EX-99.6 7 a11-5192_1ex99d6.htm EX-99.6 AUDITED FINANCIAL STATEMENTS OF THE REGISTRANT AND NOTES THERETO FOR THE FISCAL YEARS ENDED

Exhibit 99.6

ENBRIDGE INC.

CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2010

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, 2010, 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 at December 31, 2010.

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 and the standards of the Public Company Accounting Oversight Board (United States).

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

February 18, 2011

Independent Auditor’s 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

www.pwc.com/ca

To the Shareholders of

Enbridge Inc.

We have completed integrated audits of Enbridge Inc.’s 2010, 2009 and 2008 consolidated financial statements and its internal control over financial reporting as at December 31, 2010. Our opinions, based on our audits, are presented below.

Report on the consolidated financial statements

We have audited the accompanying consolidated financial statements of Enbridge Inc., which comprise the consolidated statements of financial position as at December 31, 2010 and December 31, 2009 and the consolidated statements of earnings, comprehensive income, shareholders’ equity and cash flows for each of the three years in the period ended December 31, 2010, and the related notes including a summary of significant accounting policies.

Management’s responsibility for the consolidated financial statements

Management is responsible for the preparation and fair presentation of these consolidated financial statements in accordance with Canadian generally accepted accounting principles and for such internal control as management determines is necessary to enable the preparation of consolidated financial statements that are free from material misstatement, whether due to fraud or error.

Auditor’s responsibility

Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We conducted our audits 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 consolidated financial statements are free from material misstatement. Canadian generally accepted auditing standards require that we comply with ethical requirements.

An audit involves performing procedures to obtain audit evidence, on a test basis, about the amounts and disclosures in the consolidated financial statements. The procedures selected depend on the auditor’s judgment, including the assessment of the risks of material misstatement of the consolidated financial statements, whether due to fraud or error. In making those risk assessments, the auditor considers internal control relevant to the company’s preparation and fair presentation of the consolidated financial statements in order to design audit procedures that are appropriate in the circumstances. An audit also includes evaluating the appropriateness of accounting principles and policies used and the reasonableness of accounting estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements.

We believe that the audit evidence we have obtained in our audits is sufficient and appropriate to provide a basis for our audit opinion on the consolidated financial statements.

Opinion

In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of Enbridge Inc. as at December 31, 2010 and December 31, 2009 and the results of its operations and cash flows for each of the three years in the period ended December 31, 2010 in accordance with Canadian generally accepted accounting principles.

“PricewaterhouseCoopers” refers to PricewaterhouseCoopers LLP, an Onlario 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.

Report on internal control over financial reporting

We have also audited Enbridge Inc.’s internal control over financial reporting as at December 31, 2010, based on the criteria established in Internal Control - Integrated Framework, issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).

Management’s responsibility for internal control over financial reporting

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.

Auditor’s responsibility

Our responsibility is to express an opinion on 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 exists, 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 audit opinion on the company’s internal control over financial reporting.

Definition of internal control over financial reporting

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 Canadian 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 Canadian 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.

Inherent limitations

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.

Opinion

In our opinion, Enbridge Inc. maintained, in all material respects, effective internal control over financial reporting as at December 31, 2010 based on criteria established in Internal Control - Integrated Framework, issued by COSO.

/s/ PriceWaterhouseCoopers

Chartered Accountants

Calgary, Alberta, Canada

February 18, 2011

CONSOLIDATED STATEMENTS OF EARNINGS

Year ended December 31,	2010		2009		2008
(millions of Canadian dollars, except per share amounts)
Revenues
Commodity sales	11,990		9,720		13,432
Transportation and other services	3,137		2,746		2,699
	15,127		12,466		16,131
Expenses
Commodity costs	11,291		9,011		12,792
Operating and administrative	1,466		1,430		1,312
Depreciation and amortization	864		764		658
	13,621		11,205		14,762
	1,506		1,261		1,369
Income from Equity Investments	38		198		177
Other Income (Note 28)	374		678		198
Interest Expense (Note 16)	(687	)	(597	)	(551	)
Gain on Sale of Investments (Note 6)	-		365		700
	1,231		1,905		1,893
Non-Controlling Interests	(10	)	(37	)	(56	)
	1,221		1,868		1,837
Income Taxes (Note 26)	(251	)	(306	)	(509	)
Earnings	970		1,562		1,328
Preferred Share Dividends	(7	)	(7	)	(7	)
Earnings Applicable to Common Shareholders	963		1,555		1,321

Earnings per Common Share (Note 20)	2.60		4.27		3.67

Diluted Earnings per Common Share (Note 20)	2.57		4.25		3.64

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

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

Year ended December 31,	2010		2009		2008
(millions of Canadian dollars)
Earnings	970		1,562		1,328
Other Comprehensive Income/(Loss)
Change in unrealized loss on cash flow hedges, net of tax	(113	)	(54	)	(127	)
Change in unrealized gain/(loss) on net investment hedges, net of tax	51		151		(160	)
Reclassification to earnings of realized cash flow hedges, net of tax	(25	)	114		(1	)
Reclassification to earnings of unrealized cash flow hedges, net of tax (Note 6)	-		(20	)	-
Other comprehensive income/(loss) from equity investees, net of tax	(11	)	(24	)	49
Non-controlling interests in other comprehensive income/(loss)	33		72		(101	)
Change in foreign currency translation adjustment	(274	)	(815	)	658
Other Comprehensive Income/(Loss)	(339	)	(576	)	318
Comprehensive Income	631		986		1,646

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

CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY

Year ended December 31,	2010		2009		2008
(millions of Canadian dollars, except per share amounts)
Preferred Shares (Note 20)	125		125		125
Common Shares (Note 20)
Balance at beginning of year	3,379		3,194		3,027
Common shares issued	-		4		-
Dividend reinvestment and share purchase plan	224		143		131
Shares issued on exercise of stock options	80		38		36
Balance at End of Year	3,683		3,379		3,194
Contributed Surplus
Balance at beginning of year	54		38		26
Stock-based compensation	13		19		14
Options exercised	(8	)	(3	)	(2	)
Balance at End of Year	59		54		38
Retained Earnings
Balance at beginning of year	4,400		3,383		2,537
Earnings applicable to common shareholders	963		1,555		1,321
Common share dividends declared	(648	)	(555	)	(489	)
Dividends paid to reciprocal shareholder	19		17		14
Balance at End of Year	4,734		4,400		3,383
Accumulated Other Comprehensive Income/(Loss) (Note 22)
Balance at beginning of year	(543	)	33		(285	)
Other comprehensive income/(loss)	(339	)	(576	)	318
Balance at End of Year	(882	)	(543	)	33
Reciprocal Shareholding (Note 11)	(154	)	(154	)	(154	)
Total Shareholders’ Equity	7,565		7,261		6,619
Dividends Paid per Common Share	1.70		1.48		1.32

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

CONSOLIDATED STATEMENTS OF CASH FLOWS

Year ended December 31,	2010		2009		2008
(millions of Canadian dollars)
Operating Activities
Earnings	970		1,562		1,328
Depreciation and amortization	864		764		658
Unrealized gains on derivative instruments	(10	)	(204	)	(120	)
Allowance for equity funds used during construction	(80	)	(135	)	(59	)
Cash distributions in excess of/(less than) equity earnings	214		(9	)	(82	)
Gain on reduction of ownership interest	(81	)	-		(12	)
Gain on sale of investments (Note 6)	-		(365	)	(700	)
Future income taxes	238		218		258
Goodwill and asset impairment losses	-		11		23
Non-controlling interests	10		37		56
Other	(11	)	(105	)	48
Changes in operating assets and liabilities (Note 29)	(263	)	243		(26	)
	1,851		2,017		1,372
Investing Activities
Additions to property, plant and equipment	(2,357	)	(3,225	)	(3,545	)
Additions to intangible assets	(50	)	(95	)	(91	)
Change in construction payable	27		(110	)	106
Long-term investments	(121	)	(359	)	(659	)
Affiliate loans, net	(80	)	(145	)	-
Acquisitions (Notes 10 and 19)	(116	)	-		-
Proceeds on sale of investments (Note 6)	23		535		1,383
Sale of property, plant and equipment	-		87		-
Settlement of hedges (Note 6)	-		6		(47	)
	(2,674	)	(3,306	)	(2,853	)
Financing Activities
Net change in short-term borrowings	(182	)	(366	)	329
Net change in commercial paper and credit facility draws	(347	)	736		744
Debenture and term note issues	2,300		1,500		498
Debenture and term note repayments	(600	)	(616	)	(602	)
Net change in Southern Lights project financing	14		343		1,238
Non-recourse debt issues	5		60		46
Non-recourse debt repayments	(73	)	(130	)	(66	)
Distributions to non-controlling interests, net	(1	)	(33	)	(10	)
Common shares issued	66		36		29
Preferred share dividends	(7	)	(7	)	(7	)
Common share dividends	(426	)	(414	)	(359	)
	749		1,109		1,840
Effect of translation of foreign denominated cash and cash equivalents	(11	)	(35	)	16
Increase/(Decrease) in Cash and Cash Equivalents	(85	)	(215	)	375
Cash and Cash Equivalents at Beginning of Year	327		542		167
Cash and Cash Equivalents at End of Year 1	242		327		542
Supplementary Cash Flow Information
Income taxes paid (Note 26)	108		205		161
Interest paid (Note 16)	711		656		607

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

1 Cash and cash equivalents consists of $143 million (2009 - $184 million; 2008 - $68 million) of cash and $99 million (2009 - $143 million; 2008 - $474 million) of short-term investments and includes restricted cash of $12 million (2009 - $7 million; 2008 - $24 million), and joint-venture cash which is not readily accessible by the Company of $48 million (2009 - $52 million; 2008 - $57 million).

CONSOLIDATED STATEMENTS OF FINANCIAL POSITION

December 31,	2010		2009
(millions of Canadian dollars)
Assets
Current Assets
Cash and cash equivalents	242		327
Accounts receivable and other (Note 7)	2,706		2,484
Inventory (Note 8)	813		784
	3,761		3,595
Property, Plant and Equipment, net (Note 9)	20,332		18,850
Long-Term Investments (Note 11)	2,198		2,312
Deferred Amounts and Other Assets (Note 12)	2,886		2,425
Intangible Assets (Note 13)	478		488
Goodwill (Note 14)	385		372
Future Income Taxes (Note 26)	80		127
	30,120		28,169
Liabilities and Shareholders’ Equity
Current Liabilities
Short-term borrowings (Note 16)	326		508
Accounts payable and other (Note 15)	2,688		2,463
Interest payable	117		104
Current maturities of long-term debt (Note 16)	154		601
Current maturities of non-recourse long-term debt (Note 17)	70		113
	3,355		3,789
Long-Term Debt (Note 16)	13,561		11,866
Non-Recourse Long-Term Debt (Note 17)	1,061		1,108
Other Long-Term Liabilities (Note 18)	1,473		1,207
Future Income Taxes (Note 26)	2,447		2,211
	21,897		20,181
Non-Controlling Interests (Note 19)	658		727
Shareholders’ Equity
Share capital
Preferred shares (Note 20)	125		125
Common shares (Note 20)	3,683		3,379
Contributed surplus	59		54
Retained earnings	4,734		4,400
Accumulated other comprehensive loss (Note 22)	(882	)	(543	)
Reciprocal shareholding (Note 11)	(154	)	(154	)
	7,565		7,261
Commitments and Contingencies (Note 31)
	30,120		28,169

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

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 five operating segments: Liquids Pipelines, Gas Distribution, Gas Pipelines, Processing and Energy Services, Sponsored Investments, and Corporate. These operating segments have been revised to better reflect the 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. Segmented information has been retroactively reclassified to reflect these changes, but had no impact on reported Consolidated Earnings Applicable to Common Shareholders.

LIQUIDS PIPELINES

Liquids Pipelines consists of common carrier and contract crude oil, natural gas liquids (NGLs) and refined products pipelines and terminals in Canada and the United States, including the Enbridge System, the Enbridge Regional Oil Sands System, Southern Lights Pipeline and other feeder pipelines.

GAS DISTRIBUTION

Gas Distribution consists of the Company’s natural gas utility operations, the core of which is Enbridge Gas Distribution Inc. (EGD) which serves residential, commercial and industrial 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.

GAS PIPELINES, PROCESSING AND ENERGY SERVICES

Gas Pipelines, Processing and Energy Services consists of investments in natural gas pipelines, processing and green energy projects, the Company’s commodity marketing businesses, and international activities.

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. Investments in processing includes the Company’s interest 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 25.5% ownership interest in Enbridge Energy Partners, L.P. (EEP), Enbridge’s 66.7% investment in the United States segment of the Alberta Clipper Project through EEP and Enbridge Energy, L.P. (EELP) and an overall 72% economic interest in Enbridge Income Fund (EIF), held both directly and indirectly through Enbridge Income Fund Holdings Inc. (EIFH). 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. The primary operations of EIF include a crude oil and liquids pipeline and gathering system, a 50% interest in the Canadian portion of Alliance Pipeline Canada and partial interests in several green energy investments.

CORPORATE

Corporate consists of the Company’s investment in Noverco Inc. (Noverco), new business development activities, general corporate investments and financing costs not allocated to the business segments.

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 values of regulatory assets and liabilities (Note 5); allowance for doubtful accounts (Note 7); 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 value of financial instruments (Notes 23 and 24); income taxes (Note 26); post employment benefits (Note 27); commitments and contingencies (Note 31); and fair value of asset retirement obligations. Actual results could differ from these estimates.

BASIS OF PRESENTATION

The consolidated financial statements include the accounts of Enbridge Inc., its subsidiaries and its proportionate share of the accounts of various 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 the combination of a total direct and indirect 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 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 Canadian 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 which are both capitalized based on rates set out in a regulatory agreement. In the absence of rate regulation, the Company would capitalize interest using a capitalization rate based on its cost of borrowing and the capitalized equity component, the corresponding earnings during the construction phase and the subsequent depreciation would not be recognized.

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

With the approval of the regulator, 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.

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 committed delivery contracts rather than the cash tolls received.

For rate-regulated operations in Sponsored Investments and in natural gas pipelines included in Gas Pipelines, Processing and Energy 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 Gas Distribution, 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 Income and Interest Expense. The Company has classified Cash and Cash Equivalents and its non-qualifying derivative instruments as held for trading.

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/(Loss) (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 affiliate 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 deferred in OCI up to that date will be 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 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.

Balance Sheet Offset

Assets and liabilities arising from derivative instruments are offset in the Consolidated Statement of Financial Position when the Company has the legal right and intention to settle them on a net basis.

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 by completing a quantitative or qualitative analysis of factors impacting the investment. 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. For the Company’s regulated operations, a future income tax liability is recognized with a corresponding regulatory asset.

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 foreign currency 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 historical rate of exchange in effect on the date of the transaction. Exchange gains and losses resulting from translation of monetary assets and liabilities are included in the Consolidated 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 restricted cash of 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 as a liability for future refund or as an asset for 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.

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 and 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, commencing when the asset is available for use.

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 in which 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 the majority 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:

· 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 invested asset mix within the pension plans. 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 Accounts Payable and Other or 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

FUTURE ACCOUNTING POLICY CHANGES

International Financial Reporting Standards

First-time adoption of Part I - International Financial Reporting Standards (Part I) of the Canadian Institute of Chartered Accountants (CICA) Handbook is mandatory for Canadian publicly accountable enterprises on January 1, 2011, with the exception of certain qualifying entities. Part I is mandatory for qualifying entities, including those with operations subject to rate regulation, for periods beginning on or after January 1, 2012. The Company is a qualifying entity for purposes of this deferral and it will continue to present its financial statements in accordance with Part V - Pre-changeover Accounting Standards of the CICA Handbook during the 2011 deferral period.

Business Combinations

CICA Handbook Section 1582, Business Combinations, replaces Section 1581. The new standard requires assets and liabilities acquired in a business combination to be measured at fair value at the acquisition date and if applicable, any original equity interest in the investee to be re-measured to fair

value through earnings on the date control is obtained. The standard also requires that acquisition-related costs, such as advisory or legal fees, incurred to effect a business combination be expensed in the period in which they are incurred. The adoption of this standard will impact the Company’s accounting treatment of future business combinations occurring on or after January 1, 2011.

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 impacts presentation only. They are not expected to have a material impact to the Company’s consolidated earnings or cash flows. The revised standards are effective January 1, 2011.

4. SEGMENTED INFORMATION

Year ended December 31, 2010	Liquids Pipelines		Gas Distribution		Gas Pipelines, Processing and Energy Services		Sponsored Investments		Corporate		Consolidated
(millions of Canadian dollars)
Revenues	1,672		2,611		10,518		326		-		15,127
Commodity costs	-		(1,384	)	(9,907	)	-		-		(11,291	)
Operating and administrative	(603	)	(497	)	(215	)	(120	)	(31	)	(1,466	)
Depreciation and amortization	(312	)	(310	)	(144	)	(88	)	(10	)	(864	)
	757		420		252		118		(41	)	1,506
Income from equity investments	-		-		-		32		6		38
Other income/(expense) and gain on sale of investments	115		(17	)	30		114		132		374
Interest and preferred share dividends	(223	)	(179	)	(96	)	(58	)	(138	)	(694	)
Non-controlling interest	(2	)	(5	)	-		(3	)	-		(10	)
Income taxes	(135	)	(64	)	(65	)	(66	)	79		(251	)
Earnings applicable to common shareholders	512		155		121		137		38		963

Year ended December 31, 2009	Liquids Pipelines		Gas Distribution		Gas Pipelines, Processing and Energy Services		Sponsored Investments		Corporate		Consolidated
(millions of Canadian dollars)
Revenues	1,333		2,992		7,823		313		5		12,466
Commodity costs	-		(1,757	)	(7,254	)	-		-		(9,011	)
Operating and administrative	(565	)	(495	)	(226	)	(113	)	(31	)	(1,430	)
Depreciation and amortization	(230	)	(298	)	(140	)	(88	)	(8	)	(764	)
	538		442		203		112		(34	)	1,261
Income from equity investments	-		-		-		188		10		198
Other income/(expense) and gain on sale of investments	161		(12	)	366		13		515		1,043
Interest and preferred share dividends	(144	)	(188	)	(87	)	(56	)	(129	)	(604	)
Non-controlling interests	(2	)	(6	)	-		(28	)	(1	)	(37	)
Income taxes	(108	)	(50	)	(54	)	(88	)	(6	)	(306	)
Earnings applicable to common shareholders	445		186		428		141		355		1,555

Year ended December 31, 2008	Liquids Pipelines		Gas Distribution		Gas Pipelines, Processing and Energy Services		Sponsored Investments		Corporate		Consolidated
(millions of Canadian dollars)
Revenues	1,170		3,189		11,464		298		10		16,131
Commodity costs	-		(1,994	)	(10,798	)	-		-		(12,792	)
Operating and administrative	(492	)	(475	)	(211	)	(102	)	(32	)	(1,312	)
Depreciation and amortization	(181	)	(277	)	(115	)	(78	)	(7	)	(658	)
	497		443		340		118		(29	)	1,369
Income from equity investments	-		-		25		148		4		177
Other income and gain on sale of investments	61		14		718		25		80		898
Interest and preferred share dividends	(111	)	(193	)	(77	)	(60	)	(117	)	(558	)
Non-controlling interests	(1	)	(7	)	-		(47	)	(1	)	(56	)
Income taxes	(118	)	(96	)	(239	)	(73	)	17		(509	)
Earnings applicable to common shareholders	328		161		767		111		(46	)	1,321

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

TOTAL ASSETS
December 31,	2010	2009
(millions of Canadian dollars)
Liquids Pipelines	11,503	10,763
Gas Distribution	7,562	7,377
Gas Pipelines, Processing and Energy Services	5,533	4,801
Sponsored Investments	3,822	3,860
Corporate	1,700	1,368
	30,120	28,169

ADDITIONS TO PROPERTY, PLANT AND EQUIPMENT1

December 31,	2010	2009
(millions of Canadian dollars)
Liquids Pipelines	765	2,662
Gas Distribution	387	326
Gas Pipelines, Processing and Energy Services	1,153	321
Sponsored Investments	132	41
Corporate	-	10
	2,437	3,360

1 Includes AEDC.

GEOGRAPHIC INFORMATION
Revenues1
Year ended December 31,	2010	2009	2008
(millions of Canadian dollars)
Canada	9,876	9,503	12,459
United States	5,251	2,963	3,672
	15,127	12,466	16,131

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

Property, Plant and Equipment
December 31,	2010	2009
(millions of Canadian dollars)
Canada	16,095	15,101
United States	4,237	3,749
	20,332	18,850

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 whereby 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 2005 to 2009 and a one year ITS was approved by the NEB for 2010. The Company has reached agreement with industry to roll forward the 2010 ITS agreement for a year and will file the 2011 ITS with the NEB in March 2011. The ITS 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 with industry continue for a longer term settlement agreement which will support a competitive toll structure. Until all matters before the NEB are settled, interim tolls will continue to be collected for the Enbridge System.

Southern Lights

The United States portion of the Southern Lights Pipeline is regulated by the FERC and the Canadian portion of the pipeline is regulated by the NEB. Shippers on the Southern Lights Pipeline are subject to 15-year transportation contracts under a cost of service toll methodology. Toll adjustments are filed annually with the regulators. Tariffs provide for recovery of all operating and debt financing costs, plus a pre-determined after tax rate of return on equity (ROE) of 10%. Southern Lights 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 that expires 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 years ended December 31, 2010, 2009 and 2008 based on a 36% deemed common equity component of capital for regulatory purposes for each of those years.

Enbridge Gas New Brunswick

Enbridge Gas New Brunswick (EGNB) is regulated by the EUB and an application for rate adjustments is filed annually for EUB approval. EGNB’s after-tax ROE for the year ended December 31, 2010 was 13.00% (2009 - 13.00%; 2008 - 13.00%) based on equity which is capped at 50%.

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, 2010 included an after tax ROE component of 11.18% (2009 - 11.07%; 2008 - 11.04%).

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 annually with the regulators. Tolls for the years ended December 31, 2010, 2009 and 2008 included an after tax ROE component of 10.88% for the United States portion and 11.26% for the Canadian portion. Alliance Pipeline tolls are based on a deemed 70% debt and 30% equity structure.

FINANCIAL STATEMENT EFFECTS

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

					Estimated Settlement Period	Earnings Impact1
December 31,	2010		2009		(years)	2010		2009		2008
(millions of Canadian dollars)
Regulatory Assets/(Liabilities)
Liquids Pipelines
Future income taxes2	575		504		-	53		49		-
Tolling deferrals3	91		98		1	(7	)	(16	)	(30)
Gas Distribution
Future income taxes2	169		227		-	(7	)	(11	)	-
EGNB regulatory deferral4	171		155		30	18		15		10
Future removal and site restoration reserves5	(773	)	(710	)	-	-		6		-
Purchased gas variance6	(144	)	(227	)	1	-		-		-
Pension plans and OPEB, net7	(114	)	(60	)	-	-		(2	)	-
Gas Pipelines, Processing and Energy Services
Future income taxes2	42		-		-	(5	)	-		-
Deferred transportation revenue8	150		185		13-15	(17	)	(6	)	1
Sponsored Investments
Future income taxes2	94		98		-	(3	)	(11	)	-
Deferred transportation revenue8	98		91		15	5		5		6

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

2 This regulatory asset is a corresponding balance to a future income tax liability, first recognized on adoption of the revised CICA Handbook section 3465 – Income Taxes in 2009.The asset represents the regulatory offset to future income tax liabilities to the extent that it is expected to be included in regulator-approved future rates and recovered from or refunded to future customers. The recovery period depends on future temporary differences. In the absence of rate regulation, this regulatory balance and the related earnings impact would not be recorded.

3 Tolls are calculated in accordance with the ITS, System Expansion Program (SEP), Terrace, Southern Access, Line 4, Alberta Clipper and Southern Lights Pipeline 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 included in subsequent years’ tolls. In addition, other tolling deferrals are recorded in accordance with the various agreements.

4 A 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 2013 and end in 2043.

5 The future removal and site restoration reserves balance results from amounts collected from customers by certain of the Company’s businesses, with the approval of the regulator, to fund future costs for removal and site restoration relating to property, plant and equipment. These costs are collected as part of depreciation charged on property, plant and equipment. The balance represents the amount that has been collected from customers, net of actual costs expended on removal and site restoration. The settlement of this balance will occur as future removal and site restoration costs are incurred. In the absence of rate regulation, costs incurred for removal and site restoration would be charged to earnings as incurred with recognition of revenue for amounts previously collected.

6 Purchased gas variance is the difference between the actual cost and the approved cost of natural gas reflected in rates. EGD has been granted OEB approval to refund this balance to customers in the following year. In the absence of rate regulation the actual cost of natural gas would be included in commodity costs and commodity sales would be adjusted by an equal and corresponding amount as the right to collect revenue has been established.

7 The pension plan balance represents the regulatory offset to the pension asset to the extent that the amounts are to be refunded to customers in future rates. The other post employment benefits (OPEB) balance represents the regulatory offset to the OPEB liability to the extent that the amounts are to be collected in future rates. The settlement periods for these balances are not determinable. EGD continues to record and recover pension and OPEB expenditures through rates on a cash basis. In the absence of rate regulation, these regulatory balances would not be recorded and pension and OPEB expense would be charged to earnings based on the accrual basis of accounting.

8 Deferred 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 2012 and for Vector Pipeline beginning in 2008. This regulatory asset is not included in the rate base.

OTHER ITEMS AFFECTED BY RATE REGULATION

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

With the approval of the OEB, 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 operating costs may be charged to earnings in the year incurred.

EGD entered into a consulting contract relating to asset management initiatives. The majority of the costs, primarily consulting fees, are being capitalized to gas mains in accordance with regulatory approval. At December 31, 2010, cumulative costs relating to this consulting contract of $124 million (2009 - $112 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, some of these costs would be charged to earnings in the year incurred.

6. GAIN ON SALE OF INVESTMENTS

December 31,	2010	2009	2008
(millions of Canadian dollars)
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 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 Gas Pipelines, Processing and Energy 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 and are included in the Gas Pipelines, Processing and Energy Services operating segment. Operating cash flows generated by the CLH investment for the year ended December 31, 2008 were $12 million.

7. ACCOUNTS RECEIVABLE AND OTHER

December 31,	2010		2009
(millions of Canadian dollars)
Unbilled revenues	1,284		1,018
Trade receivables	740		681
Taxes receivable	205		94
Regulatory assets	182		181
Current derivative assets (Note 23)	170		128
Due from affiliates (Note 30)	63		336
Prepaid expenses and deposits	36		27
Dividends receivable	16		14
Other	72		79
Allowance for doubtful accounts (Note 23)	(62	)	(74	)
	2,706		2,484

8. INVENTORY

December 31,	2010	2009
(millions of Canadian dollars)
Natural gas	537	492
Other commodities	276	292
	813	784

9. PROPERTY, PLANT AND EQUIPMENT

December 31, 2010	Weighted Average Depreciation Rate	Cost	Accumulated Depreciation	Net
(millions of Canadian dollars)
Liquids Pipelines
Pipeline	2.7%	7,295	1,618	5,677
Pumping equipment, buildings, tanks and other	3.6%	4,728	1,221	3,507
Land and right-of-way	1.8%	232	29	203
Under construction	-	728	-	728
		12,983	2,868	10,115
Gas Distribution
Pipeline	2.3%	29	10	19
Gas mains, services and other	3.6%	6,576	1,262	5,314
Land and right-of-way	2.6%	68	15	53
Under construction	-	103	-	103
		6,776	1,287	5,489
Gas Pipelines, Processing and Energy Services
Pipeline	3.4%	2,121	706	1,415
Wind turbines, solar panels and other	3.1%	1,527	142	1,385
Land and right-of-way	2.4%	62	13	49
Under construction	-	622	-	622
		4,332	861	3,471
Sponsored Investments
Pipeline	4.0%	1,598	484	1,114
Other	8.5%	108	29	79
Under construction	-	17	-	17
		1,723	513	1,210
Corporate
Other	11.3%	67	20	47
		67	20	47
		25,881	5,549	20,332

	Weighted Average		Accumulated
December 31, 2009	Depreciation Rate	Cost	Depreciation	Net
(millions of Canadian dollars)
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
Gas Distribution
Pipeline	2.3%	21	5	16
Gas mains, services and other	3.8%	6,122	982	5,140
Land and right-of-way	5.0%	49	8	41
Under construction	-	111	-	111
		6,303	995	5,308
Gas Pipelines, Processing and Energy Services
Pipeline	3.4%	2,104	679	1,425
Wind turbines, solar panels and other	3.8%	890	108	782
Land and right-of-way	2.9%	48	13	35
Under construction	-	321	-	321
		3,363	800	2,563
Sponsored Investments
Pipeline	4.6%	1,406	368	1,038
Other	6.9%	108	18	90
Under construction	-	31	-	31
		1,545	386	1,159
Corporate
Other	11.3%	77	17	60
		77	17	60
		23,617	4,767	18,850

10. JOINT VENTURES

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

	Ownership	Net Assets
December 31,	Interest	2010	2009
(millions of Canadian dollars)
Liquids Pipelines
Chicap Pipeline	43.8%	27	9
Mustang Pipeline	30%	26	22
Olympic Pipeline	85% (2009 - 65%)	-	111
Hardisty Caverns	100% (2009 - 50%)	-	33
Gas Pipelines, Processing and Energy Services
Enbridge Offshore Pipelines - various joint ventures	22%-74.3%	433	385
Vector Pipeline	60%	349	420
Alliance Pipeline US	50%	318	383
Aux Sable	42.7%-50%	86	153
Other	33.3%-70%	50	32
Sponsored Investments
Alliance Pipeline Canada	50%	660	676
Other	33%-50%	56	46
		2,005	2,270

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

Year ended December 31,	2010		2009		2008
(millions of Canadian dollars)
Earnings
Revenues	771		781		891
Commodity costs	(92	)	(74	)	(174	)
Operating and administrative	(203	)	(226	)	(235	)
Depreciation and amortization	(163	)	(171	)	(173	)
Interest expense	(82	)	(99	)	(97	)
Other income/(expense)	(1	)	10		13
Proportionate share of earnings	230		221		225
Cash Flows
Cash provided by operating activities	349		342		408
Cash used in investing activities	(57	)	(49	)	(61	)
Cash used in financing activities	(78	)	(133	)	(121	)
Proportionate share of increase in cash and cash equivalents	214		160		226

December 31,	2010		2009
(millions of Canadian dollars)
Financial Position
Current assets	171		173
Property, plant and equipment, net	2,331		2,657
Intangible assets	166		188
Goodwill	321		321
Deferred amounts and other assets	270		299
Current liabilities	(150	)	(212	)
Non-recourse long-term debt	(1,061	)	(1,108	)
Other long-term liabilities	(43	)	(48	)
Proportionate share of net assets	2,005		2,270

During the year ended December 31, 2010, the Company acquired an additional 20% interest in Olympic Pipeline Company (Olympic Pipeline), a refined products pipeline, for $12 million, increasing its ownership interest to 85%. As the Company now controls the entity, it has consolidated its interest in Olympic Pipeline. Prior to August 9, 2010, the entity was accounted for as a joint venture.

During the year ended December 31, 2010, the Company acquired the remaining 50% interest in Hardisty Caverns Limited Partnership (Hardisty Caverns), an oil storage facility, for $52 million, increasing its ownership interest to 100%. As the Company now controls the entity, it has consolidated its interest in Hardisty Caverns. Prior to June 16, 2010, the entity was accounted for as a joint venture.

During the year ended December 31, 2009, the Company purchased the additional 50% interest in Starfish Pipeline Company, LLC (Starfish Pipeline), increasing its ownership percentage to 100%. As the Company established control over the entity effective December 31, 2009, it has consolidated its interest in Starfish Pipeline 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 Company (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.

11. LONG-TERM INVESTMENTS

	Ownership
December 31,	Interest	2010	2009
(millions of Canadian dollars)
Equity Investments
Sponsored Investments
The Partnership	25.5%	1,473	1,697
Enbridge Energy, L.P. - Series AC	66.7%	463	357
Corporate
Noverco Inc. Common Shares	32.1%	14	14
Other	5%-14%	13	9
Other Investments
Corporate
Noverco Inc. Preferred Shares		181	181
Value Creation Inc.		29	29
Fuel Cell Energy Ltd.		25	25
		2,198	2,312

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 $123 million at December 31, 2010 (2009 - $126 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.

The Partnership

The Partnership includes the Company’s investments in EEP and Enbridge Energy Management, L.L.C. (EEM). The Company has a combined 25.5% ownership in EEP, through a 2.0% general partner interest, an 18.1% interest in Class A units, a 3.0% interest in Class B units and a 2.4% interest in EEP as a result of a 17.2% investment in EEM, which owns 13.7% of EEP through its 100% interest in EEP’s i-units. The Company recorded investment income of $51 million (2009 - $175 million; 2008 - $162 million), inclusive of incentive earnings, and including dilution gains of $81 million (2009 - nil; 2008 - $12 million), before tax and non-controlling interest, from EEP for the year ended December 31, 2010.

During the year ended December 31, 2010, EEP issued Class A units and, because Enbridge did not fully participate in this issuance, a dilution gain of $81 million, before tax and non-controlling interest, was recognized and Enbridge’s ownership interest in EEP decreased from 27.0% to 25.5%.

Although 82.8% of EEM is widely held, the Company has voting control and therefore consolidates its investment in EEM.

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 $12 million, before tax and non-controlling interest, 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%.

Enbridge Energy, L.P.

The Company has a 66.7% interest in the series AC units of EELP, which constructed the United States segment of the Alberta Clipper project (Note 30). The Company recorded investment income from EELP of $63 million for the year ended December 31, 2010 (2009 - $12 million).

During 2010, the Board of Directors of Enbridge Energy Management, L.L.C. declared distributions of $40 million (US$39 million) payable to the Company relating to its series AC interest in the Alberta Clipper project.

Noverco

The Company owns a preferred share investment in Noverco of $181 million at December 31, 2010 and 2009, 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, 2010 (2009 - $14 million). Noverco owns an approximate 9.0% (2009 - 9.2%) reciprocal shareholding in the shares of the Company. As a result, the Company has an indirect pro-rata interest of 2.9% (2009 - 2.9%) 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, 2010 and 2009. Noverco records dividends paid by the Company as dividend income and the Company eliminates these dividends from its equity 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 2010, the Company recorded equity investment earnings of $6 million (2009 - $10 million; 2008 - $4 million) related to its interest in Noverco.

Subsequent to December 31, 2010, the Company announced that it will invest $145 million to acquire an additional 6.8% interest in Noverco, bringing its total investment in Noverco to 38.9%.

12. DEFERRED AMOUNTS AND OTHER ASSETS

December 31,	2010	2009
(millions of Canadian dollars)
Regulatory assets	1,514	1,419
Long-term portion of derivative assets (Note 23)	462	485
Affiliate long-term note receivable (Note 30)	334	-
Pension asset (Note 27)	301	216
Contractual receivables	182	171
Other	93	134
	2,886	2,425

At December 31, 2010, deferred amounts of $66 million (2009 - $71 million) were subject to amortization and are presented net of accumulated amortization of $39 million (2009 - $34 million). Amortization expense in 2010 was $9 million (2009 - $7 million; 2008 - $5 million).

13. INTANGIBLE ASSETS

	Weighted Average		Accumulated
December 31, 2010	Amortization Rate	Cost	Amortization	Net
(millions of Canadian dollars)
Software	13.4%	457	172	285
Transportation agreements	4.2%	231	66	165
Power purchase agreements and other	5.0%	33	5	28
		721	243	478

	Weighted Average		Accumulated
December 31, 2009	Amortization Rate	Cost	Amortization	Net
(millions of Canadian dollars)
Software	17.1%	448	159	289
Transportation agreements	4.2%	232	56	176
Power purchase agreements and other	5.0%	27	4	23
		707	219	488

Total amortization expense for intangible assets was $60 million for the year ended December 31, 2010 (2009 - $44 million; 2008 - $58 million). Assuming no asset additions or impairments, the Company expects aggregate amortization expense for the years ending December 31, 2011 through 2015 of $47 million, $41 million, $36 million, $32 million and $28 million, respectively.

14. GOODWILL

	Liquids Pipelines		Gas Distribution	Gas Pipelines, Processing and Energy Services		Sponsored Investments	Corporate	Consolidated
(millions of Canadian dollars)
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
Foreign exchange and other	(1	)	-	(3	)	-	-	(4	)
Business acquisition	17		-	-		-	-	17
Balance at December 31, 2010	35		-	42		308	-	385

In 2010, the Company recognized $17 million of goodwill on the acquisition of the remaining 50% interest in Hardisty Caverns. In 2009, the Company recognized an impairment of $7 million on goodwill related to Enbridge Electric Connections Inc.

15. ACCOUNTS PAYABLE AND OTHER

December 31,	2010	2009
(millions of Canadian dollars)
Operating accrued liabilities	1,621	1,313
Trade payables	232	415
Construction payables	253	163
Taxes payable	156	103
Current derivative liabilities (Note23)	138	123
Security deposits	78	60
Contractor holdbacks	78	108
Other	132	178
	2,688	2,463

16. DEBT

	Weighted Average
December 31,	Interest Rate	Maturity	2010	2009
(millions of Canadian dollars)
Liquids Pipelines
Debentures	8.20%	2024	200	200
Medium-term notes	5.05%	2012-2040	2,425	1,525
Southern Lights project financing1	2.54%	2012-2014	1,488	1,531
Commercial paper and credit facility draws, net2			36	874
Other3			15	15
Gas Distribution
Debentures	10.46%	2011-2024	235	385
Medium-term notes	5.54%	2014-2050	2,195	1,795
Commercial paper and credit facility draws, net			334	512
Sponsored Investments
Medium-term notes	5.03%	2014-2020	290	90
Credit facility draws, net			130	197
Corporate
U.S. dollar term notes4	5.48%	2014-2017	1,094	1,151
Medium-term notes	5.25%	2013-2040	2,918	2,568
Commercial paper and credit facility draws, net5			2,776	2,235
Deferred debt issue costs and other			(95)	(103)
Total Debt			14,041	12,975
Current Maturities			(154)	(601)
Short-Term Borrowings	1.14%		(326)	(508)
Long-Term Debt			13,561	11,866

1	2010 - $388 million and US$1,106 million (2009 - $385 million and US$1,095 million).

2	2010 - $26 million and US$10 million (2009 - $874 million).

3	Primarily capital lease obligations.

4	2010 - US$1,100 (2009 - US$1,100).

5	2010 - $2,515 million and US$265 million (2009 - $1,973 million and US$250 million).

Debenture and term note maturities for the years ending December 31, 2011 through 2015 are $154 million, $250 million, $201 million, $889 million and $549 million, respectively. The Company’s debentures and term notes bear interest at fixed rates and the interest obligations for the years ending December 31, 2011 through 2015 are $511 million, $504 million, $487 million, $466 million and $426 million, respectively.

INTEREST EXPENSE

Year ended December 31,	2010	2009	2008
(millions of Canadian dollars)
Debentures and term notes	578	494	417
Non-recourse long-term debt (Note 17)	75	83	87
Commercial paper and credit facility draws	63	71	100
Southern Lights project financing	37	45	28
Capitalized	(66)	(96)	(81)
	687	597	551

CREDIT FACILITIES

December 31, 2010		Expiry Dates2	Total Facilities	Credit Facility Draws3	Available
(millions of Canadian dollars)
Liquids Pipelines		2012	200	26	174
Gas Distribution		2011-2012	717	334	383
Sponsored Investments		2012	300	130	170
Corporate		2012-2014	4,631	2,826	1,805
			5,848	3,316	2,532
Southern Lights project financing1		2012-2014	1,697	1,504	193
Total Credit Facilities			7,545	4,820	2,725
1	Total facilities inclusive of $60 million for debt service reserve letters of credit.

2	Includes $30 million in demand facilities with no maturity date.

3	Includes facility draws, letters of credit and commercial paper issuances, that are backstopped by the credit facility.

Credit facilities carry a weighted average standby fee of 0.20% 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 2011 to 2014.

Commercial paper and credit facility draws, net of short-term borrowings, of $2,950 million (2009 - $3,310 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

December 31,		Weighted Average Interest Rate	Maturity	2010	2009
(millions of Canadian dollars)
Gas Pipelines, Processing and Energy Services
Long-term credit facilities1			2012	1	1
Senior notes2		6.79%	2015-2025	347	400
Term debt3		3.81%	2011-2019	29	24
Capital lease obligations		11.27%	2020	32	36
Sponsored Investments
Credit facilities			2012	23	25
Senior notes		6.68%	2015-2025	675	708
Fair value increment on senior notes acquired				29	33
Deferred debt issue costs and other				(5)	(6)
Total Non-Recourse Debt				1,131	1,221
Current Maturities				(70)	(113)
Non-Recourse Long-Term Debt				1,061	1,108
1	2010 - US$1 million (2009 - US$1 million).

2	2010 - US$349 million (2009 - US$382 million).

3	2010 - US$24 million (2009 - US$23 million).

Maturities on non-recourse borrowings for the years ending December 31, 2011 through 2015 are $70 million, $94 million, $77 million, $80 million and $80 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, 2011 through 2015 are $71 million, $66 million, $61 million, $56 million and $50 million, respectively.

Certain assets of Alliance Pipeline Canada, with a carrying value of $1,006 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 $722 million, are pledged as collateral to Alliance Pipeline US’s lenders and to the lenders to Alliance Pipeline Canada.

18. OTHER LONG-TERM LIABILITIES

December 31,	2010	2009
(millions of Canadian dollars)
Future removal and site restoration reserves (Note 5)	773	710
Regulatory liabilities	198	138
Derivative liabilities (Note 23)	133	42
Other post-employment benefit liabilities (Note 27)	118	110
Other	251	207
	1,473	1,207

19. NON-CONTROLLING INTERESTS

December 31,	2010	2009
(millions of Canadian dollars)
EEM	394	424
EIF	109	134
EGD Preferred Shares	100	100
EGNB	-	54
Talbot Windfarm, LP (Talbot)	26	9
Greenwich Windfarm, LP (Greenwich)	12	-
Other	17	6
	658	727

Non-controlling interests in EEM represents the 82.8% of the listed shares of EEM not held by the Company. Non-controlling interests in EIF represents 58.1% of interests that are held by third parties.

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, 2010, no preferred shares have been redeemed.

During the year ended December 31, 2010, the Company acquired the remaining 27.5% of EGNB limited partnership units held by third parties for $52 million, increasing its partnership interest to 100%.

Non-controlling interests in both Talbot and Greenwich represent 10.0% of partnership units held by a third party.

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

	2010		2009		2008
December 31	Number of Shares	Amount	Number of Shares	Amount	Number of Shares	Amount
(millions of Canadian dollars,
number of common shares in millions)
Balance at beginning of year	378	3,379	373	3,194	369	3,027
Common shares issued	-	-	-	4	-	-
Shares issued on exercise of stock options	3	80	1	38	1	36
Dividend Reinvestment and Share
Purchase Plan	4	224	4	143	3	131
Balance at end of year	385	3,683	378	3,379	373	3,194

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 (2009 - 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.

December 31,	2010	2009	2008
(number of common shares in millions)
Weighted average shares outstanding	370	364	360
Effect of dilutive options	4	2	3
Diluted weighted average shares outstanding	374	366	363

For the year ended December 31, 2010, 46,000 anti-dilutive stock options (2009 – 556,500; 2008 – 2,879,800) with a weighted average exercise price of $55.68 (2009 - $40.98; 2008 - $40.53) 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 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 PSU Plan and the RSU Plan. A maximum of 30 million common shares were reserved for issuance under the 2002 ISO plan, of which 20 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 0.3 million 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, 2010 for ISOs is $11 million (2009 - $17 million; 2008 - $13 million).

Outstanding Incentive Stock Options

	2010		2009		2008
December 31,	Number	Weighted Average Exercise Price	Number	Weighted Average Exercise Price	Number	Weighted Average Exercise Price
(options in thousands;
exercise price in Canadian dollars)
Options at beginning of year	12,466	34.01	10,650	31.05	9,237	27.24
Options granted	2,000	45.40	3,028	39.62	2,642	40.54
Options exercised	(1,718)	29.04	(1,187)	22.01	(1,178)	21.85
Options cancelled or expired	(18)	24.89	(25)	40.65	(51)	36.83
Options at end of year	12,730	36.48	12,466	34.01	10,650	31.05
Options vested	6,882	32.01	6,550	28.96	6,087	25.32

The total intrinsic value of ISOs exercised during the year ended December 31, 2010 was $38 million (2009 - $22 million; 2008 - $23 million) and cash received on exercise was $50 million (2009 - $26 million; 2008 - $26 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, 2010 was $182 million (2009 - $81 million) and $131 million (2009 - $76 million), respectively.

Incentive Stock Option Characteristics

December 31, 2010

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

(options in thousands;

exercise price in Canadian dollars)

15.00-19.99

222

0.1

19.10

222

0.1

19.10

20.00-24.99

1,399

1.7

21.27

1,399

1.7

21.27

25.00-29.99

851

3.1

25.72

851

3.1

25.72

30.00-34.99

1,487

5.7

31.68

1,017

4.6

31.74

35.00-39.99

4,336

7.0

38.55

2,262

6.1

37.75

40.00-44.99

2,783

7.4

40.82

1,131

7.1

40.39

45.00-49.99

1,606

9.1

46.59

55.00-59.99

9.9

55.68

12,730

6.2

36.48

6,882

4.6

32.01

The total fair value of options vested under the ISO Plan during the year ended December 31, 2010 was $14 million (2009 - $13 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,		2010	2009	2008
Fair value per option (Canadian dollars)1		6.88	7.12	6.14
Valuation assumptions
Expected option term (years)2		6	6	6
Expected volatility3		19.72%	28.08%	18.48%
Expected dividend yield4		3.64%	3.87%	3.34%
Risk-free interest rate5		2.70%	2.24%	3.50%
1	Options granted to United States employees are based on New York Stock Exchange (NYSE) prices. The option value and assumptions shown are based on a weighted average of the United States options and the Canadian options. The fair values per option were $6.56 (2009 - $6.73; 2008 - $6.20) for Canadian employees and US$8.00 (2009 - US$6.86; 2008 - US$5.82) for United States employees.

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

3	Expected volatility is determined with reference to historic daily share price volatility and beginning in 2010, implied volatility observable in call option values near the grant date.

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

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

As of December 31, 2010, unrecognized compensation cost related to non-vested share-based compensation arrangements granted under the ISO plan was $16 million. The cost is expected to be fully recognized by December 31, 2013.

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 under the 2002 plan and on August 15, 2007 and February 19, 2008 under the 2007 plan. All performance and time vesting conditions on the 2002 grant were met prior to the term of the options expiring on September 16, 2010. All performance targets for the 2007 and 2008 grants have been met. The time vesting requirements will be fulfilled evenly over a five year period ending on August 15, 2012 with the options being exercisable until August 15, 2015. Compensation expense recorded for the year ended December 31, 2010 for PBSOs was $2 million (2009 - $2 million; 2008 - $2 million).

Outstanding Performance Based Stock Options


December 31,	2010			2009			2008
	Number		Weighted Average Exercise Price	Number		Weighted Average Exercise Price	Number		Weighted Average Exercise Price
(options in thousands;
exercise price in Canadian dollars)
Options at beginning of year	3,395		33.69	3,738		32.72	3,588		31.92
Options granted	-		-	-		-	250		40.42
Options exercised	(1,039	)	26.24	(343	)	23.15	(100	)	23.15
Options cancelled	(209	)	36.57	-		-	-		-
Options at end of year	2,147		37.02	3,395		33.69	3,738		32.72
Options vested	1,262		36.88	800		23.15	1,143		23.15

The total intrinsic value of PBSOs exercised during the year ended December 31, 2010 was $26 million (2009 - $6 million; 2008 - $2 million) and cash received on exercise was $27 million (2009 - $8 million; 2008 - $2 million). The total intrinsic value of PBSOs outstanding and vested at December 31, 2010 is $30 million (2009 - $23 million) and $18 million (2009 - $14 million), respectively.

Performance Based Stock Option Characteristics

December 31, 2010

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

(options in thousands;

exercise price in Canadian dollars)

36.57

1,897

4.6

36.57

1,162

4.6

36.57

40.42

250

4.6

40.42

100

4.6

40.42

2,147

4.6

37.02

1,262

4.6

36.88

The total fair value of options vested under the PBSO Plan during the year ended December 31, 2010 was $2 million (2009 - $2 million; 2008 - $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
Fair value per option (Canadian dollars)		4.82
Valuation assumptions
Expected option term (years)1		8
Expected volatility2		13.60%
Expected dividend yield3		3.32%
Risk-free interest rate4		3.75%
1	Expected option term is based on historical information.

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

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

4	The 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, 2010, unrecognized compensation cost related to non-vested share-based compensation arrangements granted under the PBSO plan was $3 million. The cost is expected to be fully recognized by December 31, 2012.

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 for 20 days prior to the maturity of the grant 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 2008, 2009 and 2010 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 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, 2010 for PSUs was $27 million (2009 - $20 million; 2008 - $13 million). To calculate the 2010 expense, multipliers of two, based upon multiplier estimates at December 31, 2010, were used for each of the 2008, 2009 and 2010 PSU grants.

Outstanding Performance Stock Units

December 31,	2010		2009		2008
Units at beginning of year	330,416		295,428		267,616
Units granted	286,200		169,600		144,300
Units cancelled	-		-		-
Units matured	(159,817	)	(151,882	)	(129,852	)
Dividend reinvestment	21,148		17,270		13,364
Units at end of year	477,947		330,416		295,428

Of the PSUs outstanding at December 31, 2010, 181,932 units have a performance period ending December 31, 2011 and 296,015 have a performance period ending December 31, 2012. The total intrinsic value of PSUs outstanding at December 31, 2010 is $56 million (2009 - $47 million; 2008 - $21 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 for 20 days prior to the maturity of the grant multiplied by the units outstanding on the maturity date. Compensation expense recorded for the year ended December 31, 2010 for RSUs was $29 million (2009 - $23 million; 2008 - $15 million).

Outstanding Restricted Stock Units

December 31,	2010		2009		2008
Units at beginning of year	987,877		700,034		456,621
Units granted	468,600		543,500		418,700
Units cancelled	(30,454	)	(18,429	)	(23,352	)
Units matured	(427,752	)	(282,656	)	(179,940	)
Dividend reinvestment	49,714		45,428		28,005
Units at end of year	1,047,985		987,877		700,034

The total intrinsic value of RSUs outstanding at December 31, 2010 is $63 million (2009 - $50 million; 2008 - $29 million).

As of December 31, 2010, unrecognized compensation expense related to non-vested units granted under the PSU and RSU plans was $62 million and is expected to be fully recognized by December 31, 2012.

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

	Net Investment Hedges		Cumulative Translation Adjustment		Equity Investees		Non-Controlling Interests		Cash Flow Hedges		Total
(millions of Canadian dollars)
Balance at January 1, 2008	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	)
Changes during the year	61		(274	)	(18	)	33		(133	)	(331	)
Tax impact	(10	)	-		7		-		(5	)	(8	)
	51		(274	)	(11	)	33		(138	)	(339	)
Balance at December 31, 2010	480		(1,364	)	(43	)	122		(77	)	(882	)

23. RISK MANAGEMENT

MARKET PRICE RISK

The Company’s earnings, cash flows and OCI are subject to movements in foreign exchange rates, interest rates, commodity prices and the Company’s share price (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 operate within 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’s Corporate Financial Risk Management Committee (CFRMC) establishes and monitors the EaR limits on a monthly basis. Compliance with EaR limits is reported to the CFRMC and variances are remediated as necessary.

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.

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 investments and subsidiaries. The Company has implemented a policy where it economically hedges 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, 2010, would have resulted in a $81 million increase (2009 - $92 million) to earnings. The foreign exchange sensitivity analysis is limited to changes in the fair value of financial instruments, external debt and loans to non-consolidated foreign operations within the Company that are not denominated in the Company’s functional currency and are not considered a net investment. A sensitivity analysis excludes financial instruments that are not monetary items and the impact of translating the Company’s United States dollar denominated self-sustaining subsidiaries on OCI, therefore a sensitivity analysis on the impacts to OCI is considered unrepresentative of the inherent risk to 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, primarily commercial paper. 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 2014 at an average rate of 2.1%.

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 program to significantly mitigate its exposure to long term interest rate variability on select forecast term debt issuances through 2014. A total of $2,000 million of future fixed rate term debt issuances have been hedged at an average government bond rate of 4.4%. 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 maintain a consolidated portfolio of debt which 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.

At December 31, 2010, a 1% increase across the interest rate yield curve at that date, with all other variables constant, would not have had an impact (2009 - $2 million increase) in earnings and would have caused a $178 million increase (2009 - $197 million increase) in OCI in the year due to the revaluation of interest rate derivatives outstanding at December 31, 2010, and a $22 million decrease (2009 - $26 million decrease) in earnings due to increased interest expense related to the Company’s variable rate debt outstanding at December 31, 2010 assuming the variable rate debt outstanding had been outstanding for the entire period.

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 and investments, 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 program to 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.

The Company has defined EaR limits for different components of businesses exposed to commodity price risk. The calculation of these limits reflect 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. The Company has estimated the following maximum adverse change in projected 12 month earnings that has a maximum 2.5% chance of resulting from commodity price risk over a one month period:

	2010	2009
(millions of Canadian dollars)
Average EaR during the year	22	22
High EaR during the year	29	32
Low EaR during the year	16	16
Closing EaR at year end	25	19

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, 2010 or December 31, 2009.

December 31, 2010	Derivative Instruments Used as Cash Flow Hedges		Derivative Instruments Used as Net Investment Hedges	Non-Qualifying Derivative Instruments		Total Derivative Instruments
(millions of Canadian dollars)
Accounts receivable and other (Note 7)
Foreign exchange contracts	4		15	111		130
Interest rate contracts	6		-	-		6
Commodity contracts	-		-	33		33
Other contracts	-		-	1		1
	10		15	145		170
Deferred amounts and other (Note 12)
Foreign exchange contracts	18		100	275		393
Interest rate contracts	67		-	-		67
Commodity contracts	-		-	2		2
	85		100	277		462
Accounts payable and other (Note 15)
Foreign exchange contracts	(4	)	-	(11	)	(15	)
Interest rate contracts	(72	)	-	-		(72	)
Commodity contracts	-		-	(51	)	(51	)
	(76	)	-	(62	)	(138	)
Other long-term liabilities (Note 18)
Foreign exchange contracts	(47	)	-	(3	)	(50	)
Interest rate contracts	(80	)	-	-		(80	)
Commodity contracts	-		-	(3	)	(3	)
	(127	)	-	(6	)	(133	)
Total net derivative asset/(liability)
Foreign exchange contracts	(29	)	115	372		458
Interest rate contracts	(79	)	-	-		(79	)
Commodity contracts	-		-	(19	)	(19	)
Other contracts	-		-	1		1
	(108	)	115	354		361

December 31, 2009	Derivative Instruments Used as Cash Flow Hedges		Derivative Instruments Used as Net Investment Hedges	Non-Qualifying Derivative Instruments		Total Derivative Instruments
(millions of Canadian dollars)
Accounts receivable and other (Note 7)
Foreign exchange contracts	4		14	52		70
Interest rate contracts	34		-	2		36
Commodity contracts	-		-	22		22
	38		14	76		128
Deferred amounts and other (Note 12)
Foreign exchange contracts	25		80	285		390
Interest rate contracts	90		-	-		90
Commodity contracts	1		-	2		3
Other contracts	1		-	1		2
	117		80	288		485
Accounts payable and other (Note 15)
Foreign exchange contracts	(2	)	-	(3	)	(5	)
Interest rate contracts	(68	)	-	-		(68	)
Commodity contracts	(17	)	-	(33	)	(50	)
	(87	)	-	(36	)	(123	)
Other long-term liabilities (Note 18)
Foreign exchange contracts	(21	)	-	-		(21	)
Interest rate contracts	(15	)	-	-		(15	)
Commodity contracts	(4	)	-	(2	)	(6	)
	(40	)	-	(2	)	(42	)
Total net derivative asset/(liability)
Foreign exchange contracts	6		94	334		434
Interest rate contracts	41		-	2		43
Commodity contracts	(20	)	-	(11	)	(31	)
Other contracts	1		-	1		2
	28		94	326		448

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

	December 31, 2010		December 31, 2009
	Maturity	Notional Principal or Quantity Outstanding	Maturity	Notional Principal or Quantity Outstanding
U.S. dollar forwards - purchase (millions of United States dollars)	2011-2020	1,185	2010-2019	1,078
U.S. dollar forwards - sell (millions of United States dollars)	2011-2020	3,516	2010-2020	3,102
Interest rate contracts (millions of Canadian dollars)	2011-2029	10,772	2010-2029	6,022
Commodity contracts - Energy (bcfe)	2011-2013	41	2010-2011	464
Commodity contracts - Power (MW/H)	2011-2024	2	2010-2024	38

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.

Year ended December 31,	2010		2009
(millions of Canadian dollars)
Amount of Unrealized Gain/(Loss) Recognized in OCI
Cash Flow Hedges
Foreign exchange contracts	(25	)	(116	)
Interest rate contracts	(172	)	73
Commodity contracts	97		(37	)
Other contracts	(1	)	3
Net Investment Hedges
Foreign exchange contracts	19		24
Total unrealized loss recognized in OCI	(82	)	(53	)
Amount of Gain/(Loss) Reclassified from AOCI to Earnings
Foreign exchange contracts1	(7	)	(4	)
Interest rate contracts2	68		(31	)
Commodity contracts3	(95	)	(79	)
Other contracts	1		3
Total loss reclassified from AOCI to earnings	(33	)	(111	)

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

2 Gain/(loss) reported within Interest Expense in the Consolidated Statement of Earnings.

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

The Company estimates that $71 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 in effect when derivative contracts that are currently outstanding mature. For all significant forecasted transactions, the maximum term over which the Company is hedging exposures to the variability of cash flows is 48 months at December 31, 2010.

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.

Year ended December 31,	2010		2009		2008
(millions of Canadian dollars)
Foreign exchange contracts1	33		232		35
Interest rate contracts2	(2	)	2		-
Commodity contracts3	(5	)	(88	)	122
Total unrealized derivative fair value gain	26		146		157

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

2 Gain/(loss) reported within Interest Expense in the Consolidated Statement of Earnings.

3 Gain/(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 a twelve month rolling time period 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 long-term debt which includes debentures and medium-term notes. The Company maintains current shelf prospectuses with 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 at December 31, 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.

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).

For the years ending December 31, 2011 through 2015, and thereafter, the Company has estimated the following undiscounted cash flows will arise from its financial derivative instruments based on valuations at the balance sheet date:

	2011		2012		2013		2014		2015		Thereafter
(millions of Canadian dollars)
Cash inflows	256		136		151		152		59		43
Cash outflows	(224	)	(50	)	(45	)	(25	)	(4	)	(52	)
Net cash flows	32		86		106		127		55		(9	)

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 only enters into risk management transactions 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, 2010 and 2009, the Company had group credit concentrations and maximum credit exposure, with respect to derivative instruments, in the following geographic regions:

December 31,	2010		2009
(millions of Canadian dollars)
Canadian financial institutions	373		474
Non-Canadian financial institutions	(12	)	(26	)
	361		448

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 Gas Distribution segment is mitigated by the large and diversified customer base and the ability to recover an estimate for doubtful accounts for utility operations 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.

Year ended December 31,	2010		2009
(millions of Canadian dollars)
Balance at beginning of year	(74	)	(69	)
Additional allowance	(23	)	(29	)
Amounts used	35		24
Balance at end of year	(62	)	(74	)

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.

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, 2010	Held for Trading	Available for Sale1	Loans and Receivables	Held to Maturity	Other Financial Liabilities	Qualifying Derivatives	Non- Financial Instruments	Total	Fair Value2
(millions of Canadian dollars)
Assets
Cash and cash equivalents	242	-	-	-	-	-	-	242	242
Accounts receivable and other	145	-	2,113	-	-	25	423	2,706	2,283
Long-term investments	-	54	339	181	-	-	1,624	2,198	520
Deferred amounts and other assets	277	-	334	-	-	185	2,090	2,886	462
Liabilities
Short-term borrowings	-	-	-	-	326	-	-	326	326
Accounts payable and other	62	-	-	-	2,393	76	157	2,688	2,531
Interest payable	-	-	-	-	117	-	-	117	117
Long-term debt	-	-	-	-	13,715	-	-	13,715	14,770
Non-recourse long-term debt	-	-	-	-	1,131	-	-	1,131	1,298
Other long-term liabilities	6	-	-	-	-	127	1,340	1,473	133

December 31, 2009	Held for Trading	Available for Sale1	Loans and Receivables	Held to Maturity	Other Financial Liabilities	Qualifying Derivatives	Non- Financial Instruments	Total	Fair Value2
(millions of Canadian dollars)
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	-	-	-	2,237	87	103	2,463	2,360
Interest payable	-	-	-	-	104	-	-	104	104
Long-term debt	-	-	-	-	12,467	-	-	12,467	13,773
Non-recourse long-term debt	-	-	-	-	1,221	-	-	1,221	1,250
Other long-term liabilities	2	-	-	-	-	40	1,165	1,207	42

1 Classified as Other Investments carried at Cost under U.S. GAAP.

2 Fair value does not include non-financial instruments, which includes investments accounted for under the equity method, available for sale equity instruments held at cost that do not trade on an actively quoted market and affiliate long-term notes receivable resulting from related party transactions carried at historical cost.

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 estimated to be 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 financial assets carried as 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.

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 derivatives 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 a derivative 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 derivatives used to mitigate the risk of crude oil price fluctuations in the Gas Pipelines, Processing and Energy Services segment.

Level 2

Level 2 includes derivative valuations determined using directly or indirectly observable inputs other than quoted prices included within Level 1. Derivatives 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. Derivatives 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 Gas Pipelines, Processing and Energy Services and Corporate segments.

Level 3

Level 3 includes derivative valuations based on inputs which are less observable, unavailable or where the observable data does not support a significant portion of the derivatives’ fair value. Generally, Level 3 derivatives 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 derivatives based on extrapolation of observable future prices and rates. Derivatives valued using Level 3 inputs include long-dated derivative power contracts and NGL and natural gas contracts in the Gas Pipelines, Processing and Energy Services segment.

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.

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

December 31, 2010	Level 1		Level 2		Level 3		Total
(millions of Canadian dollars)
Financial assets:
Current derivative assets
Foreign exchange contracts	-		130		-		130
Interest rate contracts	-		6		-		6
Commodity contracts	-		5		28		33
Other contracts	-		-		1		1
	-		141		29		170
Long-term derivative assets
Foreign exchange contracts	-		393		-		393
Interest rate contracts	-		67		-		67
Commodity contracts	-		-		2		2
	-		460		2		462
Financial liabilities:
Current derivative liabilities
Foreign exchange contracts	-		(15	)	-		(15	)
Interest rate contracts	-		(72	)	-		(72	)
Commodity contracts	(9	)	(2	)	(40	)	(51	)
	(9	)	(89	)	(40	)	(138	)
Long-term derivative liabilities
Foreign exchange contracts	-		(50	)	-		(50	)
Interest rate contracts	-		(80	)	-		(80	)
Commodity contracts	-		(1	)	(2	)	(3	)
	-		(131	)	(2	)	(133	)
Total net derivative asset/(liability)
Foreign exchange contracts	-		458		-		458
Interest rate contracts	-		(79	)	-		(79	)
Commodity contracts	(9	)	2		(12	)	(19	)
Other contracts	-		-		1		1
	(9	)	381		(11	)	361

December 31, 2009	Level 1		Level 2		Level 3		Total
(millions of Canadian dollars)
Financial assets:
Current derivative assets
Foreign exchange contracts	-		70		-		70
Interest rate contracts	-		36		-		36
Commodity contracts	2		-		20		22
	2		106		20		128
Long-term derivative assets
Foreign exchange contracts	-		390		-		390
Interest rate contracts	-		90		-		90
Commodity contracts	-		-		3		3
Other contracts	-		2		-		2
	-		482		3		485
Financial liabilities:
Current derivative liabilities
Foreign exchange contracts	-		(5	)	-		(5	)
Interest rate contracts	-		(68	)	-		(68	)
Commodity contracts	(2	)	-		(48	)	(50	)
	(2	)	(73	)	(48	)	(123	)
Long-term derivative liabilities
Foreign exchange contracts	-		(21	)	-		(21	)
Interest rate contracts	-		(15	)	-		(15	)
Commodity contracts	-		(3	)	(3	)	(6	)
	-		(39	)	(3	)	(42	)
Total net derivative asset/(liability)
Foreign exchange contracts	-		434		-		434
Interest rate contracts	-		43		-		43
Commodity contracts	-		(3	)	(28	)	(31	)
Other contracts	-		2		-		2
	-		476		(28	)	448

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

Year ended December 31,	2010		2009
(millions of Canadian dollars)
Level 3 net derivative asset/(liability) at beginning of year	(28	)	53
Total gains/(losses), unrealized
Included in earnings1	19		(27	)
Included in OCI	3		7
Settlements	(5	)	(61	)
Level 3 net derivative liability at end of year	(11	)	(28	)

1 Gain/(loss) reported within Commodity Costs in the Consolidated Statement of Earnings.

2 The Company’s policy is to recognize transfers as of the last day of the reporting period. There were no transfers between levels as of December 31, 2010 or 2009.

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 proportionately consolidated from joint venture interests, is excluded from the Company’s definition of capital as it is not controlled or managed exclusively by the Company.

The Company’s capital is calculated as follows:

December 31,	2010		2009
(millions of Canadian dollars)
Short-term borrowings	326		508
Long-term debt (includes current portion)	13,810		12,570
Non-controlling interests	658		727
Shareholders’ equity1	8,601		7,958
Cash and cash equivalents	(172	)	(258	)
	23,223		21,505

1 Excludes 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 while maintaining safety and reliability; 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, 2010, including short-term borrowings but excluding non-recourse short and long-term debt, was 65.0% compared with 64.1% at the end of 2009.

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 and an unconsolidated debt to unconsolidated shareholders’ equity ratio of less than 1.5. As at December 31, 2010, 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, 2010, the Company was in compliance with this covenant.

26. INCOME TAXES

INCOME TAX RATE RECONCILIATION

Year ended December 31,	2010		2009		2008
(millions of Canadian dollars)
Earnings before income taxes	1,221		1,868		1,837
Combined statutory income tax rate	28.9%		30.5%		31.3%
Income taxes at statutory rate	353		570		575
Increase/(decrease) resulting from:
Future income taxes related to regulated operations	(62	)	(68	)	(15	)
Higher/(lower) foreign tax rates	(22	)	(61	)	3
Tax rates and legislated tax changes	(23	)	(58	)	(11	)
Non-taxable items, net	(2	)	11		2
Sale of investments	-		(99	)	(82	)
Other	7		11		37
Income taxes	251		306		509
Effective income tax rate	20.6%		16.4%		27.7%

COMPONENTS OF FUTURE INCOME TAXES

December 31,	2010		2009
(millions of Canadian dollars)
Net Future Income Tax Liabilities/(Assets)
Differences in accounting and tax bases of property, plant and equipment	1,468		1,346
Differences in accounting and tax bases of investments	479		407
Regulatory assets/(liabilities)	340		319
Financial instruments	105		121
Loss carryforwards	(81	)	(138	)
Other	56		29
Net Future Income Tax Liability	2,367		2,084

Net future income tax liability of $2,367 million (2009 - $2,084 million) is comprised of future income tax liabilities of $2,447 million (2009 - $2,211 million) net of future income tax assets of $80 million (2009 - $127 million).

At December 31, 2010, the Company has recognized the benefit of unused tax loss carryforwards of $248 million (2009 - $425 million) of which $246 million start to expire in 2019 and beyond.

GEOGRAPHICAL COMPONENTS OF PRETAX EARNINGS AND INCOME TAXES

Year ended December 31,	2010		2009	2008
(millions of Canadian dollars)
Earnings before income taxes
Canada	711		954	624
United States	379		334	419
Other	131		580	794
	1,221		1,868	1,837
Current income taxes
Canada	(29	)	49	141
United States	37		35	43
Other	5		4	67
	13		88	251
Future income taxes
Canada	134		117	92
United States	104		101	166
	238		218	258
Current and future income taxes	251		306	509

27. POST EMPLOYMENT BENEFITS

PENSION PLANS

The Company has three registered pension plans which provide either defined benefit or defined contribution pension benefits, or both, to employees of the Company. The Liquids Pipelines and Gas Distribution 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.

A measurement date of December 31, 2010 was used to determine the plan assets and the accrued benefit obligation for the Canadian and United States Plans.

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
Liquids Pipelines	December 31, 2009	December 31, 2010
Gas Distribution	December 31, 2009	December 31, 2012
United States Plan	December 31, 2009	December 31, 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.


	Pension Benefits				OPEB
December 31,	2010		2009		2010		2009
(millions of Canadian dollars)
Change in Accrued Benefit Obligation
Benefit obligation at beginning of year	1,119		1,075		170		179
Service cost	48		53		5		4
Interest cost	72		71		11		11
Amendments	-		-		6		-
Employees’ contributions	-		-		1		1
Actuarial loss/(gain) 1	145		(13	)	12		(1	)
Benefits paid	(52	)	(51	)	(7	)	(8	)
Effect of foreign exchange rate changes	(9	)	(16	)	(3	)	(16	)
Benefit obligation at end of year	1,323		1,119		195		170
Change in Plan Assets
Fair value of plan assets at beginning of year	1,167		1,141		38		46
Actual return on plan assets1	127		51		2		6
Employer’s contributions	89		44		9		9
Employees’ contributions	-		-		1		1
Benefits paid	(52	)	(51	)	(7	)	(8	)
Other	(1	)	(1	)	-		(8	)
Effect of foreign exchange rate changes	(6	)	(17	)	(2	)	(8	)
Fair value of plan assets at end of year	1,324		1,167		41		38
Funded Status
Benefit obligation	(1,323	)	(1,119	)	(195	)	(170	)
Fair value of plan assets	1,324		1,167		41		38
Overfunded/(Underfunded) status at end of year	1		48		(154	)	(132	)
Contribution after measurement date	-		14		-		1
Unamortized prior service cost	4		6		6		-
Unamortized transitional obligation/(asset)	(11	)	(13	)	8		9
Unamortized net loss	307		161		22		12
Net amount recognized in the Consolidated Statement of Financial Position at end of year	301		216		(118	)	(110	)
Presented as follows:
Deferred Amounts and Other Assets (Note 12)	301		216		-		-
Other Long-Term Liabilities (Note 18)	-		-		(118	)	(110	)

1 Includes revaluing plan assets and liabilities for December 31, 2010.

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,	2010		2009		2008		2010		2009		2008
Discount rate	5.64	%	6.46	%	6.59	%	5.55	%	6.28	%	6.42	%
Average rate of salary increases	3.50	%	3.73	%	5.00	%

Net Benefit Costs Recognized

	Pension Benefits						OPEB
Year ended December 31,	2010		2009		2008		2010		2009		2008
(millions of Canadian dollars)
Benefits earned during the year	48		53		53		5		4		5
Interest cost on projected benefit obligations	72		71		65		11		11		11
Actual return on plan assets	(127	)	(51	)	180		(2	)	(6	)	12
Difference between actual and expected return on plan assets	47		(27	)	(273	)	-		3		(15	)
Amortization of prior service costs	2		2		2		-		-		-
Amortization of transitional obligation	(2	)	(2	)	(2	)	1		1		1
Amortization of actuarial loss	19		21		4		1		1		1
Amount charged to EEP1	(15	)	(20	)	(8	)	(5	)	(5	)	(3	)
Net defined benefit costs on an accrual basis	44		47		21		11		9		12
Adjustment to cash basis for amounts in EGD2	-		-		(3	)	-		-		6
Defined contribution benefit costs	5		4		4		-		-		-
Net benefit cost recognized in the Consolidated Statements of Earnings	49		51		22		11		9		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.

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,	2010		2009		2008		2010		2009		2008
Discount rate	6.47	%	6.59	%	5.65	%	6.31	%	6.42	%	5.71	%
Average rate of return on pension plan assets	7.30	%	7.30	%	7.30	%	6.00	%	6.09	%	6.00	%
Average rate of salary increases	3.73	%	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:

	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%	2010
United States Plan	8.0%	4.5%	2030

A 1% increase in the assumed medical and dental care trend rate would result in an increase of $29 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 $23 million in the accumulated post-employment benefit obligations and a decrease of $2 million in benefit and interest costs.

PLAN ASSETS

The Company manages the investment risk of its defined benefit 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	Gas Distribution 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,	2010		2009		2010		2009
Canadian Plans	7.25	%	7.25	%	6.00	%	6.00	%
United States Plan	7.75	%	7.75	%	6.00	%	6.00	%

Major Categories of Plan Assets

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

As at December 31, 2010, assets securing pension benefits were invested 60.2% (2009 - 54.7%) in equity securities, 33.8% (2009 - 34.0%) in fixed income securities and 6.0% (2009 - 11.3%) in other. OPEB assets securing OPEB benefits were invested 51.2% (2009 - 60.5%) in equity securities and 48.8% (2009 – 39.5%) in fixed income securities.

	December 31, 2010				December 31, 2009
	Level 11	Level 22	Level 33	Total	Level 11	Level 22	Level 33	Total
(millions of Canadian dollars)
Pension Benefits:
Cash and cash equivalents	10	-	-	10	65	-	-	65
Fixed income securities:
Canadian government bonds	-	97	-	97	-	82	-	82
Corporate bonds and debentures	4	-	-	4	4	-	-	4
Canadian corporate bond index fund	151	-	-	151	131	-	-	131
Canadian government bond index fund	149	-	-	149	137	-	-	137
United States debt index fund	47	-	-	47	43	-	-	43
Equity:
Canadian equity securities	163	-	-	163	150	-	-	150
Canadian equity funds	26	80	-	106	89	-	-	89
United States equity funds	147	76	-	223	117	-	-	117
Global equity funds	221	19	-	240	127	117	-	244
Private equity investment 4	-	-	65	65	-	-	37	37
Exchange-traded foreign currency					1	-	-	1
derivatives	-	-	-	-
Other:
Refundable taxes receivable 5	-	-	68	68	-	-	62	62
Other net receivables/(payables)	-	-	-	1	-	-	-	5
	918	272	133	1,324	864	199	99	1,167
OPEB:
Fixed income securities:
United States government and government					-	15	-	15
agency bonds	20	-	-	20
Equity:
United States equity funds	9	-	-	9
Global equity funds	-	12	-	12	23	-	-	23
	29	12	-	41	23	15	-	38

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

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	37	62
Total gains, unrealized	2	-
Purchases, issuances, settlements	26	6
Balance at end of year	65	68

PLAN CONTRIBUTIONS BY THE COMPANY

	Pension Benefits		OPEB
Year ended December 31,	2010	2009	2010	2009
(millions of Canadian dollars)
Total contributions	89	44	9	9
Contributions expected to be paid in 2011	90		10

BENEFITS EXPECTED TO BE PAID BY THE COMPANY

Year ended December 31,	2011	2012	2013	2014	2015	2016-2020
(millions of Canadian dollars)
Expected future benefit payments	61	64	67	71	74	437

28. OTHER INCOME

Year ended December 31,	2010	2009	2008
(millions of Canadian dollars)
Net foreign currency gains	132	444	43
Gain on reduction of EEP ownership interest	81	-	13
Allowance for equity funds used during construction (AEDC)	80	135	59
Interest income on affiliate loans	37	38	34
Noverco preferred dividends income	15	15	16
Hurricane insurance recoveries	5	13	-
OCENSA investment income	-	6	23
Other	24	27	10
	374	678	198

29. CHANGES IN OPERATING ASSETS AND LIABILITIES

Year ended December 31,	2010		2009		2008
(millions of Canadian dollars)
Accounts receivable and other	(478	)	76		186
Inventory	(42	)	99		(135	)
Deferred amounts and other assets	(99	)	(349	)	95
Accounts payable and other	283		134		(115	)
Interest payable	13		2		9
Other long-term liabilities	60		281		(66	)
	(263	)	243		(26	)

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:

Year ended December 31,	2010	2009	2008
(millions of Canadian dollars)
EEP	332	342	302
Vector Pipeline	7	6	6
	339	348	308

At December 31, 2010, the Company has accounts receivable of $29 million (2009 - $38 million) from EEP and nil (2009 - $1 million) from Vector Pipeline.

The Company previously provided EEP with an unsecured revolving credit agreement for general liquidity support. The credit facility provided for a maximum principle amount of US$500 million for a three-year term maturing in December 2010. In March 2010, the unsecured revolving credit agreement was cancelled in accordance with the terms of the agreement and without penalty. At December 31, 2009, there was no amount outstanding on this facility.

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

Year ended December 31,	2010	2009	2008
(millions of Canadian dollars)
Alliance Pipeline Canada	25	24	24
Alliance Pipeline US	17	18	17
Vector Pipeline	28	29	27
	70	71	68

Tidal Energy Marketing (US) L.L.C., formerly 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:

Year ended December 31,	2010	2009		2008
(millions of Canadian dollars)
Purchases	2	16		52
Sales	-	(6	)	(7	)
	2	10		45

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

Year ended December 31,	2010	2009	2008
(millions of Canadian dollars)
Alliance Pipeline Canada	13	9	9
Alliance Pipeline US	9	7	7
Vector Pipeline	10	16	16
	32	32	32

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:

Year ended December 31,	2010	2009		2008
(millions of Canadian dollars)
Purchases	151	80		24
Sales	(3)	(7	)	(9	)
	148	73		15

ALBERTA CLIPPER PROJECT

In July 2009, the Company committed to fund 66.7% of the United States segment of the Alberta Clipper Project. The total cost of the United States segment was US$1,200 million. As at December 31, 2010, the Company had substantially met all funding commitments.

The Company funded 66.7% of the project’s equity requirements through EELP, an equity investee. The Company also provided a $346 million (US$347 million) (2009 - $282 million (US$270 million)) loan to EEP for debt financing related to the construction. At December 31, 2010, $334 million is included in Deferred Amounts and Other Assets with the remaining $12 million included in Accounts Receivable and Other (2009 - $282 million included in Accounts Receivable and Other). The loan, denominated in United States dollars, bears interest based on variable short-term rates.

During the year the Board of Directors of Enbridge Energy Management, L.L.C. declared distributions of $40 million (US$39 million) payable to the Company relating to its series AC interests in 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 PIPELINE

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, which became effective in February 2009, expired in April 2010. For the year ended December 31, 2010, EEP paid $5 million (2009 - $21 million) to the Company to lease Line 13.

LONG-TERM RECEIVABLE FROM AFFILIATE

An affiliate long-term note receivable of $159 million (US$130 million) 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).

ENBRIDGE INCOME FUND HOLDINGS

In December 2010, EIFH entered into an agreement with Enbridge Management Services Inc. (EMSI), a wholly owned subsidiary of the Company, to provide management and administrative services to EIFH. EMSI also provides management and administrative services to EIF. Provided that EIF is paying a base fee to EMSI for the services received by EIF, there is no fee payable to EMSI by EIFH as was the case for the period ended December 31, 2010.

LAKEHEAD LINE 6B LEAK

In connection with the Lakehead Line 6B Leak, the Company provided personnel support and other services to its affiliate, EEP, to assist in the clean-up and remediation efforts. These services, which were charged at cost, totaled $18 million for the year ended December 31, 2010.

31. COMMITMENTS AND CONTINGENCIES

COMMITMENTS

The Company has signed contracts for the purchase of services, pipe and other materials totaling $1,686 million which are expected to be paid within the next 5 years.

ENBRIDGE ENERGY PARTNERS, L.P.

EEP Lakehead System Line 6B and 6A Crude Oil Releases

Enbridge holds an approximate 25.5% combined direct and indirect ownership interest in EEP, which is accounted for as an equity investment. Subsidiaries of Enbridge provide services to EEP in connection with its operation of the Lakehead System.

Line 6B Leak

On July 26, 2010, a crude oil release on Line 6B of EEP’s Lakehead System was reported near Marshall, Michigan. EEP currently estimates that approximately 20,000 barrels of crude oil were leaked at the site, a portion of which reached the Talmadge Creek, a waterway that feeds the Kalamazoo River. The pipelines in the vicinity were shut down, appropriate United States federal, state and local officials were notified, and emergency response crews were dispatched to oversee containment of the released crude oil and cleanup of the affected areas. Regulatory approval of the pipeline restart plan was obtained from the United States Department of Transportation’s Pipeline and Hazardous Materials Safety Administration (PHMSA) and, on September 27, 2010, the pipeline was safely brought back into service. The cause of the release remains the subject of an investigation by the National Transportation Safety Board and other United States federal and state regulatory agencies.

EEP previously estimated that before insurance recoveries, and not including fines and penalties, costs of approximately US$430 million ($75 million after-tax net to Enbridge), excluding lost revenue of approximately US$13 million ($2 million after-tax net to Enbridge), will be incurred in connection with this incident. These costs include emergency response, environmental remediation and cleanup activities associated with the crude oil release. EEP subsequently revised its estimate from US$430 million to US$550 million ($96 million after-tax net to Enbridge) based on a review of costs and commitments incurred, as well as additional information concerning the requirements for environmental restoration and remediation. The assumptions made including the scope of remediation efforts, the duration that resources will be required to complete the work, weather conditions and other similar factors underlying EEP’s estimates are subject to further modification and could result in additional revisions to EEP’s estimates. Although EEP met the deadlines established by the Environmental Protection Agency (EPA) for clean up and remediation of areas affected by the crude oil release, it has the potential of incurring additional costs in connection with this incident, including fines and penalties.

Line 6A Leak

A crude oil release from Line 6A of EEP’s Lakehead System was reported in an industrial area of Romeoville, Illinois on September 9, 2010. The pipeline in the vicinity was immediately shut down and emergency response crews were dispatched to oversee containment, cleanup and replacement of the pipeline segment. EEP estimated approximately 9,000 barrels of crude oil were released, of which approximately 1,400 barrels were removed from the pipeline as part of the repair. Excavation and replacement of the pipeline segment were completed and the pipeline was returned to service on September 17, 2010. The cause of the crude oil release remains subject to investigation by United States federal and state environmental and pipeline safety regulators.

EEP currently estimates that before insurance recoveries, and not including fines and penalties, costs for emergency response, environmental remediation and cleanup activities associated with the Line 6A crude oil release will be approximately US$45 million ($7 million after-tax net to Enbridge), excluding lost revenue of approximately US$3 million ($1 million after-tax net to Enbridge). Actual costs incurred may differ from the estimate due to variations in assumptions or in any or all of the categories described above, including modified or revised requirements from regulatory agencies or other factors.

Insurance Recoveries

The Company maintains commercial liability insurance coverage that is consistent with coverage considered customary for its industry. The commercial liability insurance covers costs associated with environmental incidents such as those incurred for the leaks from Line 6B and 6A, excluding costs for fines and penalties. EEP is included in Enbridge’s comprehensive insurance program that has an aggregate limit of US$650 million of pollution liability through the policy renewal date of May 1, 2011. The remaining coverage under the Company’s existing insurance policies is approximately US$70 million. The Company does not maintain insurance coverage for interruption of operations except for water crossings; therefore, EEP will not recover approximately US$16 million of revenues lost while Line 6B and 6A were not in service. Apart from the amounts for which EEP is not insured, it is anticipated that substantially all of the costs incurred from the leaks will ultimately be recoverable under the Company’s existing insurance policies. EEP expects to record a receivable for any amounts claimed for recovery pursuant to its insurance policies during the period that it deems realization of the claim for recovery is probable.

Pipeline Integrity Commitment

In connection with the restart of Line 6B, EEP committed to accelerate a process, initiated prior to the leak, to perform additional inspections, testing and refurbishment of Line 6B within and beyond the immediate area of the July 26, 2010 incident. Pursuant to this agreement, EEP is remediating on schedule those pipeline anomalies it previously identified between 2007 and 2009 that were scheduled for refurbishment, including anomalies identified for action in a July 2010 PHMSA notification. EEP has agreed to complete all required work within 180 days of the September 27, 2010 restart of Line 6B. In addition to the required integrity measures, EEP also agreed to replace a 3,600 foot section of the Line 6B pipeline that lies underneath the St. Clair River in Michigan within one year of the restart of Line 6B, subject to obtaining required permits. The total cost to EEP for these integrity measures and pipeline replacement are estimated to approximate US$110 million, the majority of which is expected to be capital in nature. Additional significant integrity expenditures may be required after this initial remediation program. EEP is currently discussing with its customers recovery of these costs through the tolls on its Lakehead System.

Legal and Regulatory Proceedings

A number of United States governmental agencies and regulators have initiated investigations into the Line 6A and Line 6B incidents. Currently, approximately 20 actions or claims have been filed against Enbridge, EEP or their affiliates in United States federal and state courts in connection with the Line 6B incident; however, currently no penalties or fines have been assessed against EEP in connection with this incident. Currently, one action or claim related to the Line 6A incident has been filed against Enbridge, EEP or their affiliates in a United States state court. The Company believes this action or claim has been resolved pursuant to an agreed interim order.

ENBRIDGE GAS DISTRIBUTION INC.

Bloor Street Incident

EGD had been 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 was appealed by the Crown to the Ontario Superior Court of Justice and the appeal was heard by the Court during November and December 2009. In April 2010, the Superior Court overturned the trial judge’s decision and ordered a new trial to be conducted before a different judge. EGD commenced a motion for leave to appeal to the Ontario Court of Appeal and the motion was heard by the Court of Appeal in August 2010. On January 7, 2011 the Court of Appeal dismissed EGD’s motion, meaning that the Superior Court’s decision ordering a new trial will stand. At this time it is not certain when a new trial of the charges will commence. Management does not believe any fines that may be levied will have a material financial impact on the Company.

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 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

The Company 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.

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 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.

The above-noted indemnifications and guarantees have not had, and are not reasonably likely to have, a material effect on the Company’s financial condition, changes in financial condition, earnings, liquidity, capital expenditures or capital resources.

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

Year ended December 31,	2010	2009		2008
(millions of Canadian dollars, except per share amounts)
Earnings under Canadian GAAP Applicable to Common Shareholders	963	1,555		1,321
Earnings under Canadian GAAP	970	1,562		1,328
Dilution gains, net of tax1	(52)	-		-
Gain on acquisition, net of tax2	20	-		-
Inventory valuation adjustment, net of tax3	4	(24	)	-
Earnings/(Loss) attributable to non-controlling interests
EEP4	(172)	177		278
Other1,5	25	37		56
Earnings under U.S. GAAP	795	1,752		1,662
Attributable to
Enbridge Inc.5	942	1,538		1,328
Non-controlling interests5	(147)	214		334
Earnings under U.S. GAAP	795	1,752		1,662
Earnings per Common Share attributable to Enbridge Inc.	2.55	4.71		3.67
Diluted Earnings per Common Share attributable to Enbridge Inc.	2.52	4.68		3.64

COMPREHENSIVE INCOME

Year ended December 31,	2010	2009		2008
(millions of Canadian dollars, except per share amounts)
Earnings under U.S. GAAP	795	1,752		1,662
Other comprehensive income/(loss) under Canadian GAAP	(339)	(576	)	318
Underfunded pension adjustment, net of tax6	(120)	3		(57	)
Other comprehensive income attributable to non-controlling interests under Canadian GAAP 5	(33)	(72	)	101
Other comprehensive loss attributable to non-controlling interests to non-controlling interest in EEP under U.S. GAAP4	(29)	(62	)	241
Comprehensive income under U.S. GAAP	274	1,045		2,265
Attributable to
Enbridge Inc.5	483	965		1,589
Non-controlling interests5	(209)	80		676
Comprehensive income under U.S. GAAP	274	1,045		2,265

FINANCIAL POSITION

	2010				2009
			United				United
December 31,	Canada		States		Canada		States
(millions of Canadian dollars)
Assets
Current Assets
Cash and cash equivalents4,7	242		387		327		478
Accounts receivable and other4,7	2,706		3,595		2,484		2,848
Inventory3,4,7	813		915		784		824
	3,761		4,897		3,595		4,150
Property, Plant and Equipment, net4,7	20,332		28,872		18,850		26,837
Long-Term Investments4,7	2,198		226		2,312		228
Deferred Amounts and Other Assets4,6,7,8	2,886		2,064		2,425		2,478
Intangible Assets4	478		753		488		575
Goodwill2,4	385		728		372		719
Future Income Taxes7	80		79		127		148
	30,120		37,619		28,169		35,135

Liabilities and Shareholders’ Equity
Current Liabilities
Short-term borrowings	326		326		508		508
Accounts payable and other4,7	2,688		3,864		2,463		3,178
Interest payable4	117		177		104		151
Current maturities of long-term debt4	154		185		601		633
Current maturities of non-recourse long-term debt7	70		72		113		131
	3,355		4,624		3,789		4,601
Long-Term Debt4,7,8	13,561		18,403		11,866		15,932
Non-Recourse Long-Term Debt7	1,061		753		1,108		1,114
Other Long-Term Liabilities4,6,7	1,473		1,638		1,207		1,311
Future Income Taxes2,3,6	2,447		2,306		2,211		2,147
	21,897		27,724		20,181		25,105
Non-Controlling Interests5	658		-		727		-
Shareholders’ Equity
Share capital
Preferred shares	125		125		125		125
Common shares	3,683		3,683		3,379		3,379
Contributed surplus	59		-		54		-
Retained earnings	4,734		4,648		4,400		4,343
Additional paid in capital1	-		103		-		98
Accumulated other comprehensive loss6	(882	)	(1,105	)	(543	)	(646	)
Reciprocal shareholding	(154	)	(154	)	(154	)	(154	)
	7,565		7,300		7,261		7,145
Total Enbridge Inc. Liabilities and Shareholders’ Equity	30,120		35,024		28,169		32,250
Non-Controlling Interests5	-		2,595		-		2,885
	30,120		37,619		28,169		35,135

1 Dilution Gains

Under Canadian GAAP, dilution gains are recorded as an increase to earnings. Under U.S. GAAP, dilution gains are recorded as equity transactions. During the year ended December 31, 2010, dilutions gains of $52 million, net of tax of $30 million, were reclassified from earnings to equity. The Company did not record any dilution gains during 2009. Prior to 2009 there was no recognition difference between Canadian and U.S. GAAP.

2 Gain on Acquisition

Under Canadian GAAP, the original equity interest in a step acquisition continues to be carried at book value subsequent to the acquisition date of the additional interest. Under U.S. GAAP, the original equity interest and non-controlling interest in a step acquisition are re-measured to fair value on the date control is obtained. Under Canadian GAAP, the original equity interest and non-controlling interest are not re-measured to fair value.

On June 16, 2010, the Company acquired the remaining 50% interest in Hardisty Caverns, an oil storage facility, increasing its ownership interest to 100%. The acquisition date fair value of the original equity interest in Hardisty Caverns was $52 million, which was determined based on the valuation of the additional 50% interest. As a result of the re-measurement of Hardisty Caverns, a $20 million gain, net of tax, was recorded in earnings for the year ended December 31, 2010 under U.S GAAP.

3 Commodity 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, 2010, lower of cost or market adjustments resulted in a $33 million (2009 - $36 million) decrease to inventory, a $12 million (2009 - $12 million) decrease to the future income tax liability and a $4 million increase (2009 - $24 million decrease) to earnings. There were no lower of cost or market adjustments related to commodity inventory valuation for the year ended December 31, 2008.

4 Consolidation of a Limited Partnership

Under U.S. GAAP the Company is deemed to have control of EEP and therefore consolidates its 25.5% interest in the partnership, resulting in an increase to assets of $8,012 million (2009 - $6,974 million), an increase in liabilities of $6,131 million (2009 - $4,816) and an increase in non-controlling interests of $1,881 million (2009 - $2,158 million) at December 31, 2010 and no recognition or measurement changes to equity or earnings attributable to the Company as at and for the years ended December 31, 2010 and 2009.

5 Presentation 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 outside of equity 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, 2010, $147 million of losses (2009 - $214 million of earnings; 2008 - $334 million of earnings) are attributable to non-controlling interests.

Included in OCI for the year ended December 31, 2010 is an unrealized loss on cash flow hedges of $29 million (2009 - $62 million unrealized loss; 2008 - $241 million unrealized gain), and an after-tax change in OCI of $33 million (2009 - $1 million; 2008 - $20 million) attributable to non-controlling interests.

6 Pension 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 $338 million (2009 - $155 million) for the underfunded status of the plans, a decrease in future tax liability of $113 million (2009 - $52 million) and an increase in accumulated other comprehensive loss of $223 million (2009 - $103 million) at December 31, 2010.

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)	2010		2009		2008

Prior service cost	2		2		1

Net transitional obligation	(2	)	(1	)	(1)

Net loss	19		22		1

	19		23		1

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)	2010		2009		2008

Prior service cost	7		4		1

Net transitional obligation	(2	)	(3	)	(6	)

Accumulated net loss	217		107		110
	222		108		105

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

(millions of Canadian dollars)	2010	2009		2008

Unamortized prior service cost	3	3		(3	)

Unamortized transitional obligation	1	3		1

Net loss/(gain)	111	(3	)	58
	115	3		56

The Company estimates that approximately $17 million related to pension and OPEB plans at December 31, 2010 will be reclassified into earnings in the next twelve months, as follows:

	Pension Benefits		OPEB	Total

(millions of Canadian dollars)

Net transitional obligation	(2	)	1	(1	)

Prior service costs	1		-	1

Loss	16		1	17
	15		2	17

7 Accounting 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.

8 Transaction 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, 2010, $89 million (2009 - $98 million) of transaction costs were reclassified.

9 Unrecognized Tax Benefits

	*2010*	2009

(millions of Canadian dollars)

Unrecognized Tax Benefits at beginning of year	22	13

Gross increases for tax positions of current year	2	5

Gross increases for tax positions of prior years	-	6

Gross decreases for tax positions of prior years	*(2)*	(1)

Reduction for lapse of statute of limitations	*(2)*	-

Changes in translation of foreign currency	-	(1)

Decreases relating to settlements with taxing authority	*(3)*	-
Unrecognized Tax Benefits at end of year	17	22

The unrecognized tax benefits at December 31, 2010, if recognized, would affect the Company’s effective income tax rate. 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, 2010 includes a recovery of $2 million (2009 - $1 million expense) of interest and penalties. As at December 31, 2010, interest and penalties of $8 million (2009 - $10 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 2007 and all returns are generally closed through 2005. Generally, all United States federal income tax returns and state and local income tax returns are closed through 2006, with the exception of years under adjustment relating to the 2008 unfavourable court decision.

10 Indefinite 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, 2010 were approximately $491 million (2009 - $460 million).

FUTURE ACCOUNTING STANDARDS UNDER U.S. GAAP

The following standards will be effective for the Company beginning on January 1, 2011. Management does not expect the adoption of any of these standards to significantly impact the consolidated financial statements.

Fair Value Measurements

In January 2010, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) No. 2010-06, Fair Value Measurements and Disclosures (Topic 820): Improving Disclosures about Fair Value Measurements. The ASU updates the current authoritative guidance pertaining to fair value measurements by enhancing existing disclosure requirements for both the valuation techniques and inputs used to determine fair value measurements.

Stock-Based Compensation

In April 2010, the FASB issued ASU No. 2010-13, Compensation – Stock Compensation (Topic 718): Effect of Denominating the Exercise Price of a Share-Based Payment Award in the Currency of the Market in Which the Underlying Equity Security Trades. The ASU updates the current authoritative guidance pertaining to stock-based compensation by clarifying the classification of an employee share-based payment award with an exercise price denominated in the currency of a market in which the underlying equity trades.

Goodwill and Intangibles

In December 2010, the FASB issued ASU No. 2010-28, Intangibles – Goodwill and Other (Topic 350) – When to perform step 2 of the goodwill impairment test for reporting units with zero or negative carrying value. This ASU updates the current authoritative guidance pertaining to goodwill impairment testing by modifying step one of the goodwill impairment test for reporting units with zero or negative carrying amounts requiring the performance of step two if it is more likely than not that a goodwill impairment exists.

Business Combinations

In December 2010, the FASB issued ASU No. 2010-29, Business Combinations (Topic 805) – Disclosure of Supplementary Pro Forma Information for Business Combinations. This ASU updates the current authoritative guidance pertaining to the disclosure requirements for a business combination by clarifying and expanding the existing requirements related to pro forma revenue and earnings.