approved by the EUB expected to commence at the end of the development period in 2010 and expected to end in 2040.

7Class action lawsuit settlement deferral represents amounts paid towards the settlement of a class action lawsuit related to late payment penalties. Pursuant to an OEB decision in February 2008, these amounts will be recovered from customers over a five-year period commencing in 2008. In the absence of rate regulation these costs would be expensed as incurred.

8Shared savings mechanism (SSM) deferral represents the benefit derived by EGD as a result of its energy efficiency programs. EGD has historically been granted OEB approval to recover the SSM amount through rates after a detailed review by the OEB. The process of review and subsequent recovery may extend over a few years. In the absence of rate regulation, the amount would be included in earnings in the year of approval.

9Ontario hearing costs are incurred by EGD for the rate hearing process. EGD has historically been granted OEB approval for recovery of such hearing costs, generally within two years. In the absence of rate regulation these costs would be expensed as incurred.

10The deferred transportation revenue adjustment is the cumulative difference between actual expenses of Alliance Pipeline US and estimated expenses included in transportation rates. The deferred transportation revenue adjustment is recoverable, typically in the following year, under the long-term transportation agreements and is not included in the rate base.

11Unaccounted for gas variance represents the difference between the total gas distributed by EGD and the amount of gas billed or billable to ratepayers, to the extent it is different from the approved gas variance. EGD has deferred unaccounted for gas variance and has historically been granted approval for recovery or required refund of this amount in the subsequent year. In the absence of rate regulation this variance would be included in Commodity Costs.

12Future removal and site restoration reserves results from the adoption of a revised accounting standard in 2009 (Note 3). With the approval of the regulators, certain of the Company’s businesses collect amounts from customers to fund future costs for removal and site restoration relating to property, plant and equipment and are collected as part of depreciation charged on property, plant and equipment. The balance represents the net amount that EGD has collected from customers, net of actual costs expended on removal and site restoration as at December 31, 2009. In the absence of rate regulation, this balance would not be recorded as amounts would not have been collected from customers.

13Purchased gas variance is the difference between the actual cost and the approved cost of gas reflected in rates. EGD has been granted approval to refund this balance to customers in the following year. In the absence of rate regulation the actual cost of gas would be included in commodity costs and commodity sales would be adjusted by the purchased gas variance.

14This pension plan and OPEB account results from the adoption of a revised accounting standard in 2009 (Note 3). EGD continues to record and recover pension plan contributions and OPEB expenditures through rates on a cash basis. However, as a result of the revised accounting standard, a net asset was recorded representing the amount of pension and OPEB benefits calculated on an accrual basis, with an offsetting net regulatory liability. The settlement period is not determinable. In the absence of rate regulation, there would be no regulatory offset to the net asset.

15Earnings sharing deferral represents amounts relating to the earnings sharing mechanism, which forms part of the IR Settlement. The earnings sharing is payable to ratepayers and represents 50% of earnings excluding the effects of weather, represented by the ROE in excess of 100 basis points above the notional allowed utility ROE. The December 31, 2009 balance relates to the years ended December 31, 2009 and 2008. There would be no change in the treatment of this item in the absence of rate regulation.

16Transactional services deferral represents the ratepayer portion of excess earnings generated from optimization of storage and pipeline capacity. EGD has historically been required to refund the amount to ratepayers in the following year. There would be no change in the treatment of this item in the absence of rate regulation.

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OTHER ITEMS AFFECTED BY RATE REGULATION

Future Income Taxes

On January 1, 2009, the Company adopted a change in accounting standard that impacted the recognition of future income taxes as it relates to rate regulated activities. Effective January 1, 2009, future income tax balances arising primarily from property, plant and equipment are recognized, along with offsetting regulatory assets or liabilities to the extent such balances are expected to be included in future rates. Previously, neither the future income tax balance nor the associated regulatory asset or liability would have been recognized.

At December 31, 2008, in the absence of rate regulation, a future income tax liability of $533 million associated primarily with property, plant and equipment would have been recognized.

At December 31, 2008 the Company had recorded net future income tax liabilities of $68 million related to certain regulatory asset and liability deferral accounts identified above. Accumulated future income tax liabilities of $55 million related to the remaining regulatory deferral accounts have not been recognized at December 31, 2008. In the absence of rate regulation, regulatory deferrals would not be recorded nor would the associated future income tax liabilities. As a result of these tax impacts, earnings for the year ended December 31, 2008 would have decreased by $15 million (2007 - increased by $62 million).

Allowance for Funds Used During Construction and Other Capitalized Costs

Under the pool method prescribed by certain 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 certain 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, 2009, costs relating to this consulting contract of $112 million (2008 - $94 million) were included in property, plant and equipment, and are being depreciated over the average service life of 25 years. In the absence of rate regulation, these costs would be charged to current earnings.

Pension Plans

Prior to January 1, 2009 had pension costs and obligations been recognized at EGD, the net pension asset would have increased by $157 million at December 31, 2008 and earnings would have increased by $3million for the year ended December 31, 2008 (2007 - decreased by $1 million) (Note 3).

Post-Employment Benefits Other than Pensions

Prior to January 1, 2009 had the cost of OPEB been accrued at EGD, the net OPEB liability would have increased by $75 million as at December 31, 2008 and earnings would have decreased by $6 million for the year ended December 31, 2008 (2007 - $6 million) (Note 3).

6.GAIN ON SALE OF INVESTMENTS

(millions of Canadian dollars)
December 31,	2009	2008	2007
NetThruPut (NTP)	29	-	-
Oleoducto Central S.A. (OCENSA)	336	-	-
Compañía Logística de Hidrocarburos CLH, S.A. (CLH)	-	695	-
Other	-	5	-
	365	700	-

NTP

On May 1, 2009, the Company sold its investment in NTP, an internet-based exchange facility for physical crude oil products, for proceeds of $32 million. Earnings generated by the NTP investment for the year ended December 31, 2009 were $1 million (2008 - $1 million) and are included in the Corporate operating

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segment.

OCENSA

On March 17, 2009, the Company sold its investment in OCENSA, a crude oil pipeline in Colombia, for proceeds of $512 million (US$402 million). Earnings and cash flows from operating activities generated by this investment for the year ended December 31, 2009 were $7 million (2008 - $33 million). Earnings from the OCENSA investment are included in the Natural Gas Delivery and Services operating segment. As a result of the sale of OCENSA, the Company reclassified $20 million of after-tax gains on unrealized cash flow hedges from OCI to earnings in the year ended December 31, 2009.

CLH

On June 17, 2008, the Company sold its 25% investment in CLH for total proceeds of $1,380 million (€876 million), net of transaction costs. The sale of CLH resulted in a gain of $695 million. Earnings generated by the CLH investment for the year ended December 31, 2008 were $25 million (2007 - $66 million), and are included in the Natural Gas Delivery and Services operating segment. Operating cash flows generated by the CLH investment for the year ended December 31, 2008 were $12 million (2007 - $58 million).

7.ACCOUNTS RECEIVABLE AND OTHER

(millions of Canadian dollars)
December 31,	2009	2008
Unbilled revenues	1,018	751
Trade receivables	607	907
Regulatory assets	181	138
Taxes receivable	94	133
Short-term portion of derivative assets (Note 23)	128	72
Due from affiliates (Note 30)	336	19
Prepaid expenses and deposits	27	28
Dividends receivable	14	13
GST receivable	-	75
Other	79	186
	2,484	2,322

8.INVENTORY

(millions of Canadian dollars)
December 31,	2009	2008
Natural gas	492	674
Other commodities	292	171
	784	845

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9.PROPERTY, PLANT AND EQUIPMENT

(millions of Canadian dollars)	Weighted
	Average		Accumulated
December 31, 2009	Depreciation Rate	Cost	Depreciation	Net
Liquids Pipelines
Pipeline	2.4%	4,053	1,481	2,572
Pumping equipment, buildings, tanks and other	3.5%	4,029	1,065	2,964
Land and right-of-way	2.0%	118	23	95
Under construction	-	4,129	-	4,129
		12,329	2,569	9,760
Natural Gas Delivery and Services
Pipeline	3.5%	1,971	570	1,401
Regulating, metering and other equipment	4.0%	1,204	280	924
Gas mains and services	3.4%	5,133	854	4,279
Storage	2.8%	241	43	198
Computer technology	20.6%	20	3	17
Land and right-of-way	4.1%	103	27	76
Under construction	-	341	-	341
		9,013	1,777	7,236
Sponsored Investments
Pipeline	4.6%	1,406	368	1,038
Other	6.9%	139	18	121
		1,545	386	1,159
Corporate
Wind turbines and other	4.5%	631	35	596
Land and right-of-way	4.0%	2	-	2
Under construction	-	97	-	97
		730	35	695
		23,617	4,767	18,850

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(millions of Canadian dollars)	Weighted Average		Accumulated
December 31, 2008	Depreciation Rate	Cost	Depreciation	Net
Liquids Pipelines
Pipeline	2.4%	3,162	1,360	1,802
Pumping equipment, buildings, tanks and other	3.7%	2,958	986	1,972
Land and right-of-way	2.5%	70	20	50
Under construction	-	3,857	-	3,857
		10,047	2,366	7,681
Natural Gas Delivery and Services
Pipeline	3.6%	2,169	589	1,580
Regulating, metering and other equipment	4.4%	1,226	307	919
Gas mains and services	3.7%	5,074	1,401	3,673
Storage	2.7%	239	61	178
Computer technology	19.0%	22	3	19
Land and right-of-way	2.8%	49	11	38
Under construction	-	360	-	360
		9,139	2,372	6,767
Sponsored Investments
Pipeline	4.4%	1,363	277	1,086
Other	8.1%	112	4	108
		1,475	281	1,194
Corporate
Wind turbines and other	4.9%	508	17	491
Land and right-of-way	4.0%	2	-	2
Under construction	-	22	-	22
		532	17	515
		21,193	5,036	16,157

10.  JOINT VENTURES

The impact of the Company’s joint venture interests on net assets, earnings, cash flows and financial position is summarized below.

(millions of Canadian dollars)	Ownership	Net Assets
December 31,	Interest	2009	2008
Liquids Pipelines
Olympic Pipelines	65%	111	125
Chicap Pipeline	43.8%	9	9
Other	30%-50%	55	59
Natural Gas Delivery and Services
Alliance Pipeline US	50%	383	453
Vector Pipeline	60%	420	486
Enbridge Offshore Pipelines - various joint ventures	22%-75%	385	521
Aux Sable	42.7%	153	174
Other	42.7%-70%	32	45
Sponsored Investments
Alliance Pipeline Canada	50%	676	688
Other	33%-50%	46	48
		2,270	2,608

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The following table summarizes the impact of proportionately consolidating the joint ventures to the consolidated financial statements of the Company.

(millions of Canadian dollars)
Year ended December 31,	2009		2008		2007
Earnings
Revenues	781		891		844
Commodity costs	(74	)	(174	)	(133	)
Operating and administrative	(226	)	(235	)	(208	)
Depreciation and amortization	(171	)	(173	)	(153	)
Interest expense	(99	)	(97	)	(106	)
Other investment income	10		13		7
Proportionate share of earnings	221		225		251
Cash Flows
Cash provided by operating activities	342		408		312
Cash used in investing activities	(49	)	(61	)	(132	)
Cash used in financing activities	(296	)	(351	)	(184	)
Proportionate share of decrease in cash and cash equivalents	(3	)	(4	)	(4	)

(millions of Canadian dollars)
December 31,	2009		2008
Financial Position
Current assets	173		179
Property, plant and equipment, net	2,769		3,221
Deferred amounts and other assets	696		735
Current liabilities	(212	)	(177	)
Non-recourse long-term debt	(1,109	)	(1,309	)
Other long-term liabilities	(47	)	(41	)
Proportionate share of net assets	2,270		2,608

During the year ended December 31, 2009, the Company purchased the additional 50% interest in Starfish Pipeline Company, LLC, increasing its ownership percentage to 100.0%. As the Company established control over the entity effective December 31, 2009, it has consolidated its interest in Starfish Pipeline Company, LLC from that date forward. Prior to December 31, 2009, the entity was classified as a joint venture.

During the year ended December 31, 2008, the Company purchased an additional equity interest in Chicap Pipeline, increasing its ownership percentage to 43.8%. As the Company established joint control over the entity effective October 31, 2008, it has proportionally consolidated its interest in Chicap Pipeline from that date forward. Prior to October 31, 2008, the entity was classified as a long-term investment.

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11.LONG-TERM INVESTMENTS

(millions of Canadian dollars)	Ownership
December 31,	Interest	2009	2008
Equity Investments
Sponsored Investments
The Partnership	27.0%	1,697	2,014
Enbridge Energy, L.P. - Series AC	66.7%	357	-
Natural Gas Delivery and Services
Noverco Inc. Common Shares	32.1%	14	11
Corporate
Other	10%-33%	9	9
Other Investments
Natural Gas Delivery and Services
Noverco Inc. Preferred Shares		181	181
Fuel Cell Energy Ltd.		25	25
OCENSA		-	223
Corporate
Value Creation Inc.		29	29
		2,312	2,492

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 $126 million at December 31, 2009 (2008 - $130 million). The excess is attributable to the value of property, plant and equipment within the investees based on estimated fair values at the purchase date and is amortized over the economic life of the assets. During 2009 dividends from equity investments exceeded equity investment earnings by $75 million; whereas during 2008, equity investment earnings exceeded dividends in the year by $10 million.

THE PARTNERSHIP

The Partnership includes the Company’s investments in EEP and Enbridge Energy Management, L.L.C. (EEM). The Company has a combined 27.0% ownership in EEP, through a 2.0% general partner interest, a 19.4% interest in Class A units, a 3.3% interest in Class B units and a 2.3% interest in EEP as a result of a 17.2% investment in EEM, which owns 12.6% of EEP through its 100% interest in EEP’s i-units. The Company recorded investment income from EEP of $175 million for the year ended December 31, 2009 (2008 - $162 million including dilution gains; 2007 - $130 million including dilution gains).

Although 82.8% of EEM is widely held, the Company has voting control and therefore consolidates its investment in EEM, including its investment in EEP of $615 million (2008 - $691 million). Net of non-controlling interests in EEM, the book value of the Company’s investment in EEP is $1,544 million (2008 - $1,441 million.)

In October 2009, the Company converted its investment in EEP Class C units into Class A common units. The Class C units converted on a one-for-one basis, resulting in the issuance and receipt of 21,333,273 Class A common units. Prior to the unit conversion, distributions were paid in additional Class C units where Class C units were valued at the market value of Class A units.

In March 2008, EEP issued Class A units and, because Enbridge did not fully participate in this issuance, a dilution gain of $5 million was recognized and Enbridge’s ownership interest in EEP decreased from 15.1% to 14.6%. In November 2008, the Company subscribed for 16.3 million Class A common units of EEP for US$510 million increasing its ownership interest from 14.6% to 27.0%.

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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 interests of $12 million were recognized and Enbridge’s ownership interest in the Partnership decreased from 16.6% to 15.1%.

ENBRIDGE ENERGY, L.P.

The Company has a 66.7% interest in the series AC units of EELP, which is constructing the United States segment of the Alberta Clipper project (Note 30).

NOVERCO

The Company owns a preferred share investment in Noverco Inc. (Noverco) of $181 million at December 31, 2009 (2008 - $181 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 Company also owns an equity investment in the common shares of Noverco of $14 million at December 31, 2009 (2008 - $11 million). Noverco owns an approximate 9.2% (2008 - 9.3%) reciprocal shareholding in the shares of the Company. As a result, the Company has an indirect pro-rata interest of 2.9% (2008 - 3.0%) in its own shares. Both the equity investment in Noverco and shareholders’ equity have been reduced by the reciprocal shareholding of $154 million at December 31, 2009 (2008 - $154 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 2009, the Company recorded equity investment earnings of $10 million (2008 - $4 million; 2007 - $9 million) related to its interest in Noverco.

OCENSA

On March 17, 2009 the Company sold its investment in OCENSA (Note 6).

CORPORATE

The Company reviews the carrying value of its long-term investments on a regular basis as events or changes in circumstances warrant. During 2008, one of the Company’s equity investments, N-Solv, a developer of in-situ oil sands extraction technology, failed a key milestone when its planned demonstration pilot plant was terminated. A writedown of $7 million was recognized in the year ended December 31, 2008 to adjust the carrying value of this investment to its fair value of $7 million.

12.DEFERRED AMOUNTS AND OTHER ASSETS

(millions of Canadian dollars)
December 31,	2009	2008
Regulatory assets	1,419	510
Long-term portion of derivative assets (Note 23)	485	317
Pension asset (Note 27)	216	70
Affiliate long-term note receivable (Note 30)	-	159
Contractual receivables	171	159
Other	134	103
	2,425	1,318

At December 31, 2009, deferred amounts of $71million (2008 - $48 million) were subject to amortization and are presented net of accumulated amortization of $34million (2008 - $26 million). Amortization expense in 2009 was $7million (2008 - $5 million; 2007 - $4 million).

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13.INTANGIBLE ASSETS

(millions of Canadian dollars)	Weighted Average		Accumulated
December 31, 2009	Amortization Rate	Cost	Amortization	Net
Software	17.1%	448	159	289
Transportation agreements	4.2%	232	56	176
Power Purchase Agreements	4.0%	18	1	17
Customer lists	7.1%	9	3	6
		707	219	488

(millions of Canadian dollars)	Weighted Average		Accumulated
December 31, 2008	Amortization Rate	Cost	Amortization	Net
Software	17.6%	536	303	233
Transportation agreements	4.2%	252	50	202
Power Purchase Agreements	4.0%	16	-	16
Customer lists	7.1%	10	3	7
		814	356	458

Total amortization expense for intangible assets was $44 million for the year ended December 31, 2009 (2008 - $58 million; 2007 - $43 million). The Company expects aggregate amortization expense for the years ending December 31, 2010 through 2014 of $58 million, $49 million, $42 million, $36 million and $30 million, respectively.

14.GOODWILL

(millions of Canadian dollars)	Liquids Pipelines	Natural Gas Delivery and Services	Sponsored Investments	Corporate	Consolidated
Balance at December 31, 2007	18	49	308	13	388
Goodwill impairment	-	-	-	(13)	(13)
Foreign exchange and other	4	10	-	-	14
Balance at December 31, 2008	22	59	308	-	389
Goodwill impairment	-	(7)	-	-	(7)
Foreign exchange and other	(3)	(7)	-	-	(10)
Balance at December 31, 2009	19	45	308	-	372

In the fourth quarter of 2009, the Company recognized an impairment of $7 million on goodwill related to Enbridge Electric Connections Inc. within the Natural Gas Delivery and Services segment.

In the fourth quarter of 2008, the Company concluded the goodwill related to Ontario Wind Power, within the Corporate operating segment, was impaired. Accordingly an impairment loss of $13 million was recorded.

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15.ACCOUNTS PAYABLE AND OTHER

(millions of Canadian dollars)
December 31,	2009	2008
Operating accrued liabilities	1,313	963
Trade payables	415	548
Construction payables	163	273
Current derivative liabilities (Note 23)	123	50
Contractor holdbacks	108	68
Taxes payable	103	273
Security deposits	60	123
Other	178	113
	2,463	2,411

16.DEBT

(millions of Canadian dollars)	Weighted Average
December 31,	Interest Rate	Maturity	2009	2008
Liquids Pipelines
Debentures	8.20%	2024	200	200
Medium-term notes	5.48%	2012-2039	1,525	1,125
Southern Lights project financing1	2.05%	2014	1,531	1,359
Commercial paper and credit facility draws, net			874	525
Other2			15	15
Natural Gas Delivery and Services
Debentures	11.04%	2010-2024	385	485
Medium-term notes	5.77%	2014-2036	1,795	1,795
Commercial paper and credit facility draws, net			512	883
Corporate
U.S. dollar term notes3	5.48%	2014-2017	1,151	1,680
Medium-term notes	5.47%	2010-2039	2,568	1,568
Commercial paper and credit facility draws, net4			2,235	2,034
Deferred debt issue costs and other			(101)	(106)
Total Debt			12,690	11,563
Current Maturities			(601)	(534)
Short-Term Borrowings	0.26%		(508)	(874)
Long-Term Debt			11,581	10,155

12009 - $385 million and US$1,095 million (2008 - $318 million and US$850 million).

2Primarily capital lease obligations.

32009 - US$1,100 million (2008 - US$1,372 million).

42009 - $1,973 million and US$250 million (2008 - $1,189 million and US$690 million).

Debenture and term note maturities for the years ending December 31, 2010 through 2014 are $600 million, $150 million, $250 million, $200 million and $819 million, respectively. The Company’s debentures and term notes bear interest at fixed rates and the interest obligations for the years ending December 31, 2010 through 2014 are $445 million, $407 million, $399 million, $383 million and $360 million, respectively.

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INTEREST EXPENSE

(millions of Canadian dollars)

Year ended December 31,	2009	2008	2007
Debentures and term notes	484	404	418
Non-recourse long-term debt	93	100	102
Commercial paper and credit facility draws	71	100	91
Southern Lights project financing	45	28	-
Capitalized	(96)	(81)	(61)
	597	551	550

CREDIT FACILITIES

(millions of Canadian dollars) December 31, 2009	Expiry Dates	Total Facilities	Credit Facility Draws2	Available
Liquids Pipelines	2011	1,300	876	424
Natural Gas Delivery and Services	2010-2011	813	512	301
Corporate	2011-2013	3,898	2,255	1,643
		6,011	3,643	2,368
Southern Lights project financing1	2014	1,796	1,531	265
Total Credit Facilities		7,807	5,174	2,633

1Total facilities inclusive of $186 million which is available if certain conditions related to the project are met.

2Includes facility draws and commercial paper issuances, net of discount, that are back-stopped by the credit facility.

Credit facilities carry a weighted average standby fee of 0.39% per annum on the unused portion and draws 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 2010 to 2014.

Commercial paper and credit facility draws, net of short-term borrowings, of $3,113million (2008 - $2,567 million) are supported by the availability of long-term committed credit facilities and therefore have been classified as long-term debt.

17.NON-RECOURSE DEBT

(millions of Canadian dollars)December 31,	Weighted Average Interest Rate	Maturity	2009	2008
Natural Gas Delivery and Services
Long-term credit facilities1		2012	1	1
Senior notes2	6.77%	2015-2025	400	507
Term debt3	3.09%	2010-2019	24	27
Capital lease obligations	10.45%	2020	37	53
Sponsored Investments
Credit facilities		2011-2012	222	174
Medium-term notes	5.25%	2014	90	190
Senior notes	6.63%	2015-2025	708	679
Fair value increment on senior notes acquired			33	38
Deferred debt issue costs and other			(9)	(10)
Total Non-Recourse Debt			1,506	1,659
Current Maturities			(113)	(185)
Non-Recourse Long-Term Debt			1,393	1,474

12009 - US$1 million (2008 - US$1 million).

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22009 - US$382 million (2008 - US$414 million).

32009 - US$23 million (2008 - US$22 million).

Maturities on non-recourse borrowings for the years ending December 31, 2010 through 2014 are $113 million, $71 million, $77 million, $81 million and $81 million, respectively. The medium-term notes and senior notes bear interest at fixed rates. Interest obligations on non-recourse borrowings for the years ending December 31, 2010 through 2014 are $82 million, $78 million, $72 million, $67 million and $61 million, respectively.

Certain assets of Alliance Pipeline Canada, with a carrying value of $1,055 million, 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, with a carrying value of $806 million, are pledged as collateral to Alliance Pipeline US’s lenders and to the lenders to Alliance Pipeline Canada.

18.OTHER LONG-TERM LIABILITIES

(millions of Canadian dollars)
December 31,	2009	2008
Future removal and site restoration reserves (Note 5)	710	-
Regulatory liabilities	138	-
Other post-employment benefit liabilities (Note 27)	110	22
Derivative liabilities (Note 23)	42	47
Other	207	190
	1,207	259

19.NON-CONTROLLING INTERESTS

(millions of Canadian dollars)
December 31,	2009	2008
EEM	424	481
EIF	134	147
EGD Preferred Shares	100	100
EGNB	54	57
Other	15	12
	727	797

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

The Company owns 100% of the outstanding common shares of EGD; however, the four million Cumulative Redeemable EGD Preferred Shares held by third parties are entitled to a claim on the assets of EGD prior to the common shareholder. The fixed yield rate on these preferred shares was 4.93% per annum until July 1, 2009, after which floating adjustable cumulative cash dividends are payable at 80% of the prime rate. The preferred shares have no fixed maturity date. EGD may, at its option, redeem all or a portion of the outstanding shares for $25 per share plus all accrued and unpaid dividends to the redemption date. As at December 31, 2009, no preferred shares have been redeemed.

Non-controlling interests in EIF represents 58.1% of voting units that are held by public unitholders. Non-controlling interests in EGNB represents 27.5% of the limited partnership units held by third parties.

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20.  SHARE CAPITAL

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

COMMON SHARES

(millions of Canadian dollars, number of common shares in millions)

December 31,	2009		2008		2007
	Number of Shares	Amount	Number of Shares	Amount	Number of Shares	Amount
Balance at beginning of year	373	3,194	369	3,027	352	2,416
Common shares issued	-	4	-	-	15	567
Shares issued on exercise of stock options	1	38	1	36	1	26
Dividend Reinvestment and Share Purchase Plan	4	143	3	131	1	18
Balance at end of year	378	3,379	373	3,194	369	3,027

PREFERRED SHARES

The five 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 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 million (2008 - 11 million), 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 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,	2009	2008	2007
Weighted average shares outstanding	364	360	355
Effect of dilutive options	2	3	3
Diluted weighted average shares outstanding	366	363	358

For the year ended December 31, 2009, 556,500 anti-dilutive stock options (2008 - 2,879,800; 2007 - 1,158,200) with a weighted average exercise price of $40.98 (2008 - $40.53; 2007 - $38.26) 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. Participants in the Company’s Dividend Reinvestment and Share Purchase Plan receive a 2% discount on the purchase of common shares with reinvested dividends.

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

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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.

21.STOCK OPTION AND STOCK UNIT PLANS

The Company maintains four long term incentive compensation plans: the Incentive Stock Option (ISO) Plan, the 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 17.5 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, of which none have been issued to date. 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, 2009 for ISOs is $17 million (2008 - $13 million; 2007 - $9 million).

Outstanding Incentive Stock Options

(options in thousands; exercise price in Canadian dollars)

December 31,	2009		2008		2007
	Number	Weighted Average Exercise Price	Number	Weighted Average Exercise Price	Number	Weighted Average Exercise Price
Options at beginning of year	10,650	31.05	9,237	27.24	9,186	24.97
Options granted	3,028	39.62	2,642	40.54	1,158	38.26
Options exercised	(1,187)	22.01	(1,178)	21.85	(1,046)	19.21
Options cancelled or expired	(25)	40.65	(51)	36.83	(61)	32.97
Options at end of year	12,466	34.01	10,650	31.05	9,237	27.24
Options vested	6,550	28.96	6,087	25.32	5,865	22.87

The total intrinsic value of ISOs exercised during the year ended December 31, 2009 was $22 million (2008 - $23 million; 2007 - $19 million) and cash received on exercise was $26 million (2008 - $26 million; 2007 - $20 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, 2009 was $81 million (2008 - $109 million) and $76 million (2008 - $97 million), respectively.

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Incentive Stock Option Characteristics

(options in thousands; exercise price in Canadian dollars)

December 31, 2009	Options Outstanding			Options Vested
Exercise Price Range	Number	Weighted Average Remaining Life (years)	Weighted Average Exercise Price	Number	Weighted Average Remaining Life (years)	Weighted Average Exercise Price
10.00-14.99	111	0.3	13.09	111	0.3	13.09
15.00-19.99	486	1.2	19.06	486	1.2	19.06
20.00-24.99	1,682	2.6	21.29	1,682	2.6	21.29
25.00-29.99	1,025	4.0	25.72	1,025	4.0	25.72
30.00-34.99	1,727	6.6	32.33	1,089	5.1	31.77
35.00-39.99	4,836	7.8	38.43	1,523	6.4	37.10
40.00-44.99	2,599	8.1	40.86	634	8.1	40.87
	12,466	6.4	34.01	6,550	4.5	28.96

The total fair value of options vested under the ISO Plan during the year ended December 31, 2009 was $13 million (2008 - $9 million).

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,	2009	2008	2007
Fair value per option (Canadian dollars)1	7.12	6.14	6.16
Valuation assumptions
Expected option term (years)2	6	6	6
Expected volatility3	28.08%	18.48%	18.10%
Expected dividend yield4	3.87%	3.34%	3.22%
Risk-free interest rate5	2.24%	3.50%	4.11%

1Beginning in 2008, options granted to United States employees are based on New York Stock Exchange (NYSE) prices. The option value and assumptions shown for 2009 are based on a weighted average of the United States options and the Canadian options. The fair values per option were $6.73 for Canadian employees and US$6.86 for United States employees.

2The expected option term is based on historical exercise practice.

3Expected volatility is determined with reference to historic daily share price volatility.

4The expected dividend yield is the current annual dividend at the grant date divided by the current stock price.

5The risk-free interest rate is based on the Government of Canada’s Canadian Bond Yields and the U.S. Treasury Bond Yields.

As of December 31, 2009, unrecognized compensation cost related to non-vested share-based compensation arrangements granted under the ISO plan was $14 million. The cost is expected to be fully recognized by December 31, 2012.

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, August 15, 2007 and February 19, 2008. The 2008 PBSO grant is included in the 2007 PBSO plan. 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 and 2008 PBSO grants’ 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 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, 2009 for PBSOs was $2 million (2008 - $2 million; 2007 - $1 million).

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Outstanding Performance Based Stock Options

(options in thousands; exercise price in Canadian dollars)

December 31,	2009		2008		2007
	Number	Weighted Average Exercise Price	Number	Weighted Average Exercise Price	Number	Weighted Average Exercise Price
Options at beginning of year	3,738	32.72	3,588	31.92	1,379	23.15
Options granted	-	-	250	40.42	2,345	36.57
Options exercised	(343)	23.15	(100)	23.15	(136)	23.15
Options at end of year	3,395	33.69	3,738	32.72	3,588	31.92
Options vested	800	23.15	1,143	23.15	1,243	23.15

The total intrinsic value of PBSOs exercised during the year ended December 31, 2009 was $6 million (2008 - $2 million; 2007 - $2 million) and cash received on exercise was $8 million (2008 - $2 million; 2007 - $3 million). The total intrinsic value of PBSOs outstanding and vested at December 31, 2009 is $23 million (2008 - $32 million) and $14 million (2008 - $21 million), respectively.

Performance Based Stock Option Characteristics

(options in thousands; exercise price in Canadian dollars)

December 31, 2009	Options Outstanding			Options Vested
Exercise Price	Number	Weighted Average Remaining Life (years)	Weighted Average Exercise Price	Number	Weighted Average Remaining Life (years)	Weighted Average Exercise Price
23.15	800	0.7	23.15	800	0.7	23.15
36.57	2,345	5.6	36.57	-	-	-
40.42	250	5.6	40.42	-	-	-
	3,395	4.5	33.69	800	0.7	23.15

The total fair value of options vested under the PBSO Plan during the year ended December 31, 2009 was $2 million (2008 - $2 million; 2007 - $2 million).

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

Year ended December 31,	2008	2007
Fair value per option (Canadian dollars)	4.82	3.40
Valuation assumptions
Expected option term (years)1	8	8
Expected volatility2	13.60%	13.60%
Expected dividend yield3	3.32%	3.57%
Risk-free interest rate4	3.75%	4.38%

1Expected option term is based on historical information.

2Expected volatility is determined with reference to 20-day rolling period historic share price information

3The expected dividend yield is the current annual dividend divided by the current stock price.

4The risk-free interest rate is based on the Government of Canada’s Canadian Bond Yields and the United States Treasury Bond Yields.

As of December 31, 2009, unrecognized compensation cost related to non-vested share-based compensation arrangements granted under the PBSO plan was $5 million. The cost is expected to be fully recognized by December 31, 2012.

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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 weighted average share price and by a performance multiplier. The performance multiplier ranges from zero, if the Company’s performance fails to meet threshold performance levels, to a maximum of two, if the Company performs within the highest range of its performance targets. The 2007, 2008 and 2009 grants derive 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, adjusted for non-operating or non-recurring items, relative to targets established at the time of grant.

Compensation expense recorded for the year ended December 31, 2009 for PSUs was $20 million (2008 - $13 million; 2007 - $3 million). To calculate the 2009 expense, multipliers of two, based upon multiplier estimates at December 31, 2009, were used for each of the 2007, 2008 and 2009 PSU grants.

Outstanding Performance Stock Units

December 31,	2009	2008	2007
Units at beginning of year	295,428	267,616	328,716
Units granted	169,600	144,300	137,200
Units cancelled	-	-	(2,384)
Units matured	(151,882)	(129,852)	(209,827)
Dividend reinvestment	17,270	13,364	13,911
Units at end of year	330,416	295,428	267,616

Of the PSUs outstanding at December 31, 2009, 154,518 units have a performance period ending December 31, 2010 and 175,898 have a performance period ending December 31, 2011. The total intrinsic value of PSUs outstanding at December 31, 2009 is $47 million (2008 - $21 million; 2007 - $11 million).

RESTRICTED STOCK UNITS

Enbridge has a RSU plan where cash awards are paid to certain non-executive employees of the Company following a 35 month maturity period. RSU holders receive cash equal to the Company’s weighted average share price multiplied by the units outstanding on the maturity date. Compensation expense recorded for the year ended December 31, 2009 for RSUs was $23 million (2008 - $15 million; 2007 - $7 million).

Outstanding Restricted Stock Units

December 31,	2009	2008	2007
Units at beginning of year	700,034	456,621	183,253
Units granted	543,500	418,700	276,875
Units cancelled	(18,429)	(23,352)	(18,627)
Units matured	(282,656)	(179,940)	-
Dividend reinvestment	45,428	28,005	15,120
Units at end of year	987,877	700,034	456,621

The total intrinsic value of RSUs outstanding at December 31, 2009 is $50 million (2008 - $29 million; 2007 - $18 million).

As of December 31, 2009, unrecognized compensation expense related to non-vested units granted under the PSU and RSU plans was $44 million and is expected to be fully recognized by December 31, 2011.

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

(millions of Canadian dollars)	Net Investment Hedges	Cumulative Translation Adjustment	Equity Investees	Non-Controlling Interests	Cash Flow Hedges	Total
Balance at January 1, 2007	263	(399)	-	-	-	(136)
Adjustment on adoption	-	-	(57)	26	79	48
Tax impact of adjustment on adoption	-	-	20	-	(20)	-
	-	-	(37)	26	59	48
Changes during the year	194	(534)	(29)	92	95	(182)
Tax impact	(19)	-	9	-	(5)	(15)
	175	(534)	(20)	92	90	(197)
Balance at December 31, 2007	438	(933)	(57)	118	149	(285)
Changes during the year	(180)	658	78	(101)	(175)	280
Tax impact	20	-	(29)	-	47	38
	(160)	658	49	(101)	(128)	318
Balance at December 31, 2008	278	(275)	(8)	17	21	33
Changes during the year	181	(815)	(38)	72	71	(529)
Tax impact	(30)	-	14	-	(31)	(47)
	151	(815)	(24)	72	40	(576)
Balance at December 31, 2009	429	(1,090)	(32)	89	61	(543)

23.RISK MANAGEMENT

MARKET PRICE RISK

The Company’s earnings, cash flows and OCI are subject to movements in foreign exchange rates, interest rates and commodity prices (collectively, market price risk). Formal risk management policies, processes and systems have been designed to mitigate these risks.

Earnings at Risk (EaR), a variant of Value at Risk, is the principal risk management metric used to quantify market price risk at Enbridge. EaR is an objective, statistically derived risk metric that measures the maximum adverse change in projected 12-month earnings that could result from market price risk over a one-month period within a 97.5% confidence interval. The Company’s policy is to target a maximum EaR of 5% of earnings. Earnings exposure from market price risk is managed within the overall consolidated EaR limits of the Company. Further, commodity price risk is managed within business unit EaR sub-limits.

The Company calculates EaR using Monte Carlo simulation to produce projections of earnings using a randomly generated series of forecasted market prices and Enbridge’s current market exposures. Historical statistical distributions of market prices and the correlation among those market prices are used to generate an entire probability distribution of possible deviations from forecast earnings.

There is currently no uniform industry methodology for estimating EaR. The use of this metric has limitations because it is based on historical correlations and volatilities in commodity prices and assumes future price movements will follow a statistical distribution. Although losses are not expected to exceed the statistically estimated EaR on 97.5% of occasions, losses on the other 2.5% of occasions could be substantially greater than the estimated EaR.

The following summarizes the types of market price risks to which the Company is exposed and the risk management instruments used to mitigate them.

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Foreign Exchange Risk

The Company’s earnings, cash flows, and OCI are subject to foreign exchange rate variability, primarily arising from its United States dollar denominated subsidiaries. The Company has implemented a policy where it must hedge a minimum level of foreign currency denominated earnings exposures identified over the next five year period. The Company may also hedge anticipated foreign currency denominated purchases or sales, foreign currency denominated debt, as well as certain equity investment balances and net investments in foreign denominated subsidiaries.

The impact of a $0.05 strengthening of the Canadian dollar across the forward curve relative to the United States dollar at December 31, 2009, would have resulted in a $92 million increase (2008 - $58 million) to earnings and a $27 million (2008 - $19 million) increase to OCI. The foreign exchange sensitivity analysis is limited to changes in the fair value of financial instruments, external debt and loans to foreign operations within the Company that are not denominated in the Company’s functional currency and are not considered a net investment. Further, the sensitivity analysis excludes financial instruments that are not monetary items and the impact of the Company’s United States dollar denominated self-sustaining subsidiaries on OCI.

Interest Rate Risk

The Company’s earnings and cash flows are exposed to short term interest rate variability due to the regular repricing of its variable rate debt. Floating to fixed interest rate swaps and options are used to hedge against the effect of future interest rate movements. The Company has implemented a program to significantly mitigate the volatility of short-term interest rates on interest expense through 2013 at an average rate of 2.2%.

The Company’s earnings and cash flows are also exposed to variability in longer term interest rates ahead of anticipated fixed rate debt issuances. Forward starting interest rate swaps are used to hedge against the effect of future interest rate movements. The Company has implemented a hedging program to significantly mitigate its exposure to long term interest rate variability on select forecast term debt issuances through 2013. A total of $2,500 million of future fixed rate term debt issuances have been hedged at an average government bond rate of 4.0%. Further, many of the Company’s existing commercial arrangements and certain construction projects provide for the full recovery of financing costs through tolls.

The Company also monitors its debt portfolio mix of fixed and variable rate debt instruments to ensure that the consolidated portfolio of debt stays within its Board of Directors approved policy limit band of a maximum of 25% floating rate debt as a percentage of total debt outstanding.

A 1% increase across the interest rate yield curve would have caused a $2 million increase (2008 - nil) in earnings and a $197 million increase (2008 - $14 million) in OCI at December 31, 2009 due to the revaluation of interest rate derivatives. If interest rates had been 1% higher during the 12 months ended December 31, 2009, there would have been a $26 million decrease (2008 - $24 million) in earnings due to increased interest expense related to the Company’s floating rate debt assuming that the variable rate debt outstanding at December 31, 2009 had been outstanding for the entire year, partially offset by an increase in earnings due to increased realized fair value gains on settled interest rate hedges of $15 million (2008 - $4 million).

Commodity Price Risk

The Company’s earnings and cash flows are exposed to changes in commodity prices as a result of ownership interest in certain assets, as well as through the activities of its energy services subsidiaries. The Company uses natural gas, power, crude oil and NGL derivative instruments to fix a portion of the variable price exposures that may arise from commodity usage, storage, transportation and supply agreements.

The Company has implemented a hedging program to significantly mitigate the volatility from fractionation spreads (natural gas / NGLs) that impact earnings from its ownership in the Aux Sable natural gas processing plant through 2011.

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The Company has defined EaR limits for different components of businesses exposed to commodity price risk. The calculation of these limits include physical and financial derivatives as well as physical transportation and storage capacity contracts accounted for as executory contracts in the consolidated financial statements. Positions giving rise to commodity price exposure are monitored against these EaR limits daily. For the year ended December 31, 2009, the average EaR was $29 million (2008 - $24 million) and as at December 31, 2009 the Company’s EaR was $22 million (2008 - $16 million).

TOTAL DERIVATIVE INSTRUMENTS

The following tables summarize the balance sheet location and fair value of the Company’s derivative instruments. The Company did not have any outstanding fair value hedges as at December 31, 2009 or December 31, 2008.

(millions of Canadian dollars) December 31, 2009	Derivative Instruments used as Cash Flow Hedges	Derivative Instruments used as Net Investment Hedges	Non- Qualifying Derivative Instruments	Total Derivative Instruments
Accounts receivable and other(Note 7)
U.S. dollar forwards	4	14	52	70
Interest rate contracts	34	-	2	36
Energy commodity	-	-	19	19
Power commodity	-	-	3	3
	38	14	76	128
Deferred amounts and other(Note 12)
U.S. dollar forwards	25	80	285	390
Interest rate contracts	90	-	-	90
Energy commodity	-	-	1	1
Power commodity	1	-	1	2
Other	1	-	1	2
	117	80	288	485
Accounts payable and other(Note 15)
U.S. dollar forwards	(2)	-	(3)	(5)
Interest rate contracts	(68)	-	-	(68)
Energy commodity	(17)	-	(32)	(49)
Power commodity	-	-	(1)	(1)
	(87)	-	(36)	(123)
Other long-term liabilities(Note 18)
U.S. dollar forwards	(21)	-	-	(21)
Interest rate contracts	(15)	-	-	(15)
Energy commodity	(4)	-	-	(4)
Power commodity	-	-	(2)	(2)
	(40)	-	(2)	(42)
Total net derivative asset/(liability)
U.S. dollar forwards	6	94	334	434
Interest rate contracts	41	-	2	43
Energy commodity	(21)	-	(12)	(33)
Power commodity	1	-	1	2
Other	1	-	1	2
	28	94	326	448

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(millions of Canadian dollars) December 31, 2008	Derivative Instruments used as Cash Flow Hedges	Derivative Instruments used as Net Investment Hedges	Non- Qualifying Derivative Instruments	Total Derivative Instruments
Accounts receivable and other(Note 7)
U.S. dollar forwards	12	8	-	20
Interest rate contracts	1	-	-	1
Energy commodity	9	-	32	41
Power commodity	1	-	9	10
	23	8	41	72
Deferred amounts and other(Note 12)
U.S. dollar cross currency swaps	26	-	-	26
U.S. dollar forwards	153	63	56	272
Power commodity	7	-	12	19
	186	63	68	317
Accounts payable and other(Note 15)
U.S. dollar forwards	-	-	(14)	(14)
Interest rate contracts	(9)	-	-	(9)
Energy commodity	(22)	-	(4)	(26)
Power commodity	(1)	-	-	(1)
	(32)	-	(18)	(50)
Other long-term liabilities(Note 18)
U.S. dollar forwards	-	-	(8)	(8)
Interest rate contracts	(22)	-	-	(22)
Power commodity	(11)	-	(1)	(12)
Other	(3)	-	(2)	(5)
	(36)	-	(11)	(47)
Total net derivative asset/(liability)
U.S. dollar cross currency swaps	26	-	-	26
U.S. dollar forwards	165	71	34	270
Interest rate contracts	(30)	-	-	(30)
Energy commodity	(13)	-	28	15
Power commodity	(4)	-	20	16
Other	(3)	-	(2)	(5)
	141	71	80	292

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The following table summarizes the maturity and total notional principal or quantity outstanding related to the Company’s derivative instruments.

	December 31, 2009		December 31, 2008
	Maturity	Notional Principal or Quantity Outstanding	Maturity	Notional Principal or Quantity Outstanding
U.S. dollar cross currency swaps		-	2013-2022	138
(millions of Canadian dollars)
U.S. dollar forwards - purchase	2010-2019	1,078	2009-2017	1,118
(millions of United States dollars)
U.S. dollar forwards - sell	2010-2020	3,102	2009-2021	2,548
(millions of United States dollars)
Interest rate contracts	2010-2029	6,022	2009-2029	1,164
(millions of Canadian dollars)
Energy commodity (bcf)	2010-2011	464	2009-2010	530
Power commodity (MW/H)	2010-2024	38	2009-2024	57

The Company does not have any credit-risk related contingent features associated with its derivative instruments.

The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income

The following table presents the effect of cash flow hedges and net investment hedges on the Company’s consolidated earnings and consolidated comprehensive income.

(millions of Canadian dollars)
Year ended December 31,	2009
Amount of Unrealized Gain/(Loss) Recognized in OCI
Cash Flow Hedges
U.S. dollar cross currency swaps	(13)
U.S. dollar forwards	(103)
Interest rate contracts	73
Energy commodity	(41)
Power commodity	4
Other	3
Net Investment Hedges
U.S. dollar forwards	24
Total unrealized loss recognized in OCI	(53)
Amount of Gain/(Loss) Reclassified from AOCI to Earnings
U.S. dollar cross currency swaps1	19
U.S. dollar forwards1	(23)
Interest rate contracts2	(31)
Energy commodity3	(78)
Power commodity3	(1)
Other	3
Total loss reclassified from AOCI to earnings	(111)

1Gain/(loss) reported within Other Investment Income in the Consolidated Statement of Earnings.

2Loss reported within Interest Expense in the Consolidated Statement of Earnings.

3Loss reported within Commodity costs in the Consolidated Statement of Earnings.

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The Company estimates that $89 million of accumulated other comprehensive loss related to cash flow hedges will be reclassified to earnings in the next 12 months. Actual amounts reclassified to earnings depend on the foreign exchange rates, interest rates and commodity prices when derivative contracts that are currently outstanding mature. For all forecasted transactions, the maximum term over which the Company is hedging exposures to the variability of cash flows is 54 months at December 31, 2009.

During 2008, the Company terminated certain par forward currency exchange instruments for proceeds of $48 million. These instruments hedged US$162 million of the Company’s United States dollar self-sustaining operations and were accounted for as net investment hedges with the fair value recorded as long-term assets on the Statement of Financial Position with an equal and offsetting amount recorded in AOCI. No gain or loss related to the terminations will be recorded in the Company’s earnings until there is a disposal of or a return of capital on a related investment.

Non-Qualifying Derivatives

The following table presents the unrealized gains and losses associated with changes in the fair value of the Company’s non-qualifying derivatives.

(millions of Canadian dollars)
Year ended December 31,	2009	2008	2007
U.S. dollar forwards1	232	35	-
Interest rate contracts2	2	-	-
Energy commodity3	(89)	122	(49)
Power commodity3	1	-	-
Total unrealized derivative fair value gain	146	157	(49)

1Gain reported within Other Investment Income in the Consolidated Statement of Earnings.

2Gain reported within Interest Expense in the Consolidated Statement of Earnings.

3Gain/(loss) reported within Commodity costs in the Consolidated Statement of Earnings.

Additional information regarding the Company’s derivative instruments is included in Note 24, Fair Value of Financial Instruments.

LIQUIDITY RISK

Liquidity risk is the risk that the Company will not be able to meet its financial obligations, including commitments and guarantees (Notes 31 and 32), as they become due. In order to manage this risk, the Company forecasts cash requirements over the near and long term to determine whether sufficient funds will be available. The Company’s primary sources of liquidity and capital resources are funds generated from operations, the issuance of commercial paper and draws under committed credit facilities and longer term debt which includes debentures and medium-term notes. The Company maintains current shelf prospectuses with the securities regulators, which enables, subject to market conditions, ready access to either the Canadian or United States public capital markets. In addition, the Company maintains sufficient liquidity through committed credit facilities (Note 16) with a diversified group of banks and institutions which, if necessary, enables the Company to fund all anticipated requirements for one year without accessing the capital markets. The Company is in compliance with all the terms and conditions of its committed credit facilities and expects to be in compliance throughout 2010. As a result, all credit facilities are available to the Company and the banks are obligated to fund and have been funding the Company under the terms of the facilities. The Company expects to generate sufficient cash from operations and commercial paper issuances and draws under its committed credit facilities to fund liabilities as they become due, finance planned investing activities and pay common share dividends throughout the year. Additional liquidity, if necessary, is expected to be available through access to the capital markets.

Maturities of Financial Instruments

The Company generally has no financial instruments, other than derivative instruments, maturing beyond one year with the exception of its long-term debt (Notes 16 and 17).

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For the years ending December 31, 2010 through 2014, and thereafter, the Company has estimated the following undiscounted cash flows will arise from its derivative instruments based on valuation at the balance sheet date.

(millions of Canadian dollars)	2010	2011	2012	2013	2014	Thereafter
Cash inflows	182	106	136	155	86	51
Cash outflows	(167)	(29)	(5)	(7)	(3)	(25)
Net cash flows	15	77	131	148	83	26

CREDIT RISK

Entering into derivative financial instruments can result in exposure to credit risk. 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 investment grade credit ratings. Credit risk relating to derivative counterparties is mitigated by credit exposure limits and contractual requirements, frequent assessment of counterparty credit ratings and netting arrangements. At December 31, 2009, the Company has a maximum exposure to credit risk of $517 million related to its derivative counterparties.

Credit risk also arises from trade and other long-term receivables, and is mitigated through credit exposure limits and contractual requirements, assessment of credit ratings and netting arrangements. Credit risk in the Natural Gas Delivery 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. The Company actively monitors the financial strength of large industrial customers and, in select cases, has obtained additional security to minimize the risk of default on receivables. Generally, the Company classifies and provides for receivables older than 30 days as past due. The maximum exposure to credit risk related to non-derivative financial assets is their carrying value, as disclosed in Note 24, Fair Value of Financial Instruments.

The change in allowance for doubtful accounts in respect of accounts receivable is detailed below.

(millions of Canadian dollars)
Year ended December 31,	2009	2008
Balance at beginning of year	(69)	(55)
Additional allowance	(29)	(37)
Amounts used	24	23
Balance at end of year	(74)	(69)

The allowance for doubtful accounts is determined based on collection history. When the Company has determined that further collection efforts are unlikely to be successful, amounts charged to the allowance for doubtful accounts are applied against the impaired accounts receivable.

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24.FAIR VALUE OF FINANCIAL INSTRUMENTS

The following table summarizes the Company’s financial instrument carrying and fair values and provides a reconciliation to the Consolidated Statements of Financial Position.

	December 31, 2009
(millions of Canadian dollars)	Held for Trading	Available for Sale	Loans and Receivables	Held to Maturity	Other Financial Liabilities	Qualifying Derivatives	Non- Financial Instruments	Total	Fair Value1
Assets
Cash and cash equivalents	327	-	-	-	-	-	-	327	327
Accounts receivable and other	76	-	2,054	-	-	52	302	2,484	2,182
Long-term investments	-	54	6	181	-	-	2,071	2,312	187
Deferred amounts and other assets	288	-	-	-	-	197	1,940	2,425	485
Liabilities
Short-term borrowings	-	-	-	-	508	-	-	508	508
Accounts payable and other	36	-	-	-	2,177	87	163	2,463	2,300
Interest payable	-	-	-	-	104	-	-	104	104
Long-term debt	-	-	-	-	12,283	-	(101)	12,182	13,450
Non-recourse long-term debt	-	-	-	-	1,515	-	(9)	1,506	1,573
Other long-term liabilities	2	-	-	-	-	40	1,165	1,207	42

	December 31, 2008
(millions of Canadian dollars)	Held for Trading	Available for Sale	Loans and Receivables	Held to Maturity	Other Financial Liabilities	Qualifying Derivatives	Non- Financial Instruments	Total	Fair Value1
Assets
Cash and cash equivalents	542	-	-	-	-	-	-	542	542
Accounts receivable and other	41	-	1,869	-	-	31	381	2,322	1,948
Long-term investments	-	54	167	405	-	-	1,866	2,492	492
Deferred amounts and other assets	68	-	-	-	-	249	1,001	1,318	317
Liabilities
Short-term borrowings	-	-	-	-	874	-	-	874	874
Accounts payable and other	18	-	-	-	1,965	32	396	2,411	2,015
Interest payable	-	-	-	-	102	-	-	102	102
Long-term debt	-	-	-	-	10,795	-	(106)	10,689	11,173
Non-recourse long-term debt	-	-	-	-	1,669	-	(10)	1,659	1,672
Other long-term liabilities	11	-	-	-	-	36	212	259	47

1Fair value does not include non-financial instruments, which includes investments accounted for under the equity method, and available for sale equity instruments held at cost that do not trade on an actively quoted market.

The fair value of 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. When such values are not available, the Company uses discounted cash flow analysis from applicable yield curves based on observable market inputs to estimate fair value. 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 fair value of cash and cash equivalents and short-term borrowings approximates their carrying value due to their short-term maturities. The fair value of the Company’s long-term investments, other than those classified as available for sale, approximates their carrying value due to interest terms which approximate floating market rates. The fair value of the Company’s long-term debt and non-recourse long-term debt is based on quoted market prices for instruments of similar yield, credit risk and tenure. The fair value of other financial assets and liabilities other than derivative instruments approximate their cost due to the short period to maturity. Changes in the fair value of financial liabilities other than derivative instruments are due primarily to fluctuations in interest rates and time value.

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FAIR VALUE OF DERIVATIVES

The Company categorizes its derivative assets and liabilities measured at fair value into one of three different levels depending on the observability of the inputs employed in the measurement.

Level 1

Level 1 includes assets and liabilities measured at fair value based on unadjusted quoted prices for identical assets and liabilities in active markets that are accessible at the measurement date. An active market for an asset or liability is considered to be a market where transactions occur with sufficient frequency and volume to provide pricing information on an ongoing basis. The Company’s Level 1 instruments consist primarily of exchange-traded derivative instruments used to mitigate the risk of crude oil price fluctuations in its Liquids Pipelines segment and commodity marketing businesses.

Level 2

Level 2 includes valuations determined using directly or indirectly observable inputs other than quoted prices included within Level 1. Derivative instruments in this category are valued using models or other industry standard valuation techniques derived from observable market data. Such valuation techniques include inputs such as quoted forward prices, time value, volatility factors and broker quotes that can be observed or corroborated in the market for the entire duration of the derivative instrument. Instruments valued using Level 2 inputs include non-exchange traded derivatives such as over the counter foreign exchange forward and cross currency swap contracts, interest rate swaps, physical forward commodity contracts as well as commodity swaps and options for which observable inputs can be obtained. These instruments are used primarily in the Company’s commodity marketing businesses and the Corporate segment.

Level 3

Level 3 includes valuations based on inputs which are less observable, unavailable or where the observable data does not support a significant portion of the instruments’ fair value. Generally, Level 3 valuations are longer dated transactions, occur in less active markets, occur at locations where pricing information is not available or have no binding broker quote to support Level 2 classification. The Company has developed methodologies, benchmarked against industry standards, to determine fair value for these contracts based on extrapolation of observable future prices and rates. Instruments valued using Level 3 inputs include long dated derivative power, NGL and natural gas contracts in its Liquids Pipelines segment and commodity marketing businesses.

When possible the estimated fair value is based on quoted market prices and, if not available, estimates from third party brokers. For non-exchange traded derivatives classified in Levels 2 and 3, the Company uses standard valuation techniques to calculate fair value. These methods include discounted cash flows for forwards and swaps and Black-Scholes pricing models for options. Depending on the type of derivative and nature of the underlying risk, primary inputs to these techniques include observable market prices (interest, foreign exchange and commodity) and volatility. The Company uses inputs and data used by willing market participants when valuing derivatives and considers its own credit default swap spread as well as those of its counterparties in its determination of fair value. Where possible the Company uses observable inputs.

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The Company has categorized its derivative assets and liabilities measured at fair value as follows:

	December 31, 2009
(millions of Canadian dollars)	Level 1	Level 2	Level 3	Total
Financial assets:
Current derivative assets	2	84	42	128
Long-term derivative assets	-	481	4	485
Financial liabilities:
Current derivative liabilities	(2)	(68)	(53)	(123)
Long-term derivative liabilities	-	(39)	(3)	(42)
Total net derivative asset/(liability)	-	458	(10)	448

1Excludes cash and cash equivalents.

	December 31, 2008
(millions of Canadian dollars)	Level 1	Level 2	Level 3	Total
Financial assets:
Current derivative assets	10	9	53	72
Long-term derivative assets	-	301	16	317
Financial liabilities:
Current derivative liabilities	-	(44)	(6)	(50)
Long-term derivative liabilities	-	(37)	(10)	(47)
Total net derivative asset	10	229	53	292

1Excludes cash and cash equivalents.

Changes in net fair value of derivative assets and liabilities classified as Level 3 in the fair value hierarchy were as follows:

(millions of Canadian dollars)
Year ended December 31,	2009	2008
Level 3 net derivative asset at beginning of year	53	(37)
Total gains/(losses), realized and unrealized
Included in earnings	(9)	34
Included in OCI	7	2
Purchases, issuances and settlements	(61)	54
Level 3 net derivative asset/(liability) at end of year	(10)	53

25.CAPITAL DISCLOSURES

The Company defines capital as shareholders’ equity (excluding AOCI and reciprocal shareholdings), long-term debt (excluding non-recourse debt and transaction costs), short-term borrowings and non-controlling interests less cash and cash equivalents (excluding cash and cash equivalents from joint ventures and other interests not exclusively controlled by the Company). Non-recourse debt, including debt consolidated proportionately from joint venture interests, is excluded from the Company’s definition of capital as it is not controlled or managed exclusively by the Company.

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The Company’s capital is calculated as follows:

(millions of Canadian dollars)
December 31,	2009	2008
Short-term borrowings	508	874
Long-term debt (includes current portion)	12,283	10,795
Non-controlling interests	727	797
Shareholders’ equity1	7,958	6,740
Cash and cash equivalents	(258)	(469)
	21,218	18,737

1Excludes AOCI and reciprocal shareholdings.

The Company’s objectives when managing capital are to maintain flexibility among: enabling its businesses to operate at the highest efficiency; providing liquidity for growth opportunities; and providing acceptable returns to shareholders. These objectives are primarily met through maintenance of an investment grade credit rating, which provides access to lower cost capital. Capital is available generally through the issuance of both short and long-term debt and equity.

The Company manages its capital by monitoring its debt to debt plus equity ratio (excluding non-recourse debt), with a target range of 60% to 70%, to meet its capital management objectives. The debt to capitalization ratio at December 31, 2009, including short-term borrowings but excluding non-recourse short and long-term debt, was 63.6% compared with 63.6% at the end of 2008.

The Company must adhere to covenants in its credit facilities that are used to backstop its commercial paper program. These covenants include maintaining a minimum Consolidated Shareholders’ Equity balance of $1,000 million or greater and an unconsolidated debt to unconsolidated shareholders’ equity ratio of less than 1.5. As at December 31, 2009, the Company was in compliance with these covenants.

Under terms of the Company’s Trust Indenture, in order to continue to issue long-term debt, the Company must maintain a ratio of consolidated funded obligations (essentially all debt except non-recourse debt) to total consolidated capitalization of less than 75%. Total consolidated capitalization consists of shareholders’ equity, long-term debt, non-controlling interests and future income tax. As at December 31, 2009, the Company was in compliance with this covenant.

26.INCOME TAXES

INCOME TAX RATE RECONCILIATION

(millions of Canadian dollars, except per share amounts)

Year ended December 31,	2009	2008	2007
Earnings before income taxes	1,868	1,837	916
Combined statutory income tax rate	30.5%	31.3%	33.9%
Income taxes at statutory rate	570	575	311
Increase/(decrease) resulting from:
Tax rates and legislated tax changes	(58)	(11)	(63)
Future income taxes related to regulated operations	(68)	(15)	(6)
Non-taxable items, net	11	2	(19)
Higher/(lower) foreign tax rates	(61)	3	(6)
Sale of investments	(99)	(82)	-
Other	11	37	(8)
Income Taxes	306	509	209
Effective income tax rate	16.4%	27.7%	22.8%

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COMPONENTS OF FUTURE INCOME TAXES

(millions of Canadian dollars)

December 31,	2009	2008
Net Future Income Tax Liabilities/(Assets)
Differences in accounting and tax bases of property, plant and equipment	1,346	790
Differences in accounting and tax bases of investments	407	452
Regulatory assets	319	-
Financial instruments	121	(1)
Loss carryforwards	(138)	(150)
Other	29	22
Net Future Income Tax Liability	2,084	1,113

Net future income tax liability of $2,084 million (2008 - $1,113 million) includes future income tax liabilities of $2,211 million (2008 - $1,291 million) net of future income tax assets of $127 million (2008 - $178 million).

At December 31, 2009, the Company has recognized the benefit of unused tax loss carryforwards of $425 million (2008 - $452 million) of which $421 start to expire in 2019 and beyond.

GEOGRAPHICAL COMPONENTS OF PRETAX EARNINGS AND INCOME TAXES

(millions of Canadian dollars)

Year ended December 31,	2009	2008	2007
Earnings before income taxes
Canada	954	624	511
United States	334	419	210
Other	580	794	195
	1,868	1,837	916
Current income taxes
Canada	49	141	152
United States	35	43	12
Other	4	67	4
	88	251	168
Future income taxes
Canada	117	92	(36)
United States	101	166	77
	218	258	41
Current and future income taxes	306	509	209

27.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 Natural Gas Delivery and Services pension plans (collectively, the Canadian Plans) provide Company funded defined benefit pension and/or defined contribution benefits to Canadian employees of Enbridge. The Enbridge United States pension plan (the United States Plan) provides Company funded defined benefit pension benefits for United States based employees. The Company has four supplemental pension plans which provide pension benefits in excess of the basic plans for certain employees.

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The measurement date used to determine the plan assets and the accrued benefit obligation was September 30, 2009 for the Canadian Plans and December 31, 2009 for the United States Plan.

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
Canadian Plans	December 31, 2006	December 31, 20091
United States Plan	December 31, 2008	December 31, 2009

1The December 31, 2009 valuation will be filed in mid-2010.

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, benefit costs equal amounts required to be contributed by the Company.

Post-employment Benefits Other than Pensions

OPEB primarily include supplemental health, dental, health spending account and life insurance coverage for qualifying retired employees.

DEFINED BENEFIT PLANS

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.

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	Pension Benefits		OPEB
(millions of Canadian dollars)	2009	2008	2009	2008
Change in Accrued Benefit Obligation
Benefit obligation at beginning of year	1,075	1,100	179	183
Service cost	53	53	4	5
Interest cost	71	65	11	11
Amendments	-	(4)	-	-
Employees’ contributions	-	-	1	1
Actuarial gain	(13)	(125)	(1)	(27)
Benefits paid	(51)	(46)	(8)	(7)
Effect of foreign exchange rate changes	(16)	32	(16)	13
Benefit obligation at end of year	1,119	1,075	170	179
Change in Plan Assets
Fair value of plan assets at beginning of year	1,141	1,310	46	48
Actual return on plan assets	51	(180)	6	(12)
Employer’s contributions	44	33	9	8
Employees’ contributions	-	-	1	1
Benefits paid	(51)	(46)	(8)	(7)
Other	(1)	(1)	(8)	-
Effect of foreign exchange rate changes	(17)	25	(8)	8
Fair value of plan assets at end of year	1,167	1,141	38	46
Funded Status
Benefit obligation	(1,119)	(1,075)	(170)	(179)
Fair value of plan assets	1,167	1,141	38	46
Overfunded/(Underfunded) status at end of year	48	66	(132)	(133)
Contribution after measurement date	14	2	1	1
Unamortized prior service cost	6	7	-	-
Unamortized transitional obligation/(asset)	(13)	(15)	9	11
Unamortized net loss	161	167	12	24
Net amount recognized on an accrual basis at end of year	216	227	(110)	(97)
Adjustment to cash basis for amounts in EGD1	-	(157)	-	75
Net amount recognized in the Consolidated Statement of Financial Position at end of year1	216	70	(110)	(22)
Presented as follows:
Deferred Amounts and Other (Note 12)	216	70	-	-
Other Long-Term Liabilities (Note 18)	-	-	(110)	(22)

1Prior to January 1, 2009, the Company recognized pension benefit costs related to its regulated EGD pension plan on the cash basis. As a result, this amount was not recognized in the Consolidated Statements of Financial Position (Note 3).

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

	Pension Benefits			OPEB
Year ended December 31,	2009	2008	2007	2009	2008	2007
Discount rate	6.46%	6.59%	5.65%	6.28%	6.42%	5.71%
Average rate of salary increases	3.73%	5.00%	5.00%

Net Benefit Costs Recognized

(millions of Canadian dollars)	Pension Benefits			OPEB
Year ended December 31,	2009	2008	2007	2009	2008	2007
Benefits earned during the year	53	53	47	4	5	5
Interest cost on projected benefit
obligations	71	65	58	11	11	10
Actual return on plan assets	(51)	180	(105)	(6)	12	(2)
Difference between actual and
expected return on plan assets	(27)	(273)	20	3	(15)	-
Amortization of prior service costs	2	2	2	-	-	-
Amortization of transitional obligation	(2)	(2)	(2)	1	1	1
Amortization of actuarial loss	21	4	12	1	1	2
Amount charged to EEP1	(20)	(8)	(7)	(5)	(3)	(4)
Net defined benefit costs on an accrual
basis	47	21	25	9	12	12
Adjustment to cash basis for amounts
in EGD2	-	(3)	(1)	-	6	6
Defined contribution benefit costs	4	4	4	-	-	-
Net benefit cost recognized in the
Consolidated Statements of Earnings	51	22	28	9	18	18

1      EEP does not have employees and uses the services of the Company for managing and operating its businesses. EEP is charged an amount, measured at cost, for pension benefits and OPEB.

2      Prior to January 1, 2009, the Company recognized pension benefit costs related to its regulated EGD pension plan on the cash basis (Note 3).

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

	Pension Benefits			OPEB
Year ended December 31,	2009	2008	2007	2009	2008	2007
Discount rate	6.59%	5.65%	5.27%	6.42%	5.71%	5.37%
Average rate of return on pension plan
assets	7.30%	7.30%	7.31%	6.09%	6.00%	4.50%
Average rate of salary increases	5.00%	5.00%	5.00%

MEDICAL COST TRENDS

The assumed rates for the next year used to measure the expected cost of benefits are as follows:

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	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	9.4%	4.5%	2029
Other Medical and Dental	4.5%	4.5%	2009
United States Plan	8.0%	4.5%	2029

A 1% increase in the assumed medical and dental care trend rate would result in an increase of $23 million in the accumulated post-employment benefit obligations and an increase of $2 million in benefit and interest costs. A 1% decrease in the assumed medical and dental care trend rate would result in a decrease of $19 million in the accumulated post-employment benefit obligations and a decrease of $2 million in benefit and interest costs.

PLAN ASSETS

Major Categories of Plan Assets

Plan assets are invested in a diversified manner, primarily in readily marketable investments including equity and fixed income securities.

As at December 31, 2009, the pension benefits assets were invested 54.7% (2008 - 57.3%) in equity securities, 34.0% (2008 - 35.1%) in fixed income securities and 11.3% (2008 - 7.6%) in other. The OPEB assets were invested 60.5% (2008 - 58.0%) in equity securities and 39.5% (2008 - 42.0%) in fixed income securities.

	December 31, 2009
(millions of Canadian dollars)	Level 11	Level 22	Level 33	Total
Pension Benefits:
Cash and cash equivalents	65	-	-	65
Fixed income securities:
Canadian government bonds	-	82	-	82
Corporate bonds and debentures	4	-	-	4
Canadian corporate bond index fund	131	-	-	131
Canadian government bond index fund	137	-	-	137
United States debt index fund	43	-	-	43
Equity:
Canadian equity securities	150	-	-	150
Canadian equity funds	89	-	-	89
United States equity funds	117	-	-	117
Global equity funds	127	117	-	244
Private equity investment4	-	-	37	37
Exchange-traded foreign currency derivatives	1	-	-	1
Other:
Refundable taxes receivable5	-	-	62	62
Other net receivables/(payables)	-	-	-	5
	864	199	99	1,167
OPEB:
Fixed income securities:
United States government and government agency bonds	-	15	-	15
Equity:
Global equity funds	23	-	-	23
	23	15	-	38

1      Level 1 assets include assets with quoted prices in active markets for identical assets.

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2      Level 2 assets include assets with significant observable inputs.

3      Level 3 assets include assets with significant unobservable inputs.

4      The fair value of the investment in United States Limited Partnership – Global Infrastructure Fund is established through the use of valuation models.

5      The fair value of refundable taxes receivable approximates carrying value due to the nature of the receivable and the short period to maturity.

Changes in the net fair value of plan assets classified as Level 3 in the fair value hierarchy were as follows.

	Private Equity Investment	Refundable Taxes Receivable
Balance at beginning of year	19	55
Total gains/(losses), unrealized	(2)	-
Purchases, issuances, settlements	20	7
Balance at end of year	37	62

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

Target Mix for Plan Assets

	Liquids Pipelines Pension Plan	Natural Gas Delivery and Services Pension Plan	Enbridge United States Pension Plan
Equity securities	62.5%	52.5%	57.5%
Fixed income securities	32.5%	42.5%	37.5%
Other	5.0%	5.0%	5.0%

Expected Rate of Return on Plan Assets

	Pension Benefits		OPEB
Year ended December 31,	2009	2008	2009	2008
Canadian Plans	7.25%	7.25%	6.00%	6.00%
United States Plan	7.75%	7.75%	6.00%	6.00%

PLAN CONTRIBUTIONS BY THE COMPANY

(millions of Canadian dollars)	Pension Benefits		OPEB
Year ended December 31,	2009	2008	2009	2008
Total contributions	44	33	9	8
Contributions expected to be paid in 2010	66		8

BENEFITS EXPECTED TO BE PAID BY THE COMPANY

(millions of Canadian dollars)
Year ended December 31,	2010	2011	2012	2013	2014	2015-2019
Expected future benefit payments	61	63	66	70	73	428

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28.OTHER INVESTMENT INCOME

(millions of Canadian dollars)
Year ended December 31,	2009	2008	2007
Net foreign currency gains	444	43	26
Allowance for equity funds used during construction (AEDC)	135	59	15
Interest income on affiliate loans	38	34	33
Noverco preferred dividends income	15	16	16
Hurricane insurance recoveries	13	-	14
OCENSA investment income	6	23	25
Gain on reduction of EEP ownership interest	-	13	34
Other	27	10	32
	678	198	195

29.CHANGES IN OPERATING ASSETS AND LIABILITIES

(millions of Canadian dollars)
Year ended December 31,	2009	2008	2007
Accounts receivable and other	76	186	(492)
Inventory	99	(135)	160
Deferred amounts and other assets	(349)	95	(135)
Accounts payable and other	134	(115)	415
Interest payable	2	9	(6)
Other long-term liabilities	281	(66)	62
	243	(26)	4

30.RELATED PARTY TRANSACTIONS

All related party transactions are provided in the normal course of business and, unless otherwise noted, measured at the exchange amount, which is the amount of consideration established and agreed to by the related parties.

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

(millions of Canadian dollars)
Year ended December 31,	2009	2008	2007
EEP	342	302	267
Vector Pipeline	6	6	5
	348	308	272

At December 31, 2009, the Company has accounts receivable of $38 million (2008 - $41 million) from EEP and $1 million (2008 - $1 million) from Vector Pipeline.

The Company has provided EEP with an unsecured revolving credit agreement for general liquidity support. The credit facility provides for a maximum principle amount of US$500 million for a three-year term maturing in December 2010. At December 31, 2009 and 2008, there were no amounts outstanding on this facility.

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

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(millions of Canadian dollars)
Year ended December 31,	2009	2008	2007
Alliance Pipeline Canada	24	24	21
Alliance Pipeline US	18	17	15
Vector Pipeline	29	27	25
	71	68	61

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 charged/(recovered) are as follows.

(millions of Canadian dollars)
Year ended December 31,	2009	2008	2007
Purchases	16	52	43
Sales	(6)	(7)	(4)
	10	45	39

Enbridge Gas Services Inc. and Enbridge Gas Services (US) Inc., subsidiaries of the Company, have transportation commitments, measured at market value, through 2015 on Alliance Pipeline Canada and Vector Pipeline. Amounts charged are as follows.

(millions of Canadian dollars)
Year ended December 31,	2009	2008	2007
Alliance Pipeline Canada	9	9	8
Alliance Pipeline US	7	7	7
Vector Pipeline	16	16	16
	32	32	31

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 Canadian dollars)
Year ended December 31,	2009	2008	2007
Purchases	80	24	5
Sales	(7)	(9)	(6)
	73	15	(1)

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 Canadian dollars)
Year ended December 31,	2009	2008	2007
EGD	-	-	26
ECS	(2)	(2)	(2)
	(2)	(2)	24

ALBERTA CLIPPER PROJECT

In July 2009, the Company committed to fund 66.7% of the cost to construct the United States segment of the Alberta Clipper Project. The total cost of the United States segment, which is expected to be ready for

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service on April 1, 2010, is estimated at US$1,300 million, with total expenditures to date of US$900 million.

The Company is funding 66.7% of the project’s equity requirements through EELP, an equity investee. The Company has provided a $282 million (US$270 million) loan to EEP for debt financing related to the construction. At December 31, 2009, this amount is included in Accounts Receivable and Other. The loan, denominated in United States dollars, bears interest based on variable short-term rates.

In August 2008, the Company transferred $23 million, measured at market value, of 36 inch diameter line pipe to EEP for use in constructing the United States segment of the Alberta Clipper Project.

SPEARHEAD NORTH PIPELINE

In May 2009, the Company sold a section of the Spearhead Pipeline to its affiliate EEP for proceeds of US$75 million. This related party transaction has been recorded at the exchange amount which was equal to the carrying amount.

SOUTHERN LIGHTS PROJECT

In February 2009, as part of its Southern Lights Pipeline Project, the Company transferred the United States section of a newly constructed light sour pipeline to EEP in exchange for a pipeline referred to as Line 13. This non-monetary transaction has been recorded at the carrying amount.

In connection with the exchange discussed above, EEP entered into an arrangement to lease Line 13 from the Company for monthly payments of US$2 million to ensure adequate southbound pipeline capacity prior to the completion of the Alberta Clipper Project. The lease arrangement was effective in February 2009 and can be terminated at any time with written notice.

LONG-TERM RECEIVABLE FROM AFFILIATE

The affiliate long-term note receivable of $159 million (US$130 million) as at December 31, 2008, included in Deferred Amounts and Other Assets, was repaid by EEP in November 2009. Interest income for the year ended December 31, 2009 related to the note receivable was $11 million (2008 - $12 million; 2007 - $10 million).

31.COMMITMENTS AND CONTINGENCIES

COMMITMENTS

The Company has signed contracts for the purchase of services, pipe and other materials totaling $697 million which are expected to be paid within the next 5 years.

ENBRIDGE GAS DISTRIBUTION INC.

Bloor Street Incident

EGD 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 in April 2003. In October 2007, all of the TSSA and OHSA charges laid against EGD were dismissed by the Ontario Court of Justice. The decision has been appealed by the Crown to the Ontario Superior Court of Justice and the appeal was heard by the Court during November and December 2009. The Court’s decision has been reserved and EGD expects it to be released in early 2010. EGD does not believe any fines that may be levied would have a material financial impact on EGD.

EGD has also been named as a defendant in a number of civil actions related to the explosion. All significant civil actions have been settled without any material financial impact on EGD. A Coroner’s Inquest in connection with the explosion is also possible.

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 and regulatory actions and proceedings which arise in the normal course of business, including interventions in regulatory proceedings and challenges to regulatory approvals and permits by special interest groups. While the

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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.

32.GUARANTEES

Enbridge Energy Company, Inc. (EEC), a subsidiary of the Company and 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$62 million of EEP’s long-term debt at December 31, 2009 (2008 - US$93 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, the Company enters into agreements which indemnify third parties. The Company cannot reasonably estimate the maximum potential amounts that could become payable to third parties under these agreements; however, historically, the Company 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 of such indemnification obligations include the following.

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.

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33.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

(millions of Canadian dollars, except per share amounts)

Year ended December 31,	2009	2008	2007
Earnings under Canadian GAAP Applicable to Common Shareholders	1,555	1,321	700
Earnings under Canadian GAAP	1,562	1,328	707
Inventory valuation adjustment, net of tax3	(24)	-	-
Earnings attributable to non-controlling interests under Canadian GAAP	37	56	46
Earnings as a result of consolidating EEP under U.S. GAAP6	177	278	168
Earnings under U.S. GAAP	1,752	1,662	921
Attributable to
Enbridge Inc.1	1,538	1,328	707
Non-controlling interests1	214	334	214
Earnings under U.S. GAAP	1,752	1,662	921
Earnings per Common Share attributable to Enbridge Inc.	4.71	3.67	1.97
Diluted Earnings per Common Share attributable to Enbridge Inc.	4.68	3.64	1.95
COMPREHENSIVE INCOME
(millions of Canadian dollars, except per share amounts)
Year ended December 31,	2009	2008	2007
Earnings under U.S. GAAP	1,752	1,662	921
Other comprehensive income/(loss) under Canadian GAAP	(576)	318	(197)
Underfunded pension adjustment, net of tax5	3	(57)	23
Other comprehensive income attributable to non-controlling interests under Canadian GAAP	(72)	101	(92)
Other comprehensive income as a result of consolidating EEP under U.S. GAAP6	(62)	241	(81)
Comprehensive income under U.S. GAAP	1,045	2,265	574
Attributable to
Enbridge Inc.1	965	1,589	533
Non-controlling interests1	80	676	41
Comprehensive income under U.S. GAAP	1,045	2,265	574

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FINANCIAL POSITION

	2009		2008
(millions of Canadian dollars)		United		United
December 31,	Canada	States	Canada	States
Assets
Current Assets
Cash and cash equivalents2,6	327	478	542	961
Accounts receivable and other2,6	2,484	2,848	2,322	3,175
Inventory2,3,6	784	824	845	911
	3,595	4,150	3,709	5,047
Property, Plant and Equipment, net2,6	18,850	26,837	16,157	24,738
Long-Term Investments2,6	2,312	228	2,492	412
Deferred Amounts and Other Assets2,4,5,6	2,425	2,478	1,318	2,080
Intangible Assets6	488	575	458	334
Goodwill6	372	719	389	808
Future Income Taxes8	127	148	178	178
	28,169	35,135	24,701	33,597
Liabilities and Shareholders’ Equity
Current Liabilities
Short-term borrowings	508	508	874	874
Accounts payable and other2,6	2,463	3,178	2,411	3,203
Interest payable6	104	151	102	143
Current maturities of long-term debt	601	633	534	534
Current maturities of non-recourse long-term debt2,6	113	131	185	706
	3,789	4,601	4,106	5,460
Long-Term Debt4,6	11,581	15,647	10,155	10,257
Non-Recourse Long-Term Debt2,6	1,393	1,399	1,474	5,448
Other Long-Term Liabilities2,5,6,9	1,207	1,311	259	398
Future Income Taxes2,4,5,6,8	2,211	2,147	1,291	2,014
	20,181	25,105	17,285	23,577
Non-Controlling Interests1,6	727	-	797	-
Shareholders’ Equity
Share capital
Preferred shares	125	125	125	125
Common shares	3,379	3,379	3,194	3,194
Contributed surplus	54	-	38	-
Retained earnings3	4,400	4,343	3,383	3,351
Additional paid in capital	-	98	-	82
Accumulated other comprehensive income/(loss)4	(543)	(646)	33	(72)
Reciprocal shareholding	(154)	(154)	(154)	(154)
	7,261	7,145	6,619	6,526
Total Enbridge Inc. Liabilities and Shareholders’ Equity	28,169	32,250	24,701	30,103
Non-Controlling Interests1,6	-	2,885	-	3,494
	28,169	35,135	24,701	33,597

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1Presentation of Non-Controlling Interests

Under Canadian GAAP earnings attributable to non-controlling interests are presented as part of earnings on the income statement and the non-controlling interest balance is presented as a liability on the balance sheet. Under U.S. GAAP, the earnings and retained earnings attributable to non-controlling interests are presented as a separate component of equity.

For the year ended December 31, 2009, $214 million (2008 - $334 million; 2007 - $214 million) of earnings are attributable to non-controlling interests.

Included in OCI for the year ended December 31, 2009 is an unrealized loss on cash flow hedges of $62 million (2008 - $241 million unrealized gain; 2007 - $81 million unrealized loss), a decrease in currency translation adjustment of $71 million (2008 - $81 million increase; 2007 - $61 million decrease) and an after-tax change in OCI of $1 million (2008 - $20 million; 2007 - $31 million) attributable to non-controlling interests.

2Accounting for Joint Ventures

Canadian GAAP requires that investments in joint ventures are proportionately consolidated. 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 United States 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 presentation and classification and not earnings or shareholders’ equity. Additional information related to the Company’s investments in joint ventures is included in Note 10, Joint Ventures.

3Commodity Inventories Valuation

Under Canadian GAAP commodity inventories are recorded at fair value. U.S. GAAP requires that commodity inventories be recorded at the lower of cost or market. For the year ended December 31, 2009, lower of cost or market adjustments resulted in a $36 million decrease to inventory, a $12 million decrease to the future income tax liability and a $24 million decrease to earnings. There were no lower of cost or market adjustments related to commodity inventory valuation for the years ended December 31, 2008 and 2007.

4Transaction Costs

Under Canadian GAAP transaction costs arising from the issuance of debt are recorded in Long-Term Debt. For U.S. GAAP, these costs are reclassified to Deferred Amounts and Other Assets. As at December 31, 2009, $98 million (2008 - $102 million) of transaction costs were reclassified.

5Pension Funding Status

U.S. GAAP requires an employer to recognize the overfunded or underfunded status of a defined benefit post retirement plan or OPEB plan as an asset or liability and to recognize changes in the funded status in the period in which they occur through comprehensive income while Canadian GAAP does not require the recognition of the defined benefit post retirement plan or OPEB plan funding status.

Pension funding status adjustments resulted in an increase in the net liability of $155 million (2008 - $159 million) for the underfunded status of the plans, a decrease in future tax liability of $52 million (2008 - $54 million) and an increase in accumulated other comprehensive loss of $103 million (2008 - $105 million) at December 31, 2009.

Amounts removed from OCI and recognized as components of the net pension and OPEB costs in the year are as follows:

(millions of Canadian dollars)	2009	2008	2007
Prior service cost	2	1	1
Net transitional obligation	(1)	(1)	(1)
Net loss	22	1	3
	23	1	3

Amounts included in AOCI that have not yet been recognized as a component of net periodic benefit cost are as follows:

(millions of Canadian dollars)	2009	2008	2007
Prior service cost	4	1	4
Net transitional obligation	(3)	(6)	(7)
Accumulated net loss	107	110	52
	108	105	49

Net amounts reflected in OCI for the year are as follows:

(millions of Canadian dollars)	2009	2008	2007
Unamortized prior service cost	3	(3)	(1)
Unamortized transitional obligation	3	1	1
Net loss/(gain)	(3)	58	(23)
	3	56	(23)

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The Company estimates that approximately $15 million related to pension and OPEB plans at December 31, 2009 will be reclassified into earnings in the next twelve months, as follows:

(millions of Canadian dollars)	Pension Benefits	OPEB	Total
Net transitional obligation	(2)	1	(1)
Prior service costs	1	-	1
Loss	14	1	15
	13	2	15

6Consolidation of a Limited Partnership

Under U.S. GAAP the Company is deemed to have control of EEP and therefore consolidates its 27% interest in the partnership, resulting in an increase to both assets and liabilities of $6,974 million at December 31, 2009 (2008 - $8,248 million) and no recognition or measurement changes to equity or earnings as at and for the year ended December 31, 2009.

7Unrecognized Tax Benefits

(millions of Canadian dollars)	2009	2008
Unrecognized Tax Benefits at beginning of year	13	61
Gross increases for tax positions of current year	5	33
Gross increases for tax positions of prior years	6	-
Gross decreases for tax positions of prior years	(1)	(82)
Changes in translation of foreign currency	(1)	1
Unrecognized Tax Benefits at end of year	22	13

The unrecognized tax benefits at December 31, 2009, if recognized, would affect the Company’s effective income tax rate. Gross increases in 2008 include a $32 million charge for the United States tax litigated matter, to unrecognize all of the tax benefits. As an unfavourable court decision was rendered in 2008, the full tax benefit balance of $65 was reversed and the unrecognized benefits removed as reflected in 2008 gross decreases. The Company does not anticipate further adjustments to the unrecognized tax benefits during the next twelve months that would have a material impact on its consolidated financial statements.

The Company recognizes accrued interest and penalties related to unrecognized tax benefits as a component of income tax expense. Income tax expense for the year ended December 31, 2009 includes $1 million (2008 - $2 million) of interest. As at December 31, 2009, interest and penalties of $10 million (2008 - $9 million) have been accrued.

The Company and its subsidiaries are subject to either Canadian federal and provincial income tax, United States federal, state and local income tax, or the relevant income tax in other international jurisdictions. The Company has substantially concluded all Canadian federal and provincial income tax matters for the years through 2002 and all returns are generally closed through 2004. Generally, all United States federal income tax returns and state and local income tax returns are closed through 2005 for all tax matters with the exception of the previously litigated matter. Various Canadian federal and provincial income tax returns for 2006 and 2007 are currently under examination by the Canada Revenue Agency.

8Future 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, 2008, a deferred tax liability of $803 million was recorded for U.S. GAAP purposes and reflects the difference between the carrying value and the tax basis of property, plant and equipment. Effective January 1, 2009, the Canadian GAAP exemption which precluded rate regulated entities from recognizing future income taxes was removed.

9Indefinite Reversal Rule

The Company has not provided future taxes on the unremitted earnings of foreign investments that the Company does not intend to repatriate in the foreseeable future. These earnings relate to ongoing operations and as at December 31, 2009 were approximately $460 million (2008 - $428 million).

NEW ACCOUNTING STANDARDS UNDER U.S. GAAP

Fair Value Measurements

In September 2006, the Financial Accounting Standards Board (FASB) issued a statement that defines fair value, establishes a framework for measuring fair value in the context of GAAP and expands the disclosure requirements surrounding fair value measurement. In January 2008, the FASB deferred the implementation of this standard 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 Company adopted this standard for those assets and liabilities recognized or disclosed at fair value in the financial statements on a recurring basis as of January 1, 2008 and the aspects of the standard for non-financial assets and liabilities as of January 1, 2009.

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Business Combinations

In December 2007, the FASB issued a revised statement related to business combinations. This statement retains the fundamental requirements in the original statement, requiring that the acquisition method of accounting be used for all business combinations and for an acquirer to be identified for each business combination. The statement revises how the acquisition method is applied when measuring and recognizing certain items acquired. The Company adopted this standard on January 1, 2009.

Accounting for Non-Controlling Interests

In December 2007, the FASB issued a statement related to the classification of non-controlling interests in consolidated financial statements. The statement requires non-controlling interests in subsidiaries to be reported as equity on the Statement of Financial Position and requires comprehensive income attributable to non-controlling interests to be disclosed. The standard only impacts presentation and does not impact the recognition or measurement of amounts related to non-controlling interests. The Company adopted this standard on January 1, 2009.

Derivative Instrument and Hedging Activities Disclosures

In March 2008, the FASB issued a statement revising disclosure requirements for derivative instruments and hedging activities. The standard impacts presentation only and does not impact the recognition or measurement of amounts related to derivative instruments and hedging activities. The Company adopted this standard on January 1, 2009.

FUTURE ACCOUNTING STANDARDS UNDER U.S. GAAP

The following standards will be effective for the Company beginning on January 1, 2010. Management does not expect the adoption of any of these standards to significantly impact the consolidated financial statements.

Consolidation of Variable Interest Entities

In June 2009, the FASB issued a statement revising the existing statement on Consolidation of Variable Interest Entities. The revised Statement focuses on a qualitative approach and requires the re-assessment of existing arrangements on an on-going basis.

Accounting for Transfers of Financial Assets

In June 2009, the FASB issued a statement amending the existing statement on Transfers of Financial Assets and Extinguishments of Liabilities. The amended standard eliminates the qualifying special purpose entity concept, imposes stricter sale criteria, revises the de-recognition criteria and provides guidance on determining gains or losses when a transfer qualifies as a sale.

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