EX-99.6 7 a12-4695_1ex99d6.htm EX-99.6 AUDITED FINANCIAL STATEMENTS AND NOTES ENDED DECEMBER 31, 2010 AND 2011.

Exhibit 99.6

ENBRIDGE INC.

CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2011

MANAGEMENT’S REPORT

To the Shareholders of Enbridge Inc.

Financial Reporting

Management of Enbridge Inc. (the Company) is responsible for the accompanying consolidated financial statements. The consolidated financial statements have been prepared in accordance with Part V – Pre-changeover Accounting Standards of the Canadian Institute of Chartered Accountants Handbook and necessarily include amounts that reflect management’s judgment and best estimates.

The Board of Directors and its committees are responsible for all aspects related to governance of the Company. The Audit, Finance & Risk Committee (AF&RC) 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 AF&RC 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 AF&RC 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, 2011, based on the framework established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this assessment, management concluded that the Company maintained effective internal control over financial reporting as at December 31, 2011.

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 21, 2012

Independent Auditor’s Report

To the Shareholders of Enbridge Inc.

We have completed integrated audits of Enbridge Inc.’s 2011, 2010 and 2009 consolidated financial statements and its internal control over financial reporting as at December 31, 2011. 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, 2011 and December 31, 2010 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, 2011, and the related notes, which comprise a summary of significant accounting policies and other explanatory information.

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, 2011 and December 31, 2010 and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2011 in accordance with Canadian generally accepted accounting principles.

Report on internal control over financial reporting

We have also audited Enbridge Inc.’s internal control over financial reporting as at December 31, 2011, based on the criteria established in Internal Control - Integrated Framework, issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).

PricewaterhouseCoopers LLP, Chartered Accountants

111 5 Avenue SW, Suite 3100, Calgary, Alberta, Canada T2P 5L3

T: +1 403 509 7500, F: +1 403 781 1825, www.pwc.com/ca

“PwC” refers to PricewaterhouseCoopers LLP, an Ontario limited liability partnership.

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

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, 2011 based on criteria established in Internal Control – Integrated Framework, issued by COSO.

“signed” PricewaterhouseCoopers LLP

Chartered Accountants

Calgary, Alberta, Canada

February 21, 2012

CONSOLIDATED STATEMENTS OF EARNINGS

Year ended December 31,	2011		2010		2009
(millions of Canadian dollars, except per share amounts)
Revenues
Commodity sales	15,676		11,990		9,720
Transportation and other services	3,726		3,137		2,746
	19,402		15,127		12,466
Expenses
Commodity costs	14,854		11,291		9,011
Operating and administrative	1,720		1,466		1,430
Depreciation and amortization	937		864		764
	17,511		13,621		11,205
	1,891		1,506		1,261
Income from equity investments	336		38		198
Other income (Note 28)	112		374		678
Interest expense (Note 16)	(711	)	(687	)	(597	)
Gain on sale of investments (Note 6)	-		-		365
	1,628		1,231		1,905
Income taxes (Note 26)	(568	)	(251)		(306	)
Earnings	1,060		980		1,599
Earnings attributable to noncontrolling interests	(56	)	(10	)	(37	)
Earnings attributable to Enbridge Inc.	1,004		970		1,562
Preference share dividends	(13	)	(7	)	(7	)
Earnings attributable to Enbridge Inc. common shareholders	991		963		1,555
Earnings per common share attributable to Enbridge Inc. common shareholders (Note 20)	1.32		1.30		2.14
Diluted earnings per common share attributable to Enbridge Inc. common shareholders (Note 20)	1.30		1.29		2.12

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

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

Year ended December 31,	2011		2010		2009
(millions of Canadian dollars)
Earnings	1,060		980		1,599
Other comprehensive income/(loss)
Change in unrealized loss on cash flow hedges, net of tax	(427	)	(113	)	(54	)
Change in unrealized gain/(loss) on net investment hedges, net of tax	(19	)	51		151
Reclassification to earnings of realized cash flow hedges, net of tax	32		(25	)	114
Reclassification to earnings of unrealized cash flow hedges, net of tax (Note 23)	8		-		(20	)
Other comprehensive loss from equity investees, net of tax	(61	)	(11	)	(24	)
Change in foreign currency translation adjustment	242		(274	)	(815	)
Other comprehensive loss	(225	)	(372	)	(648	)
Comprehensive income	835		608		951
Comprehensive (income)/loss attributable to noncontrolling interests	(43	)	23		35
Comprehensive income attributable to Enbridge Inc.	792		631		986
Preference share dividends	(13	)	(7	)	(7	)
Comprehensive income attributable to Enbridge Inc. common shareholders	779		624		979

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

CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY

Year ended December 31,	2011		2010		2009
(millions of Canadian dollars, except per share amounts)
Preference shares (Note 20)
Balance at beginning of year	125		125		125
Preference shares issued	931		-		-
Balance at end of year	1,056		125		125
Common shares (Note 20)
Balance at beginning of year	3,683		3,379		3,194
Common shares issued	-		-		4
Dividend reinvestment and share purchase plan	229		224		143
Shares issued on exercise of stock options	57		80		38
Balance at end of year	3,969		3,683		3,379
Contributed surplus
Balance at beginning of year	59		54		38
Stock-based compensation	18		13		19
Options exercised	(7	)	(8	)	(3	)
Dilution gains and other (Note 19)	36		-		-
Balance at end of year	106		59		54
Retained earnings
Balance at beginning of year	4,734		4,400		3,383
Earnings attributable to Enbridge Inc. common shareholders	991		963		1,555
Common share dividends declared	(759	)	(648	)	(555	)
Dividends paid to reciprocal shareholder	25		19		17
Balance at end of year	4,991		4,734		4,400
Accumulated other comprehensive income/(loss) (Note 22)
Balance at beginning of year	(882	)	(543	)	33
Other comprehensive loss	(212	)	(339	)	(576	)
Balance at end of year	(1,094	)	(882	)	(543	)
Reciprocal shareholding (Note 11)
Balance at beginning of year	(154	)	(154	)	(154	)
Acquisition of equity investment	(33	)	-		-
Balance at end of year	(187	)	(154	)	(154	)
Total Enbridge Inc. shareholders’ equity	8,841		7,565		7,261
Noncontrolling interests
Balance at beginning of year	658		727		797
Earnings attributable to noncontrolling interests	56		10		37
Other comprehensive income/(loss) attributable to noncontrolling interests
Change in unrealized income/(loss) on cash flow hedges, net of tax	(7	)	(9	)	4
Other comprehensive loss from equity investees, net of tax	(15	)	(3	)	(5	)
Change in foreign currency translation adjustment	9		(21	)	(71	)
	(13	)	(33	)	(72	)
Comprehensive income/(loss) attributable to noncontrolling interests	43		(23	)	(35	)
Distributions	(37	)	(30	)	(33	)
Contributions (Note 19)	208		29		-
Acquisitions (Notes 10 and 19)	(27	)	(45	)	-
Other	1		-		(2	)
Balance at end of year	846		658		727
Total shareholders’ equity	9,687		8,223		7,988

Dividends paid per common share	0.98		0.85		0.74

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

CONSOLIDATED STATEMENTS OF CASH FLOWS

Year ended December 31,	2011		2010		2009
(millions of Canadian dollars)
Operating activities
Earnings attributable to Enbridge Inc.	1,004		970		1,562
Depreciation and amortization	937		864		764
Unrealized gain on derivative instruments	(13	)	(10	)	(204	)
Allowance for equity funds used during construction	(3	)	(80	)	(135	)
Cash distributions (less than)/in excess of equity earnings	(42	)	214		(9	)
Gain on reduction of ownership interest	(141	)	(81	)	-
Gain on sale of investments (Note 6)	-		-		(365	)
Future income taxes (Note 26)	415		238		218
Goodwill and asset impairment losses	11		-		11
Noncontrolling interests	56		10		37
Other	150		(11	)	(105	)
Changes in regulatory assets and liabilities	78		30		11
Changes in operating assets and liabilities (Note 29)	251		(293	)	232
	2,703		1,851		2,017
Investing activities
Additions to property, plant and equipment	(2,516	)	(2,357	)	(3,225	)
Government grant	145		-		-
Additions to intangible assets	(165	)	(50	)	(95	)
Change in construction payable	(66	)	27		(110	)
Long-term investments	(217	)	(121	)	(359	)
Affiliate loans, net	10		(80	)	(145	)
Acquisitions (Notes 6 and 19)	(1,208	)	(116	)	-
Proceeds on sale of investments (Note 6)	-		23		535
Sale of property, plant and equipment	-		-		87
Settlement of hedges (Note 6)	-		-		6
	(4,017	)	(2,674	)	(3,306	)
Financing activities
Net change in bank indebtedness and short-term borrowings	224		(165	)	(393	)
Net change in commercial paper and credit facility draws	11		(347	)	736
Debenture and term note issues	825		2,300		1,500
Debenture and term note repayments	(203	)	(600	)	(616	)
Net change in Southern Lights project financing	(62	)	14		343
Non-recourse debt issues	17		5		60
Non-recourse debt repayments	(81	)	(73	)	(130	)
Contributions from/(distributions) to noncontrolling interests, net	214		(1	)	(33	)
Preference shares issued	926		-		-
Common shares issued	46		66		36
Preference share dividends	(7	)	(7	)	(7	)
Common share dividends	(530	)	(426	)	(414	)
	1,380		766		1,082
Effect of translation of foreign denominated cash and cash equivalents	12		(11	)	(35	)
Increase/(decrease) in cash and cash equivalents	78		(68	)	(242	)
Cash and cash equivalents at beginning of year	342		410		652
Cash and cash equivalents at end of year1	420		342		410

Supplementary cash flow information
Income taxes paid/(received) (Note 26)	(35	)	108		205
Interest paid (Note 16)	749		711		656

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

1 Cash and cash equivalents consists of $343 million (2010 - $243 million; 2009 - $267 million) of cash and $77 million (2010 - $99 million; 2009 - $143 million) of short-term investments and includes restricted cash of $17 million (2010 - $12 million; 2009 - $7 million), and joint-venture cash which is not readily accessible by the Company of $224 million (2010 - $48 million; 2009 - $52 million).

CONSOLIDATED STATEMENTS OF FINANCIAL POSITION

December 31,	2011		2010
(millions of Canadian dollars)
Assets
Current assets
Cash and cash equivalents	420		342
Accounts receivable and other (Note 7)	3,136		2,706
Inventory (Note 8)	739		813
	4,295		3,861
Property, plant and equipment, net (Note 9)	22,623		20,332
Long-term investments (Note 11)	2,540		2,198
Deferred amounts and other assets (Note 12)	3,220		2,886
Intangible assets (Note 13)	600		478
Goodwill (Note 14)	1,024		385
Future income taxes (Note 26)	41		80
	34,343		30,220
Liabilities and shareholders’ equity
Current liabilities
Bank indebtedness	102		100
Short-term borrowings (Note 16)	548		326
Accounts payable and other (Note 15)	3,722		2,688
Interest payable	114		117
Current maturities of long-term debt (Note 16)	252		154
Current maturities of non-recourse long-term debt (Note 17)	122		70
	4,860		3,455
Long-term debt (Note 16)	14,257		13,561
Non-recourse long-term debt (Note 17)	951		1,061
Other long-term liabilities (Note 18)	1,892		1,473
Future income taxes (Note 26)	2,696		2,447
	24,656		21,997
Equity
Share capital
Preference shares (Note 20)	1,056		125
Common shares (Note 20)	3,969		3,683
Contributed surplus	106		59
Retained earnings	4,991		4,734
Accumulated other comprehensive loss (Note 22)	(1,094	)	(882	)
Reciprocal shareholding (Note 11)	(187	)	(154	)
Total Enbridge Inc. shareholders’ equity	8,841		7,565
Noncontrolling interests (Note 19)	846		658
	9,687		8,223
Commitments and contingencies (Note 31)
	34,343		30,220

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 are strategic business units established by senior management to facilitate the achievement of the Company’s long-term objectives, to aid in resource allocation decisions and to assess operational performance.

LIQUIDS PIPELINES

Liquids Pipelines consists of common carrier and contract crude oil, natural gas liquids (NGL) and refined products pipelines and terminals in Canada and the United States, including the Canadian Mainline, Regional Oil Sands System, Southern Lights Pipeline, Spearhead Pipeline, Seaway Crude Pipeline (Seaway Pipeline) interest 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 and processing facilities, green energy projects, Canadian midstream businesses, the Company’s energy services 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), the Vector Pipeline and transmission and gathering pipelines in the Gulf of Mexico. Investments in natural gas processing include the Company’s interest in Aux Sable, a natural gas fractionation and extraction business, an interest in the development of Cabin Gas Plant in northeastern British Columbia, and processing facilities connected to the Gulf of Mexico System. The energy services businesses manage the Company’s volume commitments on Alliance and Vector Pipelines, as well as perform natural gas, NGL and crude oil storage, transport and supply management services, as principal and agent.

SPONSORED INVESTMENTS

Sponsored Investments includes the Company’s 23.0% 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, Limited Partnership (EELP) and an overall 69.2% economic interest in Enbridge Income Fund (the Fund), held both directly, and indirectly through Enbridge Income Fund Holdings Inc. 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 the Fund include a crude oil and liquids pipeline and gathering system, a 50% interest in the Canadian portion of Alliance Pipeline (Alliance Pipeline Canada) and interests in renewable power generation projects.

CORPORATE

Corporate consists of the Company’s investment in Noverco Inc. (Noverco), new business development activities, 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 Part V – Pre-changeover Accounting Standards of the Canadian Institute of Chartered Accountants (CICA) Handbook (Canadian GAAP or Part V). 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); unbilled revenues (Note 7); 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 (AROs). Actual results could differ from these estimates.

BASIS OF PRESENTATION

The consolidated financial statements include the accounts of Enbridge, its subsidiaries and its proportionate share of the accounts of various joint ventures. The Fund is consolidated in the accounts of the Company because it is a variable interest entity. The Company is the primary beneficiary of the Fund through the combination of a total direct and indirect 35.4% 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, 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. 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. The recognition of regulatory assets and liabilities is based on the actions, or expected future actions of the regulator. To the extent that the regulator’s actions differ from the Company’s expectations, the timing and amount of recovery or settlement of regulatory balances could differ significantly from those recorded. 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.

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 and certain distribution operations capitalize a percentage of certain operating costs. These operations are authorized to charge depreciation and earn a return on the net book value of such capitalized costs in future years. To the extent that the regulator’s actions differ from the Company’s expectations, the timing and amount of recovery or settlement of capitalized costs could differ significantly from those recorded. In the absence of rate regulation, a portion of such costs may be charged to current period 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. Certain Liquids Pipelines revenues are recognized under the terms of committed delivery contracts rather than the cash tolls received.

For the rate-regulated portion of the Company’s main Canadian crude oil pipeline system, revenue was recognized in a manner that is consistent with the underlying agreements as approved by the regulator. Effective July 1, 2011, Canadian Mainline earnings are governed by the Competitive Toll Settlement (CTS), under which revenues are recorded when services are performed. Effective July 1, 2011, the Company discontinued the application of rate-regulated accounting for its Canadian Mainline (excluding Lines 8 and 9) on a prospective basis, with the exception of flow-through income taxes covered by a specific rate order.

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.

For rate-regulated operations in Sponsored Investments and rate-regulated operations 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.

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 Statements 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 Transportation and other services revenue, Commodity costs, Other income and Interest expense. The Company has classified Cash and cash equivalents, bank indebtedness 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. The Company did not have any fair value hedges outstanding at December 31, 2011 or December 31, 2010.

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.

Classification of Derivatives

The Company recognizes the fair market value of derivative instruments on the Consolidated Statements of Financial Position as current or long-term depending on the timing of the settlements and the resulting cash flows associated with the instruments. The fair value related to cash flows occurring beyond one year are classified as non-current.

Balance Sheet Offset

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

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.

EQUITY INVESTMENTS

Equity investments over which the Company exercises significant influence, but does not have controlling financial interests, are accounted for using the equity method. Equity investments are initially measured at cost and are adjusted for the Company’s proportionate share of undistributed equity earnings or loss. Equity investments are increased for contributions made to and decreased for distributions received from the investees.

NONCONTROLLING INTERESTS

Noncontrolling interests represent the outstanding ownership interests attributable to third parties in certain consolidated subsidiaries, limited partnerships and variable interest entities. The portion of the entities not owned by the Company is reflected as noncontrolling interests within the equity section of the Consolidated Statements of Financial Position.

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. Any interest and/or penalty incurred related to tax is reflected in income taxes.

FOREIGN CURRENCY TRANSLATION

Foreign currency transactions are those transactions whose terms are denominated in a currency other than the currency of the primary economic environment in which the Company or a reporting subsidiary operates. 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 Statements of Earnings in the period that they arise.

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

operations are included in the cumulative translation adjustment component of AOCI and are recognized in earnings when there is a disposal of all or part of the foreign operation.

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.

ALLOWANCE FOR DOUBTFUL ACCOUNTS

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.

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

Property, plant and equipment is recorded at historical cost. 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 future benefit. The Company capitalizes interest incurred during construction for non rate-regulated assets. For rate-regulated assets, 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.

The Company uses the group method of depreciation for all property, plant and equipment, except for the non rate-regulated assets in Canada, which are depreciated on a single asset basis. Depreciation is provided on a straight-line basis over the estimated useful lives of the assets commencing when the asset is placed in service. Under the group method, upon the disposition of property, plant and equipment, the net book value less net proceeds is typically charged to accumulated depreciation and no gain or loss on disposal is recognized. However, when a separately identifiable group of assets, such as a stand-alone pipeline system, is sold, a gain or loss is recognized in the Consolidated Statements of Earnings for the difference between the cash received and the net book value of the assets sold.

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, including future income taxes, 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, long-term power purchase agreements and certain software costs. The Company capitalizes costs incurred during the application development stage of internal use software projects. Intangibles 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. The carrying value of goodwill, which is not amortized, is assessed for impairment annually in the fourth quarter of each year, or more frequently if events or changes in circumstances arise that suggest the carrying value of goodwill may be impaired. 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.

IMPAIRMENT

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.

With respect to investments in debt and equity securities, 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 other financial assets, the Company assesses the assets for impairment when it no longer has reasonable assurance of timely collection. If evidence of impairment is noted, the Company reduces the value of the financial asset to its estimated realizable amount, determined using discounted expected future cash flows.

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 (OPEB), 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.

Certain regulated operations of the Company recover pension and OPEB expense based on amounts paid in accordance with the methodology accepted by the regulators for rate-making purposes. As a result, rates typically only include the recovery of required contributions. A corresponding pension regulatory liability and OPEB regulatory asset have been recorded to the extent that they are expected to be included in regulator-approved future rates and recovered from or refunded to future customers. In the absence of rate regulation, these balances would not be recorded and pension and OPEB expense would be charged to earnings based on the accrual basis of accounting.

STOCK BASED COMPENSATION

Incentive Stock Options (ISO) granted are recorded using the fair value method. Under this method, compensation expense is measured at the grant date based on the fair value as calculated by the Black-Scholes-Merton model 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 based stock options (PBSOs) granted are recorded using the fair value method. Under this method, compensation expense is measured at the grant date based on the fair value as calculated by the Bloomberg barrier option valuation model and is recognized on a straight-line basis with a corresponding credit to Contributed surplus. The options become exercisable when both performance targets and time vesting requirements have been met. Balances in Contributed surplus are transferred to share capital when the options are exercised.

Performance Stock Units (PSUs) and Restricted Stock Units (RSUs) are cash settled awards for which the related liability is remeasured each reporting period. PSUs vest at the completion of a three-year term and RSUs vest at the completion of a 35-month term. 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

Business Combinations

Effective January 1, 2011, the Company adopted Part V Section 1582, Business Combinations, which 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. In accordance with the transitional provisions of this standard, Section 1582 was adopted prospectively and accordingly, assets and liabilities that arose from business combinations occurring before January 1, 2011 were not restated.

The application of this standard decreased Earnings attributable to Enbridge Inc. by $37 million, net of income taxes of $5 million for dilution gains for subsidiaries, which are now recognized in equity for the year ended December 31, 2011. The application of this standard had no material impact to the Company’s cash flows for the year ended December 31, 2011.

Consolidated Financial Statements and Noncontrolling Interests

Effective January 1, 2011, the Company adopted Part V Sections 1601, Consolidated Financial Statements and 1602, Noncontrolling Interests, which together replace the former consolidated financial statements standard. Under the revised standards, noncontrolling interests are classified as a component of equity, and earnings and comprehensive income are attributed to both the parent and noncontrolling interest. In accordance with the transitional provisions of these standards, Section 1601 was adopted prospectively and Section 1602 was adopted retroactively with restatement of prior periods. As the adoption of these standards impacts presentation only, there was no impact to the Company’s earnings or cash flow for the current or prior periods presented.

United States Generally Accepted Accounting Principles

First-time adoption of Part I - International Financial Reporting Standards (Part I or IFRS) of the CICA Handbook was 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 presented its financial statements in accordance with Part V of the CICA Handbook during the 2011 deferral period.

As a rate regulated accounting standard model has not been finalized by the International Accounting Standards Board, the Company does not intend to adopt IFRS in 2012 but rather U.S. GAAP. As a United States Securities and Exchange Commission (SEC) registrant, Enbridge is permitted by Canadian securities regulation to prepare its financial statements in accordance with U.S. GAAP and will adopt U.S. GAAP for interim and annual financial statements beginning on January 1, 2012.

4. SEGMENTED INFORMATION

Year ended December 31, 2011

Liquids
Pipelines

Gas
Distribution

Gas
Pipelines,
Processing
and Energy
Services

Sponsored
Investments

Corporate

Consolidated

(millions of Canadian dollars)

Revenues

1,959

2,574

14,476

393

19,402

Commodity costs

(1,354)

(13,500)

(14,854)

Operating and administrative

(760)

(492)

(295)

(137)

(36)

(1,720)

Depreciation and amortization

(327)

(320)

(167)

(111)

(12)

(937)

872

408

514

145

(48)

1,891

Income/(loss) from equity investments

342

(6)

336

Other income/(expense)

(11)

202

(148)

112

Interest expense

(256)

(166)

(97)

(74)

(118)

(711)

Income taxes recovery/(expense)

(139)

(55)

(161)

(219)

(568)

Earnings/(loss)

508

176

294

396

(314)

1,060

Earnings attributable to noncontrolling interests

(3)

(1)

(52)

(56)

Preference share dividends

(13)

Earnings/(loss) attributable to Enbridge Inc. common shareholders

505

176

293

344

(327)

991

Additions to property, plant and equipment1

977

483

953

2,519

Total assets

12,366

7,713

4,968

5,245

4,051

34,343

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)	115	(17)	30	114	132	374
Interest expense	(223)	(179)	(96)	(58)	(131)	(687)
Income taxes recovery/(expense)	(135)	(64)	(65)	(66)	79	(251)
Earnings	514	160	121	140	45	980
Earnings attributable to noncontrolling interests	(2)	(5)	-	(3)	-	(10)
Preference share dividends	-	-	-	-	(7)	(7)
Earnings attributable to Enbridge Inc. common shareholders	512	155	121	137	38	963
Additions to property, plant and equipment1	765	387	1,153	132	-	2,437
Total assets	11,508	7,594	5,536	3,833	1,749	30,220

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 expense	(144)	(188)	(87)	(56)	(122)	(597)
Income taxes	(108)	(50)	(54)	(88)	(6)	(306)
Earnings	447	192	428	169	363	1,599
Earnings attributable to noncontrolling interests	(2)	(6)	-	(28)	(1)	(37)
Preference share dividends	-	-	-	-	(7)	(7)
Earnings attributable to Enbridge Inc. common shareholders	445	186	428	141	355	1,555
Additions to property, plant and equipment1	2,662	326	321	41	10	3,360

1 Includes allowance for equity funds used during construction (AEDC).

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

GEOGRAPHIC INFORMATION

Revenues1

Year ended December 31,	2011	2010	2009
(millions of Canadian dollars)
Canada	12,591	9,876	9,503
United States	6,811	5,251	2,963
	19,402	15,127	12,466

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

Property, Plant and Equipment

December 31,	2011	2010
(millions of Canadian dollars)
Canada	17,843	16,095
United States	4,780	4,237
	22,623	20,332

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.

Canadian Mainline

The Canadian Mainline includes the Canadian portion of the mainline system. The primary business activities of the Canadian Mainline are subject to regulation by the NEB. Prior to July 1, 2011, the incentive tolling settlement (ITS) defined the methodology for calculation of tolls and the revenue requirement on the core component of the Canadian Mainline. Toll adjustments, for variances from requirements defined in the ITS, were filed annually with the regulator for approval. Surcharges were also determined for a number of system expansion components and were added to the base toll determined

for the core system.

Effective July 1, 2011, Canadian Mainline earnings (excluding Lines 8 and 9) were governed by the CTS. The CTS covers local tolls to be charged for service on the Canadian Mainline and supersedes all existing toll agreements on the Canadian Mainline during the ten year term of the CTS. As a result, the Company discontinued the application of rate-regulated accounting to its Canadian Mainline on a prospective basis commencing July 1, 2011. While the CTS is based on previous tolling settlements and cost of service principles, the Company retains some risk associated with volume throughput and capital and operating costs, subject to various protection mechanisms. As a result, the Canadian Mainline operations (excluding Lines 8 and 9) no longer meet all of the criteria required for the continued application of rate-regulated accounting treatment.

The regulatory asset of approximately $470 million related to future income taxes recorded at the date of discontinuance will continue to be recognized as the Company retains the ability to recover future income taxes under an NEB order governing flow-through income tax treatment. In the same manner, the rate order provides for the recovery of future income taxes incurred subsequent to the discontinuance of rate-regulated accounting, and, as such, regulatory assets related to future income taxes will continue to be recognized as incurred. The regulatory asset of approximately $70 million related to tolling deferrals recorded at the date of discontinuance is being recovered through a toll surcharge over a period of two years.

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 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, 2011, 2010 and 2009 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, 2011 was 10.90% (2010 - 13.00%; 2009 - 13.00%) based on equity which is capped at 45%.

On December 9, 2011, the Government of New Brunswick tabled and subsequently passed legislation related to the regulatory process for setting rates for gas distribution within the province. The legislation permits the government to implement new regulations which could affect the franchise agreement between EGNB and the province, impact prior decisions by the province’s independent regulator and influence the regulator’s future decisions. Significant details of the rate setting process were left to be established in the new regulations which have yet to be published.

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, 2011 included an after-tax ROE component of 11.18% (2010 - 11.18%; 2009 - 11.07%).

Alliance Pipeline

The Alliance Pipeline US is regulated by the FERC and Alliance Pipeline Canada is regulated by the NEB. Transportation service agreements with shippers are in place for substantially all of the pipeline capacity until December 2015 under a cost of service methodology. Toll adjustments are filed annually with the regulators. Tolls for the years ended December 31, 2011, 2010 and 2009 included an after-tax ROE component of 10.88% for Alliance Pipeline US and 11.26% (2010 - 11.26%; 2009 - 11.26%) for Alliance Pipeline Canada. Alliance Pipeline tolls are based on a deemed 70% debt and 30% equity structure.

FINANCIAL STATEMENT EFFECTS

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

			Estimated Settlement Period	Earnings Impact1
December 31,	2011	2010	(years)	2011	2010	2009
(millions of Canadian dollars)
Regulatory assets/(liabilities)

Liquids Pipelines

Future income taxes2	527	479	-	36	55	49

Tolling deferrals3	14	132	1	(3)	19	(16)

Deferred transportation revenue8	84	32	29	34	21	-

Gas Distribution

Future income taxes2	224	211	-	9	(12)	(11)

EGNB regulatory deferral4	180	171	30	9	18	15

Future removal and site restoration reserves5	(836)	(773)	-	-	-	6

Purchased gas variance6	-	(144)	1	-	-	-

Pension plans and OPEB, net7	(95)	(97)	-	(2)	-	(2)

Gas Pipelines, Processing and Energy Services

Future income taxes2	1	1	-	-	-	-

Deferred transportation revenue8	124	150	13-15	(18)	(17)	(6)

Sponsored Investments

Future income taxes2	83	94	-	(8)	(3)	(11)

Deferred transportation revenue8	100	98	15	1	5	5

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	The asset represents the regulatory offset to future income tax liabilities to the extent that future income taxes are 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 for regulated pipelines under a cost of service methodology are established each year based on capacity and the allowed revenue requirement. Where actual volumes shipped on the pipeline result in an under or over collection of the annual revenue requirement, a regulatory asset or liability is recognized and incorporated into tolls in the subsequent year or in accordance with the related agreement.

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 no sooner than 2040. The impact of legislative changes passed by the Government of New Brunswick in December 2011 (the specific details of which remain dependent upon regulations which have not yet been published) is not determinable as of February 21, 2012.

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 over the long-term 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 revenue would be adjusted by an equal and offsetting amount as the right to collect the 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 OPEB balance represents the regulatory offset to the OPEB liability to the extent that the amounts are to be collected from customers 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 Southern Lights, Alliance and Vector Pipelines and the negotiated depreciation rates included in the regulated transportation tolls. 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 Southern Lights after 2020, 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 regulators, EGD and certain distribution operations capitalize a percentage of certain operating costs. These operations are 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 would 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, 2011, cumulative costs relating to this consulting contract of $133 million (2010 - $124 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. ACQUISITIONS AND DISPOSITIONS

ACQUISITIONS

Seaway Crude Pipeline Company

On December 20, 2011, Enbridge acquired 50% of the outstanding common units in Seaway Pipeline, a partnership engaged in the crude oil pipeline business in Texas, for cash consideration of $1.2 billion (US$1.2 billion). The Company’s investment in Seaway Pipeline is accounted for as a joint venture interest (Note 10).

December 20,		2011
(millions of Canadian dollars)

Fair value of net assets acquired:

Current assets		5

Property, plant and equipment		536

Goodwill		638

Current liabilities		(4)
		1,175

Purchase Price:

Cash (net of $9 million cash acquired)		1,175

A net loss of $1 million related to transaction costs was recognized in Earnings for the year ended December 31, 2011. Had the acquisition occurred on January 1, 2011, an unaudited proforma net loss of $2 million, including $1 million of transaction costs, would have been recognized as earnings. The entire amount of

acquired goodwill is expected to be tax deductible for United States income tax purposes.

Tonbridge Power Inc.

On October 13, 2011, Enbridge acquired 100% of the 36 million outstanding common shares of Tonbridge Power Inc. (Tonbridge), an independent company engaged in constructing an electric transmission line between Montana and Alberta, for $20 million in cash at a price of $0.54 per share.

October 13,		2011
(millions of Canadian dollars)

Fair value of net assets acquired:

Working capital deficiency		(5)

Property, plant and equipment		196
Intangible assets		17
Long-term debt		(182)

Other long-term liabilities		(21)
		5

Purchase Price:

Cash (net of $15 million cash acquired)		5

No revenue from Tonbridge was recognized in 2011 as the transmission line is not yet in service. A net loss of $1 million was recognized in income for the period from October 13, 2011 to December 31, 2011 related to operating and administrative expenses. An unaudited proforma net loss of $38 million, including $6 million of transaction costs, would have been recognized in income in 2011 had the acquisition occurred on January 1, 2011.

DISPOSITIONS

Gain on Sale of Investments

December 31,	2011	2010	2009
(millions of Canadian dollars)

NetThruPut (NTP)	-	-	29

Oleoducto Central S.A. (OCENSA)	-	-	336
	-	-	365

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 and were 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. Earnings from the OCENSA investment were 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.

7. ACCOUNTS RECEIVABLE AND OTHER

December 31,	2011		2010
(millions of Canadian dollars)
Unbilled revenues	1,535		1,284
Trade receivables	699		740
Taxes receivable	157		205
Regulatory assets	80		182
Current derivative assets (Note 23)	465		170
Due from affiliates (Note 30)	69		63
Prepaid expenses and deposits	42		36
Dividends receivable	32		16
Other	113		72
Allowance for doubtful accounts (Note 23)	(56	)	(62	)
	3,136		2,706

8. INVENTORY

December 31,	2011		2010
(millions of Canadian dollars)
Natural gas	488		537
Other commodities	251		276
	739		813

9. PROPERTY, PLANT AND EQUIPMENT

December 31, 2011	Weighted Average Depreciation Rate		Cost	Accumulated Depreciation	Net
(millions of Canadian dollars)
Liquids Pipelines
Pipeline	2.8	%	7,482	1,811	5,671
Pumping equipment, buildings, tanks and other	3.5	%	5,098	1,367	3,731
Land and right-of-way	3.0	%	232	38	194
Under construction	-		1,718	-	1,718
			14,530	3,216	11,314
Gas Distribution
Gas mains, services and other	4.0	%	6,961	1,401	5,560
Land and right-of-way	2.5	%	79	30	49
Under construction	-		137	-	137
			7,177	1,431	5,746
Gas Pipelines, Processing and Energy Services
Pipeline	3.6	%	2,171	814	1,357
Wind turbines, solar panels and other1	5.8	%	1,208	125	1,083
Land and right-of-way	2.6	%	50	14	36
Under construction	-		567	-	567
			3,996	953	3,043
Sponsored Investments
Pipeline	4.0	%	1,105	398	707
Wind turbines, solar panels and other1	3.4	%	1,744	225	1,519
Under construction	-		23	-	23
			2,872	623	2,249
Corporate
Other	2.9	%	270	30	240
Under construction	-		31	-	31
			301	30	271
			28,876	6,253	22,623

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
Gas mains, services and other	3.6	%	6,605	1,272	5,333
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 other1	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
Wind turbines, solar panels and other1	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

1 In October 2011, Enbridge Pipelines Inc. (EPI) sold three renewable energy assets to the Fund. As a result, at December 31, 2011, $1,087 million of property, plant and equipment was reclassified from Gas Pipelines, Processing and Energy Services to Sponsored Investments. The December 31, 2010 balance of $1,103 million has not been reclassified for presentation purposes.

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		2011	2010
(millions of Canadian dollars)
Liquids Pipelines
Chicap Pipeline	43.8	%	27	27
Mustang Pipeline	30.0	%	27	26
Woodland Pipeline	50.0	%	79	23
Seaway Pipeline (Note 6)	50.0	%	1,186	-
Gas Pipelines, Processing and Energy Services
Enbridge Offshore Pipelines - various joint ventures	22.0%-74.3	%	420	433
Alliance Pipeline US	50.0	%	293	318
Vector Pipeline	60.0	%	347	349
Aux Sable1	42.7%-50.0	%	217	86
Lac Alfred Wind Project (Lac Alfred)2	50.0	%	130	-
Other	33.3%-70.0	%	21	27
Sponsored Investments
Alliance Pipeline Canada	50.0	%	642	660
Other	33.0%-50.0	%	58	56
			3,447	2,005

1 In July 2011, the Company, through its affiliate Aux Sable, acquired a 42.7% interest in the Palermo Conditioning Plant and the Prairie Rose Pipeline for $76 million.

2 In December 2011, the Company acquired a 50% interest in the Lac Alfred for $128 million.

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

Year ended December 31,	2011		2010		2009
(millions of Canadian dollars)
Earnings
Revenues	804		771		781
Commodity costs	(138	)	(92	)	(74	)
Operating and administrative	(200	)	(203	)	(226	)
Depreciation and amortization	(163	)	(163	)	(171	)
Interest expense	(75	)	(82	)	(99	)
Other income/(expense)	(2	)	(1	)	10
Proportionate share of earnings	226		230		221
Cash flows
Cash provided by operating activities	392		349		342
Cash used in investing activities	(196	)	(57	)	(49	)
Cash used in financing activities	(71	)	(78	)	(133	)
Proportionate share of increase in cash and cash equivalents	125		214		160

December 31,	2011		2010
(millions of Canadian dollars)
Financial position
Current assets	229		171
Property, plant and equipment, net	3,019		2,331
Intangible assets	210		166
Goodwill	959		321
Deferred amounts and other assets	267		270
Current liabilities	(239	)	(150	)
Non-recourse long-term debt	(951	)	(1,061	)
Other long-term liabilities	(47	)	(43	)
Proportionate share of net assets	3,447		2,005

During the year ended December 31, 2010, the Company acquired an additional 20% interest in Olympic Pipe Line 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) for $28 million (US$27 million), 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.

11. LONG-TERM INVESTMENTS

	Ownership
December 31,	Interest		2011	2010
(millions of Canadian dollars)
Equity investments
Sponsored Investments
The Partnership	23.0	%	1,711	1,473
Enbridge Energy, Limited Partnership - Series AC	66.7	%	453	463
Corporate
Noverco Common Shares	38.9	%	-	14
Other	5.0%-20	%	35	13
Other investments
Corporate
Noverco Preferred Shares			285	181
Value Creation Inc.			29	29
Fuel Cell Energy Ltd.			11	25
Other			16	-
			2,540	2,198

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 $120 million at December 31, 2011 (2010 - $123 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 23.0% ownership in EEP, through a 2.0% general partner interest, a 16.0% interest in Class A units, a 2.7% interest in Class B units and a 2.3% interest in EEP as a result of a 16.8% investment in EEM, which owns 13.3% of EEP through its 100% interest in EEP’s i-units.

The Company recorded investment income inclusive of incentive earnings, before tax, of $296 million (2010 - $51 million; 2009 - $175 million) for the year ended December 31, 2011.

During the year ended December 31, 2011, EEP issued Class A units and, because Enbridge did not fully participate in this issuance, a dilution gain of $66 million net of income taxes of $53 million and noncontrolling interests of $22 million, was recognized in earnings. As a result, Enbridge’s ownership interest in EEP decreased from 25.5% to 23.0%.

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 noncontrolling interest, was recognized in earnings. As a result, Enbridge’s ownership interest in EEP decreased from 27.0% to 25.5%.

Although 83.2% of EEM is widely held, the Company has voting control and therefore consolidates its investment in EEM.

Enbridge Energy, Limited Partnership

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 $53 million for the year ended December 31, 2011 (2010 - $63 million; 2009 - $12 million).

During 2011, the Board of Directors of EEM declared distributions of $74 million (US$76 million) (2010 - $40 million (US$39 million)) payable to the Company relating to its series AC interest in the Alberta Clipper project.

Noverco

During the year ended December 31, 2011, the Company invested $144 million in cash and $255 million in a dividend received from Noverco to increase its common share investment from 32.1% to 38.9%. In addition, the Company received $399 million of preferred shares which are entitled to a cumulative preferred dividend based on the average yield of Government of Canada bonds maturing in greater than 10 years plus 4.40%. There has been no change in the accounting for the Company’s common or preferred share investments in Noverco as a result of the restructuring. The Company’s interest in Noverco continues to be accounted for as a long-term investment and is included in the Corporate segment.

The Company adjusted its preferred share investments in Noverco which are entitled to cumulative preferred dividends based on the average yield of Government of Canada bonds maturing in greater than 10 years plus a range of 4.34% to 4.40% to $285 million at December 31, 2011 (2010 - $181 million) due to the restructure of Noverco in 2011.

The Company also reduced its equity investment in Noverco common shares to nil at December 31, 2011 (2010 - $14 million) due to the restructure. Noverco owns an approximate 8.9% (2010 - 9.0%) reciprocal shareholding in the shares of the Company. As a result, the Company has an indirect pro-rata interest of 3.5% (2010 - 2.9%) in its own shares. Both the equity investment in Noverco and shareholders’ equity have been reduced by the reciprocal shareholding of $187 million at December 31, 2011 (2010 - $154 million). 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 2011, the Company recorded equity investment loss of $6 million (2010 - $6 million of earnings; 2009 - $10 million of earnings) related to its interest in Noverco.

12. DEFERRED AMOUNTS AND OTHER ASSETS

December 31,	2011	2010
(millions of Canadian dollars)
Regulatory assets	1,434	1,419
Long-term portion of derivative assets (Note 23)	549	462
Affiliate long-term note receivable (Note 30)	336	334
Pension asset (Note 27)	320	301
Contractual receivables	288	277
Other	293	93
	3,220	2,886

At December 31, 2011, deferred amounts of $63 million (2010 - $66 million) were subject to amortization and are presented net of accumulated amortization of $43 million (2010 - $39 million). Amortization expense in 2011 was $6 million (2010 - $9 million; 2009 - $7 million).

13. INTANGIBLE ASSETS

December 31, 2011	Weighted Average Amortization Rate	Cost	Accumulated Amortization	Net
(millions of Canadian dollars)
Software	13.4%	521	199	322
Transportation agreements	4.2%	241	79	162
Power purchase agreements and other	10.4%	122	6	116
		884	284	600

December 31, 2010	Weighted Average Amortization Rate	Cost	Accumulated 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

Total amortization expense for intangible assets was $61 million for the year ended December 31, 2011 (2010 - $60 million; 2009 - $44 million). Assuming no asset additions or impairments, the Company expects aggregate amortization expense for the years ending December 31, 2012 through 2016 of $62 million, $55 million, $48 million, $43 million and $38 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, 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
Foreign exchange and other	-	-	1	-	-	1
Acquired (Note 6)	638	-	-	-	-	638
Balance at December 31, 2011	673	-	43	308	-	1,024

In 2011, the Company recognized $638 million of goodwill on the acquisition of a 50% interest in Seaway Pipeline. In 2010, the Company recognized $17 million of goodwill on the acquisition of the remaining 50% interest in Hardisty Caverns.

15. ACCOUNTS PAYABLE AND OTHER

December 31,	2011	2010
(millions of Canadian dollars)
Operating accrued liabilities	2,068	1,677
Trade payables	153	232
Construction payables	224	253
Taxes payable	283	156
Current derivative liabilities (Note 23)	711	138
Security deposits	84	78
Contractor holdbacks	40	78
Other	159	76
	3,722	2,688

16. DEBT

	Weighted Average
December 31,	Interest Rate	Maturity	2011		2010
(millions of Canadian dollars)
Liquids Pipelines
Debentures	8.20%	2024	200		200
Medium-term notes	5.05%	2012-2040	2,435		2,435
Southern Lights project financing1	2.52%	2013-2014	1,449		1,488
Commercial paper and credit facility draws, net			26		26
Other2			13		15
Gas Distribution
Debentures	9.85%	2024	85		235
Medium-term notes	5.51%	2014-2050	2,295		2,195
Commercial paper and credit facility draws, net			556		334
Sponsored Investments
Medium-term notes	4.72%	2014-2020	415		290
Credit facility draws, net			260		130
Corporate
U.S. dollar term notes3	5.48%	2014-2017	1,119		1,094
Medium-term notes	4.74%	2013-2040	3,518		2,918
Commercial paper and credit facility draws, net4			2,785		2,776
Deferred debt issue costs and other			(99	)	(95	)
Total debt			15,057		14,041
Current maturities			(252	)	(154	)
Short-term borrowings	1.07%		(548	)	(326	)
Long-term debt			14,257		13,561

1 2011 - $360 million and US$1,071 million (2010 - $388 million and US$1,106 million).

2 Primarily capital lease obligations.

3 2011 - US$1,100 million (2010 - US$1,100 million).

4 2011 - $987 million and US$1,780 million (2010 - $2,515 million and US$265 million).

Debenture and term note maturities for the years ending December 31, 2012 through 2016 are $252 million, $451 million, $898 million, $916 million and $701 million, respectively. The Company’s debentures and term notes bear interest at fixed rates and the interest obligations for the years ending December 31, 2012 through 2016 are $557 million, $536 million, $515 million, $475 million and $450 million, respectively.

INTEREST EXPENSE

Year ended December 31,	2011		2010		2009
(millions of Canadian dollars)
Debentures and medium-term notes	598		578		494
Non-recourse long-term debt (Note 17)	65		75		83
Commercial paper and credit facility draws	71		63		71
Southern Lights project financing	38		37		45
Capitalized	(61	)	(66	)	(96	)
	711		687		597

CREDIT FACILITIES

December 31, 2011	Maturity Dates2	Total Facilities	Credit Facility Draws3	Available
(millions of Canadian dollars)
Liquids Pipelines	2013	300	26	274
Gas Distribution	2012-2013	717	556	161
Sponsored Investments	2013	500	268	232
Corporate	2012-2016	5,653	2,832	2,821
		7,170	3,682	3,488
Southern Lights project financing1	2013-2014	1,576	1,466	110
Total credit facilities		8,746	5,148	3,598

1 Total facilities inclusive of $61 million for debt service reserve letters of credit.

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

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

Credit facilities carry a weighted average standby fee of 0.17% 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 2012 to 2016.

Commercial paper and credit facility draws, net of short-term borrowings, of $3,079 million (2010 - $2,940 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	2011		2010
(millions of Canadian dollars)
Gas Pipelines, Processing and Energy Services
Long-term credit facilities1		2015	5		1
Senior notes2	6.78%	2015-2025	325		347
Term debt3	3.54%	2012-2019	31		29
Capital lease obligations	10.60%	2020	31		32
Sponsored Investments
Credit facilities		2012-2015	23		23
Senior notes	6.67%	2015-2025	638		675
Fair value increment on senior notes acquired			25		29
Deferred debt issue costs and other			(5	)	(5	)
Total non-recourse debt			1,073		1,131
Current maturities			(122	)	(70	)
Non-recourse long-term debt			951		1,061

1 2011 - US$5 million (2010 - US$1 million).

2 2011 - US$319 million (2010 - US$349 million).

3 2011 - US$26 million (2010 - US$24 million).

Maturities on non-recourse borrowings for the years ending December 31, 2012 through 2016 are $122 million, $78 million, $81 million, $86 million and $64 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, 2012 through 2016 are $67 million, $62 million, $56 million, $51 million and $46 million, respectively.

Certain assets of Alliance Pipeline Canada and Alliance Pipeline US, with a carrying value of $959 million and $693 million, respectively, are pledged as collateral to Alliance Pipeline Canada and to Alliance Pipeline US lenders.

18. OTHER LONG-TERM LIABILITIES

December 31,	2011	2010
(millions of Canadian dollars)
Future removal and site restoration reserves (Note 5)	836	773
Regulatory liabilities	189	198
Derivative liabilities (Note 23)	433	133
OPEB liabilities (Note 27)	127	118
Other	307	251
	1,892	1,473

19. NONCONTROLLING INTERESTS

December 31,	2011	2010
(millions of Canadian dollars)
Enbridge Energy Management, L.L.C. (EEM)	475	394
Enbridge Income Fund (the Fund)	227	109
Enbridge Gas Distribution Inc. (EGD) Preferred Shares	100	100
Talbot Windfarm, LP (Talbot)	-	26
Greenwich Windfarm, LP (Greenwich)	26	12
Other	18	17
	846	658

Noncontrolling interests in EEM represents the 83.2% of the listed shares of EEM not held by the Company. During the year ended December 31, 2011, EEM completed a listed share issuance, in which the Company did not participate, resulting in an increase in the noncontrolling interests.

Noncontrolling interests in the Fund at December 31, 2011 represents 64.6% of interests that are held by third parties. During the year ended December 31, 2011, the Fund acquired the Ontario Wind, Sarnia Solar and Talbot Wind energy projects from a wholly owned subsidiary of Enbridge for proceeds of $1.2 billion. Ordinary trust units were issued by the Fund to partially finance the acquisition, resulting in an increase in interests held by third parties. Contributions from noncontrolling interests for the year ended December 31, 2011 included $168 million attributable to the Fund’s common trust unit issuance.

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, 2011, no preferred shares have been redeemed.

Noncontrolling interests in both Talbot and Greenwich represent 10% of partnership units held by a third party. During the year ended December 31, 2011, the Company acquired the remaining 10% interest in Talbot for $28 million, increasing its ownership interest to 100%. Effective October 21, 2011, ownership of Talbot was transferred to the Fund.

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 preference shares.

COMMON SHARES

	2011		2010		2009
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	770	3,683	756	3,379	746	3,194
Common shares issued	-	-	-	-	-	4
Shares issued on exercise of stock options	4	57	6	80	2	38
Dividend Reinvestment and Share
Purchase Plan (DRIP)	7	229	8	224	8	143
Balance at end of year	781	3,969	770	3,683	756	3,379

PREFERENCE SHARES

	2011		2010		2009
December 31,	Number of Shares	Amount	Number of Shares	Amount	Number of Shares	Amount
(millions of Canadian dollars;
number of preference shares in millions)
Preference shares, Series A	5	125	5	125	5	125
Preference shares, Series B issued1	20	490	-	-	-	-
Preference shares, Series D issued2	18	441	-	-	-	-
Balance at end of year		1,056		125		125

1 Gross proceeds - $500 million; net issuance costs - $10 million.

2 Gross proceeds - $450 million; net issuance costs - $9 million.

Characteristics of the preference shares are as follows:

	Initial Yield		Dividend	1	Per Share Cash Dividend Declared	Per share Base Redemption Value2	Redemption and Conversion Option Date 2,3	Right to Convert3,4
(Canadian dollars unless otherwise stated)
Preference shares, Series A	5.5	%	1.3750		1.3750	25	-	-
Preference shares, Series B	4.0	%	1.0000		0.4192	25	June 1, 2017	Series C
Preference shares, Series D	4.0	%	1.0000		0.2705	25	March1, 2018	Series E

1 Fixed, cumulative, quarterly preferential dividend per share per year.

2 The Company may at its option, redeem all or a portion of the outstanding preference shares for the base redemption value per share plus all accrued and unpaid dividends on the Redemption Option Date and on every fifth anniversary thereafter.

3 The holder will have the right, subject to certain conditions, to convert their shares into Cumulative Redeemable Preference Shares of a specified Series on the Conversion Option Date and every fifth anniversary thereafter.

4 Holders will be entitled to receive quarterly floating rate cumulative dividends per share at a rate equal to: $25 x (number of days in quarter/365) x (90-day Government of Canada treasury bill rate + 2.40% (Series C) or 2.37% (Series E)).

Subsequent to year end, on January 18, 2012, the Company issued 20 million Series F Preference Shares for gross proceeds of $500 million. The 4.0% Cumulative Redeemable Preference Shares, Series F are entitled to the same dividends, redemption and conversion terms as the Series B and Series D Preference Shares. Redemption of Series F Preference Shares by the Company or conversion by holders into Cumulative Redeemable Preference Shares, Series G can occur on June 1, 2018 and on June 1 of every fifth year thereafter. The holders of Series G Preference Shares will be entitled to receive quarterly floating rate cumulative dividends per share at a rate equal to $25 multiplied by the number of days in the

quarter divided by 365 and multiplying that product by the sum of the then 90-day Government of Canada treasury bill rate plus 2.51%.

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 25 million (2010 - 22 million; 2009 - 22 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,	2011	2010	2009
(number of common shares in millions)
Weighted average shares outstanding	751	741	728
Effect of dilutive options	10	7	5
Diluted weighted average shares outstanding	761	748	733

For the year ended December 31, 2011, 48,000 anti-dilutive stock options (2010 - 92,000; 2009 - 1,113,000) with a weighted average exercise price of $32.02 (2010 - $27.84; 2009 - $20.49) were excluded from the diluted earnings per share calculation.

STOCK SPLIT

Effective May 25, 2011, a two-for-one split of the common shares of the Company was completed. All references to the number of shares outstanding, earnings per common share, diluted earnings per common share, dividends per common share and outstanding option information have been retroactively restated to reflect the impact of the stock split.

DIVIDEND REINVESTMENT AND SHARE PURCHASE PLAN

Under the DRIP, 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 DRIP 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 ISO Plan, the PBSO Plan, the PSU Plan and the RSU Plan. A maximum of 60 million common shares were reserved for issuance under the 2002 ISO plan, of which 43 million have been issued to date. In 2007, a new reserve of 33 million common shares was approved and established and in 2011 an increase of 19 million to the reserved common shares was approved, resulting in a total of 52 million shares being available for the 2007 ISO and PBSO plans, of which 1 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, 2011 for ISOs is $16 million (2010 - $11 million; 2009 - $17 million).

Outstanding Incentive Stock Options

December 31,	2011		2010		2009
	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	25,460	18.34	24,932	17.01	21,300	15.53
Options granted	6,041	28.78	4,000	22.70	6,056	19.81
Options exercised	(3,926)	14.23	(3,436)	14.52	(2,374)	11.01
Options cancelled or expired	(110)	25.87	(36)	12.45	(50)	20.33
Options at end of year	27,465	21.19	25,460	18.34	24,932	17.01
Options vested	14,214	17.93	13,764	16.01	13,100	14.48

The total intrinsic value of ISOs exercised during the year ended December 31, 2011 was $68 million (2010 - $38 million; 2009 - $22 million) and cash received on exercise was $56 million (2010 - $50 million; 2009 - $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, 2011 was $285 million (2010 - $182 million) and $194 million (2010 - $131 million), respectively.

Incentive Stock Option Characteristics

December 31, 2011

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)

10.00-12.49

1,195

1.0

10.45

1,195

1.0

10.45

12.50-14.99

1,440

2.1

12.86

1,440

2.1

12.86

15.00-17.49

2,578

4.7

15.99

1,963

4.0

15.94

17.50-19.99

7,877

6.0

19.30

5,486

5.5

19.08

20.00-22.49

5,202

6.4

20.55

3,390

6.2

20.37

22.50-24.99

3,102

8.1

23.30

717

8.1

23.30

27.50-29.99

6,023

9.1

28.90

8.9

27.84

30.00-32.49

9.7

32.02

27,465

6.5

21.08

14,214

4.9

17.83

The total fair value of options vested under the ISO Plan during the year ended December 31, 2011 was $17 million (2010 - $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,	2011	2010	2009
Fair value per option (Canadian dollars)1	4.19	3.44	3.56
Valuation assumptions
Expected option term (years)2	6	6	6
Expected volatility3	18.63%	19.72%	28.08%
Expected dividend yield4	3.40%	3.64%	3.87%
Risk-free interest rate5	2.85%	2.70%	2.24%

1 Options granted to United States employees are based on New York Stock Exchange prices. The option value and assumptions shown are based on a weighted average of the United States options and the Canadian options. The fair value per option were $4.01 (2010 - $3.28; 2009 - $3.37) for Canadian employees and US$5.11 (2010 - US$4.00; 2009 - US$3.43) 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. Beginning in 2010, implied volatility observable in call option values near the grant date is also considered in determining the expected volatility.

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 United States Treasury Bond Yields.

As of December 31, 2011, unrecognized compensation cost related to non-vested share-based compensation arrangements granted under the ISO plan was $24 million. The cost is expected to be fully recognized by December 31, 2014.

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, 2011 for PBSOs was $2 million (2010 - $2 million; 2009 - $2 million).

Outstanding Performance Based Stock Options

December 31,	2011		2010		2009
	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	4,294	18.51	6,790	16.85	7,476	16.36
Options exercised	(167)	18.29	(2,078)	13.12	(686)	11.58
Options cancelled	-	-	(418)	18.29	-	-
Options at end of year	4,127	18.52	4,294	18.51	6,790	16.85
Options vested	3,191	18.47	2,524	18.44	1,600	11.58

The total intrinsic value of PBSOs exercised during the year ended December 31, 2011 was $2 million (2010 - $26 million; 2009 - $6 million) and cash received on exercise was $3 million (2010 - $27 million; 2009 - $8 million). The total intrinsic value of PBSOs outstanding and vested at December 31, 2011 is $54 million (2010 - $30 million) and $42 million (2010 - $18 million), respectively.

Performance Based Stock Option Characteristics

December 31, 2011

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)

18.29

3,627

3.6

18.29

2,891

3.6

18.29

20.21

500

3.6

20.21

300

3.6

20.21

4,127

3.6

18.52

3,191

3.6

18.47

The total fair value of options vested under the PBSO Plan during the year ended December 31, 2011 was $2 million (2010 - $2 million; 2009 - $2 million).

As of December 31, 2011, unrecognized compensation cost related to non-vested share-based compensation arrangements granted under the PBSO plan was $1 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 2009, 2010 and 2011 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, 2011 for PSUs was $42 million (2010 - $27 million; 2009 - $20 million). To calculate the 2011 expense, multipliers of two, based upon multiplier estimates at December 31, 2011, were used for each of the 2009, 2010 and 2011 PSU grants.

Outstanding Performance Stock Units

December 31,	2011		2010		2009
Units at beginning of year	955,894		660,832		590,856
Units granted	317,000		572,400		339,200
Units matured	(375,190	)	(319,634	)	(303,764	)
Dividend reinvestment	39,453		42,296		34,540
Units at end of year	937,157		955,894		660,832

Of the PSUs outstanding at December 31, 2011, 610,459 units have a performance period ending December 31, 2012 and 326,698 have a performance period ending December 31, 2013. The total intrinsic value of PSUs outstanding at December 31, 2011 is $71 million (2010 - $54 million; 2009 - $31 million). The total amount paid during the year ended December 31, 2011 for PSUs was $17 million (2010 - $14 million; 2009 - $9 million).

RESTRICTED STOCK UNITS

Enbridge has an 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, 2011 for RSUs was $31 million (2010 - $29 million; 2009 - $23 million).

Outstanding Restricted Stock Units

December 31,	2011		2010		2009
Units at beginning of year	2,095,970		1,975,754		1,400,068
Units granted	938,100		937,200		1,087,000
Units cancelled	(92,276	)	(60,908	)	(36,858	)
Units matured	(1,132,674	)	(855,504	)	(565,312	)
Notional dividend reinvestment	92,865		99,428		90,856
Units at end of year	1,901,985		2,095,970		1,975,754

The total intrinsic value of RSUs outstanding at December 31, 2011 is $72 million (2010 - $59 million; 2009 - $47 million). The total liability paid during the year ended December 31, 2011 for RSUs was $39 million (2010 - $24 million; 2009 - $12 million).

As of December 31, 2011, unrecognized compensation expense related to non-vested units granted under the PSU and RSU plans was $68 million and is expected to be fully recognized by December 31, 2013.

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

	Net Investment Hedges		Cumulative Translation Adjustment		Equity Investees		Noncontrolling Interests	Cash Flow Hedges		Total
(millions of Canadian dollars)
Balance at January 1, 2009	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	)
Changes during the year	(21	)	2421		(91	)	13	(513	)	(370	)
Tax impact	2		-		30		-	126		158
	(19	)	242		(61	)	13	(387	)	(212	)
Balance at December 31, 2011	461		(1,122	)	(104	)	135	(464	)	(1,094	)

1 Changes in the Cumulative Translation Adjustment balance during the year included the release of a $155 million loss to earnings following the partial liquidation of an investment in a foreign subsidiary.

23. RISK MANAGEMENT AND FINANCIAL INSTRUMENTS

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, if any, 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. The Company uses a combination of qualifying and non-qualifying derivative instruments to manage the risks noted below.

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, and certain revenues and expenses denominated in United States dollars. 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 Company uses a combination of qualifying and non-qualifying derivative instruments to manage variability in cash flows arising from its United States dollar investments and subsidiaries, and primarily non-qualifying derivative instruments to manage variability arising from certain revenues and expenses denominated in United States dollars.

The impact of a $0.05 strengthening of the Canadian dollar across the forward curve relative to the United States dollar at December 31, 2011, would have resulted in a $310 million increase (2010 - $81 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. Pay fixed-receive floating interest rate swaps and options are used to hedge against the effect of future interest movements. The Company has implemented a program to significantly mitigate the volatility of short-term interest rates on interest expense through 2016 at an average swap rate of 2.27%

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 2015. A total of $5,200 million of future fixed rate term debt issuances have been hedged at an average swap rate of 3.86%. 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. The Company uses primarily qualifying derivative instruments to manage interest rate risk.

At December 31, 2011, a 1% increase across the interest rate yield curve at that date, with all other variables constant, would have resulted in no change (2010 - nil) in earnings and a $457 million increase (2010 - $178 million) in OCI in the year due to the revaluation of interest rate derivatives outstanding at December 31, 2011. A 1% increase across the interest rate yield curve, with all other variables constant, would have caused a $23 million decrease (2010 - $22 million) in earnings due to increased interest expense related to the Company’s variable rate debt outstanding at December 31, 2011 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. These commodities include natural gas, power, crude oil and NGLs. The Company employs financial derivative instruments to fix a portion of the variable price exposures that arise from physical transactions involving these commodities. The Company uses primarily non-qualifying derivative instruments to manage commodity price risk.

The Company has implemented a program to mitigate the volatility from fractionation spreads (natural gas/NGLs) that impact earnings from its ownership interest in the Aux Sable natural gas processing plant and its indirect ownership of the gathering and process business held by EEP.

The Company uses EaR as a metric to monitor certain commodity price risk exposures, principally those associated with its ownership of Aux Sable, its ownership of EEP and the activities of its energy services subsidiaries. The EaR metric measures the price exposures, net of the impact of financial derivatives used to manage such exposures. The Company has estimated the following maximum adverse change in projected 12 month earnings that has a maximum 2.5% chance of resulting from such commodity price risk over a one month period.

Equity Price Risk

Equity price risk is the risk of earnings fluctuations due to changes in the Company’s share price. The Company has exposure to its own common share price through the issuance of various forms of stock based compensation, which affect earnings through revaluation of the outstanding units every period. The Company uses equity derivatives to manage the earnings volatility derived from one form of stock based compensation, RSUs (Note 21).

Due to revaluation of the equity derivative contracts at December 31, 2011, the impact of a $4 increase in the Company’s share price would have been a $3 million increase in earnings (2010 - $2 million) and a $2 million increase in OCI (2010 - $1 million). The earnings impact of non-qualifying equity derivatives partially offsets earnings impacts due to the revaluation of liabilities associated with the Company’s RSUs.

TOTAL DERIVATIVE INSTRUMENTS

The following tables summarize the balance sheet location and fair value of the Company’s derivative instruments. The Company had no outstanding fair value hedges as at December 31, 2011 or 2010.

December 31, 2011	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		315		334
Interest rate contracts	-		-		7		7
Commodity contracts	-		-		114		114
Equity contracts	3		-		7		10
	7		15		443		465
Deferred amounts and other (Note 12)
Foreign exchange contracts	15		79		203		297
Interest rate contracts	1		-		22		23
Commodity contracts	1		-		223		224
Equity contracts	3		-		2		5
	20		79		450		549
Accounts payable and other (Note 15)
Foreign exchange contracts	(4	)	-		(275	)	(279	)
Interest rate contracts	(341	)	-		(3	)	(344	)
Commodity contracts	(1	)	-		(87	)	(88	)
	(346	)	-		(365	)	(711	)
Other long-term liabilities (Note 18)
Foreign exchange contracts	(35	)	(5	)	(51	)	(91	)
Interest rate contracts	(303	)	-		(18	)	(321	)
Commodity contracts	(2	)	-		(19	)	(21	)
	(340	)	(5	)	(88	)	(433	)
Total net derivative asset/(liability)
Foreign exchange contracts	(20	)	89		192		261
Interest rate contracts	(643	)	-		8		(635	)
Commodity contracts	(2	)	-		231		229
Equity contracts	6		-		9		15
	(659	)	89		440		(130	)

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
Equity 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	)
Equity contracts	-		-	1		1
	(108	)	115	354		361

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

	2011		2010
December 31,	Maturity	Notional Principal or Quantity Outstanding	Maturity	Notional Principal or Quantity Outstanding
U.S. dollar forwards - purchase (millions of United States dollars)	2012-2020	1,281	2011-2020	1,185
U.S. dollar forwards - sell (millions of United States dollars)	2012-2020	10,866	2011-2020	3,516
Interest rate contracts (millions of Canadian dollars)	2012-2029	16,540	2011-2029	10,772
Commodity contracts - energy (billions of cubic feet equivalent)	2012-2013	2	2011-2013	41
Commodity contracts - power (megawatts per hour)	2012-2024	53	2011-2024	2
Equity contracts (millions of shares)	2011-2013	2	2011-2012	1

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,	2011		2010
(millions of Canadian dollars)
Amount of unrealized gain/(loss) recognized in OCI
Cash flow hedges
Foreign exchange contracts	(22	)	(25	)
Interest rate contracts	(545	)	(172	)
Commodity contracts	(6	)	97
Equity contracts	6		(1	)
Net investment hedges
Foreign exchange contracts	(26	)	19
Total unrealized loss recognized in OCI	(593	)	(82	)
Amount of gain/(loss) reclassified from AOCI to earnings (effective portion)
Cash flow hedges
Foreign exchange contracts1	1		(7	)
Interest rate contracts2	18		68
Commodity contracts3	5		(95	)
Equity contracts4	(2	)	1
Total gain/(loss) reclassified from AOCI to earnings (effective portion)	22		(33	)
Amount of ineffectiveness reclassified from AOCI to earnings
Cash flow hedges
Interest rate contracts2	11		-
Total ineffectiveness reclassified from AOCI to earnings	11		-

1 (Gain)/loss reported within Other income in the Consolidated Statements of Earnings.

2 (Gain)/loss reported within Interest expense in the Consolidated Statements of Earnings.

3 (Gain)/loss reported within Operating and administrative expense in the Consolidated Statements of Earnings.

4 (Gain)/loss reported within Operating and administrative expense in the Consolidated Statements of Earnings.

The Company estimates that $33 million of AOCI 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, 2011.

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,	2011		2010		2009
(millions of Canadian dollars)
Foreign exchange contracts1	(179	)	33		232
Interest rate contracts2	9		(2	)	2
Commodity contracts3	244		(5	)	(88	)
Equity contracts4	4		-		-
Total unrealized derivative fair value gain	78		26		146

1 Gain/(loss) reported within Transportation and other services revenues and Other income in the Consolidated Statements of Earnings.

2 Gain/(loss) reported within Interest expense in the Consolidated Statements of Earnings.

3 Gain/(loss) reported within Transportation and other services revenue, Commodity costs and Operating and administrative expense in the Consolidated Statements of Earnings.

4 Gain reported within Operating and administrative expense in the Consolidated Statements 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 12 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, as well as access to capital markets. 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, 2011. 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, 2012 through 2016, 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:

	2012		2013		2014		2015		2016		Thereafter
(millions of Canadian dollars)
Cash inflows	440		213		180		69		74		105
Cash outflows	(401	)	(133	)	(124	)	(77)		(65	)	(610	)
Net cash flows	39		80		56		(8	)	9		(505	)

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 industry standard netting arrangements.

The Company generally has a policy of entering into individual International Securities Dealers Association agreements, or other similar derivative agreements, with the majority of our derivative counterparties. These agreements provide for the net settlement of derivative instruments outstanding with specific counterparties in the event of bankruptcy or other significant credit event, and would reduce the Company’s credit risk exposure on derivative asset positions outstanding with these counterparties in these particular circumstances.

At December 31, 2011 and 2010, the Company had group credit concentrations and maximum credit exposure, with respect to derivative instruments, in the following counterparty segments.

December 31,	2011	2010
(millions of Canadian dollars)
Canadian financial institutions	426	451
Non-Canadian financial institutions	509	125
Other	73	50
	1,008	626

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,	2011		2010
(millions of Canadian dollars)
Balance at beginning of year	(62	)	(74	)
Additional allowance	(26	)	(23	)
Amounts used	32		35
Balance at end of year	(56	)	(62	)

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, 2011	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	420	-	-	-	-	-	-	420	420
Accounts receivable and other	443	-	2,392	-	-	22	279	3,136	2,857
Long-term investments	-	56	-	285	-	-	2,199	2,540	285
Deferred amounts and other assets	450	-	4	-	-	99	2,667	3,220	553
Liabilities
Bank indebtedness	102	-	-	-	-	-	-	102	102
Short-term borrowings	-	-	-	-	548	-	-	548	548
Accounts payable and other	365	-	-	-	2,728	346	283	3,722	3,439
Interest payable	-	-	-	-	114	-	-	114	114
Long-term debt	-	-	-	-	14,509	-	-	14,509	16,772
Non-recourse long-term debt	-	-	-	-	1,073	-	-	1,073	1,248
Other long-term liabilities	88	-	-	-	-	345	1,459	1,892	433

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	342	-	-	-	-	-	-	342	342
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
Bank indebtedness	100	-	-	-	-	-	-	100	100
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

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, 2011	Level 1	Level 2		Level 3		Total
(millions of Canadian dollars)
Financial assets
Current derivative assets
Foreign exchange contracts	-	334		-		334
Interest rate contracts	-	7		-		7
Commodity contracts	1	59		54		114
Equity contracts	-	10		-		10
	1	410		54		465
Long-term derivative assets
Foreign exchange contracts	-	297		-		297
Interest rate contracts	-	23		-		23
Commodity contracts	-	193		31		224
Equity contracts	-	5		-		5
	-	518		31		549
Financial liabilities
Current derivative liabilities
Foreign exchange contracts	-	(279	)	-		(279	)
Interest rate contracts	-	(344	)	-		(344	)
Commodity contracts	-	(42	)	(46	)	(88	)
	-	(665	)	(46	)	(711	)
Long-term derivative liabilities
Foreign exchange contracts	-	(91	)	-		(91	)
Interest rate contracts	-	(321	)	-		(321	)
Commodity contracts	-	(16	)	(5	)	(21	)
	-	(428	)	(5	)	(433	)
Total net derivative asset/(liability)
Foreign exchange contracts	-	261		-		261
Interest rate contracts	-	(635	)	-		(635	)
Commodity contracts	1	194		34		229
Equity contracts	-	15		-		15
	1	(165	)	34		(130	)

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

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,	2011		2010
(millions of Canadian dollars)
Level 3 net derivative liability at beginning of year	(11	)	(28	)
Total gains/(losses), unrealized
Included in earnings1	46		19
Included in OCI	(4	)	3
Settlements	3		(5	)
Level 3 net derivative asset/(liability) at end of year	34		(11	)

1 Gain reported within Transportation and other services revenue, Commodity costs and Operating and administrative expense.

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, 2011 and December 31, 2010.

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 noncontrolling interests less cash and cash equivalents (excluding restricted cash of amounts in trust and proportionately consolidated cash from joint ventures, net of bank indebtedness). 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,	2011		2010
(millions of Canadian dollars)
Short-term borrowings	548		326
Long-term debt (includes current portion)	14,608		13,810
Noncontrolling interests	846		658
Shareholders’ equity	10,122		8,601
Cash and cash equivalents	(77	)	(282	)
	26,047		23,113

The Company seeks to balance a number of objectives when managing capital, including enabling its businesses to operate at the highest efficiency while maintaining safety and reliability; ensuring liquidity for growth opportunities; and minimizing cost of capital. These objectives are primarily met through maintenance of an investment grade credit rating, disciplined investment criteria and sufficient committed credit facilities. Capital is available generally through the issuance of both short and long-term debt and various forms of 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, 2011, including short-term borrowings but excluding non-recourse short and long-term debt, was 58.0% compared with 60.4% at the end of 2010.

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%. This covenant also applies to the Company’s credit facilities that are used to backstop its commercial paper program. Total consolidated capitalization consists of shareholders’ equity, long-term debt, noncontrolling interests and future income taxes.

During the year ended December 31, 2011, the Company was in compliance with externally imposed capital requirements.

26. INCOME TAXES

INCOME TAX RATE RECONCILIATION
Year ended December 31,	2011		2010		2009
(millions of Canadian dollars)
Earnings attributable to Enbridge Inc. before income taxes	1,572		1,221		1,868
Combined statutory income tax rate	27.3	%	28.9	%	30.5	%
Income taxes at statutory rate	429		353		570
Increase/(decrease) resulting from:
Future income taxes related to regulated operations	(35	)	(62	)	(68	)
Higher/(lower) foreign tax rates	84		(22	)	(61	)
Tax rates and legislated tax changes	2		(23	)	(58	)
Non-taxable items, net	1		(2	)	11
Intercompany sale of investments1	98		-		(99	)
Other	(11	)	7		11
Income taxes	568		251		306
Effective income tax rate	36.1	%	20.6	%	16.4	%

1 In October 2011, EPI sold three renewable energy assets to the Fund. As the transaction occurred between entities under common control of the Company, the intercompany gain realized as a result of this transfer has been eliminated, although cash income taxes of $98 million remain as a charge to earnings. The Company retains the benefit of cash taxes paid in the form of increased tax basis of its investment in the underlying partnerships; however, accounting recognition of such benefit is not permitted until such time as the partnerships are sold outside of the consolidated group.

COMPONENTS OF FUTURE INCOME TAXES
December 31,	2011		2010
(millions of Canadian dollars)
Net future income tax liabilities/(assets)
Differences in accounting and tax bases of property, plant and equipment	1,831		1,468
Differences in accounting and tax bases of investments	603		479
Regulatory assets/(liabilities)	308		340
Financial instruments	(24	)	105
Loss carryforwards	(126	)	(81	)
Other	63		56
Net future income tax liability	2,655		2,367

Net future income tax liability of $2,655 million (2010 - $2,367 million) is comprised of future income tax liabilities of $2,696 million (2010 - $2,447 million) net of future income tax assets of $41 million (2010 - $80 million).

At December 31, 2011, the Company had recognized the benefit of unused tax loss carryforwards of $401 million (2010 - $248 million) which start to expire in 2020 and beyond.

GEOGRAPHICAL COMPONENTS OF PRETAX EARNINGS AND INCOME TAXES
Year ended December 31,	2011		2010		2009
(millions of Canadian dollars)
Earnings before income taxes
Canada	600		711		954
United States	839		379		334
Other	133		131		580
	1,572		1,221		1,868
Current income taxes
Canada	207		(29	)	49
United States	(48	)	37		35
Other	(6	)	5		4
	153		13		88
Future income taxes
Canada	31		134		117
United States	384		104		101
	415		238		218
Current and future income taxes	568		251		306

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, 2011 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, 2010	December 31, 2011
Gas Distribution	December 31, 2009	December 31, 2012
United States Plan	December 31, 2010	December 31, 2011

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,	2011	2010	2011	2010
(millions of Canadian dollars)
Change in accrued benefit obligation
Benefit obligation at beginning of year	1,323	1,119	195	170
Service cost	61	48	6	5
Interest cost	73	72	11	11
Amendments	-	-	-	6
Employees’ contributions	-	-	1	1
Actuarial loss1	270	145	28	12
Benefits paid	(54)	(52)	(7)	(7)
Other	8	-	7	-
Effect of foreign exchange rate changes	5	(9)	2	(3)
Benefit obligation at end of year	1,686	1,323	243	195
Change in plan assets
Fair value of plan assets at beginning of year	1,324	1,167	41	38
Actual return on plan assets1	16	127	1	2
Employer’s contributions	72	89	13	9
Employees’ contributions	-	-	1	1
Benefits paid	(54)	(52)	(7)	(7)
Other	4	(1)	4	-
Effect of foreign exchange rate changes	3	(6)	1	(2)
Fair value of plan assets at end of year	1,365	1,324	54	41
Funded status
Benefit obligation	(1,686)	(1,323)	(243)	(195)
Fair value of plan assets	1,365	1,324	54	41
Overfunded/(underfunded) status at end of year	(321)	1	(189)	(154)
Unamortized prior service cost	2	4	5	6
Unamortized transitional obligation/(asset)	(9)	(11)	7	8
Unamortized net loss	648	307	50	22
Net amount recognized in the Consolidated Statements of Financial Position at end of year	320	301	(127)	(118)
Presented as follows:
Deferred amounts and other assets (Note 12)	320	301	-	-
Other long-term liabilities (Note 18)	-	-	(127)	(118)

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,	2011	2010	2009	2011	2010	2009
Discount rate	4.46%	5.64%	6.46%	4.44%	5.55%	6.28%
Average rate of salary increases	3.50%	3.50%	3.73%

Net Benefit Costs Recognized

	Pension Benefits			OPEB
Year ended December 31,	2011	2010	2009	2011	2010	2009
(millions of Canadian dollars)
Benefits earned during the year	61	48	53	6	5	4
Interest cost on projected benefit obligations	73	72	71	11	11	11
Actual return on plan assets	(16)	(127)	(51)	(1)	(2)	(6)
Difference between actual and expected return on plan assets	(76)	47	(27)	(2)	-	3
Amortization of prior service costs	2	2	2	1	-	-
Amortization of transitional obligation	(2)	(2)	(2)	1	1	1
Amortization of actuarial loss	25	19	21	1	1	1
Amount charged to EEP1	(15)	(15)	(20)	(6)	(5)	(5)
Net defined benefit costs on an accrual basis	52	44	47	11	11	9
Defined contribution benefit costs	4	5	4	-	-	-
Net benefit cost recognized in the Consolidated Statements of Earnings	56	49	51	11	11	9

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.

For certain gas distribution businesses, regulatory adjustments are recorded in the Consolidated Statement of Earnings and the Consolidated Statements of Financial Position to reflect the difference between pension expense for accounting purposes and pension expense for ratemaking purposes. Differences arise since accounting is based on an accrual basis whereas ratemaking is based on a cash basis or funding approach. Regulatory assets or liabilities recognized in the Consolidated Statements of Financial Position are disclosed in Note 5.

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,	2011	2010	2009	2011	2010	2009
Discount rate	5.64%	6.47%	6.59%	5.55%	6.31%	6.42%
Average rate of return on pension plan assets	7.30%	7.30%	7.30%	6.00%	6.00%	6.09%
Average rate of salary increases	3.50%	3.73%	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	8.4%	4.5%	2029
Other Medical and Dental	4.5%	4.5%	2029
United States Plan	7.8%	4.5%	2030

A 1% increase in the assumed medical and dental care trend rate would result in an increase of $36 million in the accumulated post-employment benefit obligations and an increase of $3 million in benefit and interest costs. A 1% decrease in the assumed medical and dental care trend rate would result in a decrease of $29 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	United States Plan
Equity securities	62.5%	53.5%	62.5%
Fixed income securities	30.0%	40.0%	30.0%
Other	7.5%	6.5%	7.5%

Expected Rate of Return on Plan Assets

	Pension Benefits		OPEB
Year ended December 31,	2011	2010	2011	2010
Canadian Plans	7.0%	7.25%
United States Plan	7.5%	7.75%	6.0%	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, 2011, assets securing pension benefits were invested 56.6% (2010 - 60.2%) in equity securities, 36.5% (2010 - 33.8%) in fixed income securities and 6.9% (2010 - 6.0%) in other. OPEB assets securing OPEB benefits were invested 55.3% (2010 - 51.2%) in equity securities, 40.3% (2010 - 48.8%) in fixed income securities and 4.3% (2010 - nil) in other.

The following table summarizes the Company’s pension financial instruments at fair value. Non-financial instruments with a carrying value of $82 million (2010 - $69 million) have been excluded from the table below.

December 31,	2011							2010
	Level 1	1	Level 2	2	Level 3	3	Total	Level 1	1	Level 2	2	Level 3	3	Total
(millions of Canadian dollars)
Pension benefits
Cash and cash equivalents	14		-		-		14	10		-		-		10
Fixed income securities
Canadian government bonds	-		115		-		115	-		97		-		97
Corporate bonds and debentures	-		4		-		4	4		-		-		4
Canadian corporate bond index fund	158		-		-		158	151		-		-		151
Canadian government bond index fund	157		-		-		157	149		-		-		149
United States debt index fund	62		-		-		62	47		-		-		47
Equity
Canadian equity securities	148		-		-		148	163		-		-		163
Canadian equity funds	23		74		-		97	26		80		-		106
United States equity funds	172		89		-		261	147		76		-		223
Global equity funds	192		7		-		199	221		19		-		240
Private equity investment 4	-		-		68		68	-		-		65		65
OPEB
Cash and cash equivalents	3		-		-		3	-		-		-		-
Fixed income securities
United States government and government agency bonds	22		-		-		22	20		-		-		20
Equity
United States equity funds	15		14		-		29	9		-		-		9
Global equity funds	-		-		-		-	-		12		-		12

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.

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

		Private Equity Investment
Balance at beginning of year		65
Total gains, unrealized		8
Purchases, issuances, settlements, net		(5)
Balance at end of year		68

PLAN CONTRIBUTIONS BY THE COMPANY

	Pension Benefits		OPEB
Year ended December 31,	2011	2010	2011	2010
(millions of Canadian dollars)
Total contributions	72	89	13	9
Contributions expected to be paid in 2012	94		11

BENEFITS EXPECTED TO BE PAID BY THE COMPANY

Year ended December 31,	2012	2013	2014	2015	2016	2017-2021
(millions of Canadian dollars)
Expected future benefit payments	66	68	72	76	80	466

28. OTHER INCOME

Year ended December 31,	2011	2010	2009
(millions of Canadian dollars)
Net foreign currency gains/(loss)	(109)	132	444
Gain on reduction of EEP ownership interest	141	81	-
AEDC	3	80	135
Interest income on affiliate loans	38	37	38
Noverco preferred dividends income	30	15	15
Hurricane insurance recoveries	-	5	13
OCENSA investment income	-	-	6
Other	9	24	27
	112	374	678

29. CHANGES IN OPERATING ASSETS AND LIABILITIES

Year ended December 31,	2011	2010	2009
(millions of Canadian dollars)
Accounts receivable and other	(94)	(480)	99
Inventory	54	(42)	99
Deferred amounts and other assets	(253)	(98)	(354)
Accounts payable and other	504	254	105
Interest payable	(3)	13	2
Other long-term liabilities	43	60	281
	251	(293)	232

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,	2011	2010	2009
(millions of Canadian dollars)
EEP	380	332	342
Vector Pipeline	6	7	6
	386	339	348

At December 31, 2011, the Company had accounts receivable of $35 million (2010 - $29 million) from EEP and nil (2010 - nil) 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 principal 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.

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,	2011	2010	2009
(millions of Canadian dollars)
Alliance Pipeline Canada	25	25	24
Alliance Pipeline US	17	17	18
Vector Pipeline	25	28	29
	67	70	71

Tidal Energy Marketing (US) L.L.C., 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,	2011	2010	2009
(millions of Canadian dollars)
Purchases	1	2	16
Sales	-	-	(6	)
	1	2	10

Tidal Energy Marketing Inc. and Tidal Energy Marketing (US) L.L.C., 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,	2011	2010	2009
(millions of Canadian dollars)
Alliance Pipeline Canada	17	13	9
Alliance Pipeline US	11	9	7
Vector Pipeline	11	10	16
	39	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,	2011		2010		2009
(millions of Canadian dollars)
Purchases	122		151		80
Sales	(4	)	(3	)	(7	)
	118		148		73

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, 2011, the Company had 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 $348 million (US$342 million) (2010 - $346 million (US$347 million)) loan to EEP for debt financing related to the construction. At December 31, 2011, $336 million (2010 - $334 million) is included in Deferred amounts and other assets with the remaining $12 million (2010 - $12 million) included in Accounts receivable and other. The loan, denominated in United States dollars, matures on March 15, 2020, bears interest at a fixed rate of 5.20% and has a maximum loan amount of $400 million. Semi-annual payments of principal and accrued interest are required. Semi-annual principal payments are based upon a straight-line amortization of the principal balance over a 30 year period.

During the year ended December 31, 2011, the Board of Directors of EEM declared distributions of $74 million (US$76 million) (2010 - $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.

LAKEHEAD LINE 6B CRUDE OIL RELEASE

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 $6 million (2010 - $18 million) for the year ended December 31, 2011.

31. COMMITMENTS AND CONTINGENCIES

COMMITMENTS

The Company has signed contracts for the purchase of services, pipe and other materials, as well as transportation totaling $4,120 million which are expected to be paid within the next five years.

ENBRIDGE GAS DISTRIBUTION INC.

Bloor Street Incident

EGD was charged under both the Ontario Technical Standards and Safety Act (TSSA) and the Ontario Occupational Health and Safety Act (OHSA) in connection with an explosion that occurred in April 2003 on Bloor Street West in Toronto. In December 2011, EGD pleaded guilty before the Ontario Court of Justice to one charge under the OHSA and one charge under the TSSA. The Court imposed a fine of $350,000 in connection with each charge. With the application of a required 25% Victim Fine Surcharge,

the total amount payable by EGD was $875,000, which management believes concludes this matter.

ENBRIDGE GAS NEW BRUNSWICK INC.

Regulatory Matters

As at December 31, 2011, the carrying value of EGNB’s regulatory asset and property, plant and equipment totaled $180 million and $264 million, respectively (2010 - $171 million and $254 million, respectively). Earnings from EGNB approximate $20 million per year. As the details of the regulations have not yet been made available, the effect of such regulations is not determinable as at February 21, 2012. While EGNB continues to engage in discussions with the province about the potential effect of the regulations, EGNB will preserve its legal rights.

ENBRIDGE ENERGY PARTNERS, L.P.

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

Enbridge holds an approximate 23.0% 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 Crude Oil Release

On July 26, 2010, a release of crude oil on Line 6B of EEP’s Lakehead System was reported near Marshall, Michigan. EEP 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. The released crude oil affected approximately 61 kilometres (38 miles) of area along the Talmadge Creek and Kalamazoo River waterways, including residential areas, businesses, farmland and marshland between Marshall and downstream of Battle Creek, Michigan. 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.

Pursuant to an administrative order issued by the Environmental Protection Agency (EPA) under the United States Clean Water Act, EEP was directed to clean up the released oil and remediate and restore the affected areas – a process EEP had begun upon discovering the release.

As at December 31, 2010, EEP estimated that before insurance recoveries, and not including fines and penalties, costs of approximately US$550 million ($96 million after-tax net to Enbridge), excluding lost revenue of approximately US$13 million ($2 million after-tax net to Enbridge), would be incurred in connection with this incident. These costs included emergency response, environmental remediation and cleanup activities associated with the crude oil release, as well as potential claims by third parties.

As at December 31, 2011, EEP revised its total estimate for this crude oil release to US$765 million ($129 million after-tax net to Enbridge), an increase of US$215 million ($33 million after-tax net to Enbridge) from December 31, 2010. The change in estimate was primarily based on a review of costs and commitments incurred, and additional information concerning the reassessment of the overall monitoring area, related cleanup, including submerged oil recovery operations and remediation activities, including the estimated costs related to the additional scope of work set forth in its response to the EPA directive it submitted to the EPA on October 20, 2011. During the fourth quarter of 2011, EEP resubmitted a revised work plan which was approved by the EPA on December 19, 2011.

EEP continues to make progress on the cleanup, remediation and restoration of the areas affected by the Line 6B crude oil release. All of the initiatives EEP undertakes in the monitoring and restoration phases are intended to restore the crude oil release area to the satisfaction of the appropriate regulatory authorities.

Expected losses associated with the Line 6B crude oil release include those costs that are considered probable and that could be reasonably estimated at December 31, 2011. The estimates do not include amounts capitalized or any fines, penalties or claims associated with the release that may later become evident and are before insurance recoveries. Despite the efforts EEP has made to ensure the reasonableness of its estimates, changes to the recorded amounts associated with this release are possible as more reliable information becomes available. There continues to be the potential for EEP to incur additional costs in connection with this crude oil release due to variations in any or all of the cost categories, including modified or revised requirements from regulatory agencies, in addition to fines and penalties as well as expenditures associated with litigation and settlement of claims.

Line 6A Crude Oil Release

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 continues to monitor the areas affected by the crude oil release from Line 6A of its Lakehead System for any additional requirements; however, the cleanup, remediation and restoration of the areas affected by the release have been substantially completed.

As at December 31, 2010, EEP estimated 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 would 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).

As at December 31, 2011, EEP revised its cost estimate for this crude oil release to US$48 million ($7 million after-tax net to Enbridge), before insurance recoveries and excluding fines and penalties. The US$3 million increase was based on a refinement of future costs based on additional information.

EEP included those costs it considered probable and that it could reasonably estimate for purposes of determining its expected losses associated with the Line 6A crude oil release. The estimates do not include consideration of any unasserted claims associated with the release that later may become evident, nor has EEP considered any potential recoveries from third-parties that may later be determined to have contributed to the release. EEP is pursuing recovery of the costs associated with the Line 6A crude oil release from third parties; however, there can be no assurance that any such recovery will be obtained.

Insurance Recoveries

EEP is included in the comprehensive insurance program that is maintained by Enbridge for its subsidiaries and affiliates which renews in May of each year. The program includes commercial liability insurance coverage that is consistent with coverage considered customary for its industry and includes coverage for environmental incidents such as those incurred for the crude oil releases from Lines 6A and 6B, excluding costs for fines and penalties. The claims for the crude oil release for Line 6B are covered by Enbridge’s comprehensive insurance policy that expired on April 30, 2011, which had an aggregate limit of US$650 million for pollution liability. Based on EEP’s increased estimate of costs associated with the crude oil releases, Enbridge and its affiliates will exceed the limits of its coverage under this insurance policy. Additionally, fines and penalties would not be covered under the existing insurance policy.

EEP recognized US$335 million ($50 million after-tax net to Enbridge) for the year ended December 31, 2011 for insurance claims filed in connection with the Line 6B crude oil release. EEP expects to record a receivable for additional amounts claimed for recovery pursuant to insurance policies during the period it deems realization of the claim for recovery is probable.

During the second quarter of 2011, the Company renewed its comprehensive insurance program. The current coverage year has an aggregate limit of US$575 million for pollution liability for the period from May 1, 2011 through April 30, 2012.

Legal and Regulatory Proceedings

A number of United States governmental agencies and regulators have initiated investigations into the Line 6A and Line 6B crude oil releases. Approximately 25 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 crude oil release, including direct actions and actions seeking class status. With respect to the Line 6B crude oil release, no penalties or fines have been assessed against Enbridge, EEP or their affiliates as at December 31, 2011. One claim related to the Line 6A crude oil release has been filed against Enbridge, EEP or their affiliates by the State of Illinois in a United States state court. The parties are currently operating under an agreed interim order.

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 LEGAL AND REGULATORY PROCEEDINGS

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,	2011		2010		2009
(millions of Canadian dollars, except per share amounts)
Earnings attributable to Enbridge Inc. common shareholders under Canadian GAAP	991		963		1,555
Earnings attributable to Enbridge Inc. under Canadian GAAP	1,004		970		1,562
Dilution gains, net of tax4	(88	)	(52	)	-
Gain on acquisition, net of tax1	-		20		-
Inventory valuation adjustment, net of tax2	13		4		(24	)
Amortization of underfunded pension adjustment3	(7	)	(7	)	(7	)
Unrealized foreign exchange loss adjustment12	155		-		-
Earnings/(loss) attributable to noncontrolling interests
EEP	351		(172	)	177
Other	56		25		37
Earnings under U.S. GAAP	1,484		788		1,745
(Earnings)/loss attributable to noncontrolling interests	(407	)	147		(214	)
Earnings attributable to Enbridge Inc. under U.S. GAAP	1,077		935		1,531
Preference share dividends	(13	)	(7	)	(7	)
Earnings attributable to Enbridge Inc. common shareholders under U.S. GAAP	1,064		928		1,524
Earnings per common share attributable to Enbridge Inc. common shareholders	1.42		1.25		2.09
Diluted earnings per common share attributable to Enbridge Inc. common shareholders	1.40		1.24		2.08

COMPREHENSIVE INCOME

Year ended December 31,	2011		2010		2009
(millions of Canadian dollars)
Earnings under U.S. GAAP	1,484		788		1,745
Other comprehensive loss including noncontrolling interests under Canadian GAAP	(225	)	(372	)	(648	)
Underfunded pension adjustment3	(145	)	(38	)	11
Unrealized foreign exchange loss adjustment12	(155	)	-		-
Other comprehensive loss attributable to noncontrolling interests in EEP under U.S. GAAP4	(124	)	(29	)	(62	)
Other comprehensive loss including noncontrolling interests under U.S. GAAP	(649	)	(439	)	(699	)
Comprehensive income	835		349		1,046
Comprehensive (income)/loss attributable to noncontrolling interests	(270	)	224		(80	)
Comprehensive income attributable to Enbridge Inc. under U.S. GAAP	565		573		966
Preference share dividends	(13	)	(7	)	(7	)
Comprehensive income attributable to Enbridge Inc. common shareholders under U.S. GAAP	552		566		959

FINANCIAL POSITION

December 31,	2011				2010
			United				United
	Canada		States		Canada		States
(millions of Canadian dollars)
Assets
Current assets
Cash and cash equivalents4,6	420		811		342		456
Accounts receivable and other4,6,9	3,136		3,990		2,706		3,582
Inventory2,4,6	739		714		813		915
	4,295		5,515		3,861		4,953
Property, plant and equipment, net4,6,8,9	22,623		31,833		20,332		28,562
Long-term investments4,6	2,540		510		2,198		367
Deferred amounts and other assets3,4,6,7,9	3,220		2,615		2,886		2,212
Intangible assets4,8	600		798		478		676
Goodwill4,8	1,024		1,091		385		445
Future income taxes1	41		40		80		79
	34,343		42,402		30,220		37,294

Liabilities and shareholders’ equity
Current liabilities
Bank indebtedness	102		102		100		100
Short-term borrowings	548		548		326		326
Accounts payable and other4,6,9	3,722		4,904		2,688		3,811
Interest payable4	114		185		117		177
Current maturities of long-term debt4	252		354		154		185
Current maturities of non-recourse long-term debt6	122		103		70		68
	4,860		6,196		3,455		4,667
Long-term debt4,7,8	14,257		19,222		13,561		18,374
Non-recourse long-term debt6	951		606		1,061		701
Other long-term liabilities3,4,6,9	1,892		2,306		1,473		1,658
Future income taxes1,2,3,6,8	2,696		2,574		2,447		2,370
	24,656		30,904		21,997		27,770
Redeemable noncontrolling interests5	-		640		-		364
Shareholders’ equity
Share capital
Preference shares	1,056		1,056		125		125
Common shares	3,969		3,969		3,683		3,683
Contributed surplus	106		-		59		-
Retained earnings1,2,3,5,8,9,12	4,991		4,172		4,734		3,977
Additional paid-in capital4	-		244		-		131
Accumulated other comprehensive loss3,12	(1,094	)	(1,536	)	(882	)	(1,026	)
Reciprocal shareholding	(187	)	(187	)	(154	)	(154	)
Total Enbridge Inc. shareholders’ equity	8,841		7,718		7,565		6,736
Noncontrolling interests4,5	846		3,140		658		2,424
	9,687		10,858		8,223		9,160
	34,343		42,402		30,220		37,294

1 Gain on Acquisition

At December 31, 2010 under Canadian GAAP, the original equity interest in a step acquisition continued to be carried at book value subsequent to the acquisition date of the additional interest. Under U.S. GAAP, the original equity interest and noncontrolling interest in a step acquisition were re-measured to fair value on the date control was obtained. Under Canadian GAAP, the original equity interest and noncontrolling interest were not re-measured to fair value. At December 31, 2011, this recognition difference between Canadian GAAP and U.S. GAAP no longer exists.

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.

2 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, 2011, lower of cost or market adjustments resulted in a $11 million (2010 - $32 million) decrease to inventory, a $4 million increase (2010 - $6 million decrease) to the future income tax liability and a $13 million increase (2010 - $4 million increase; 2009 - $24 million decrease) to earnings.

3 Pension Accounting

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 OCI 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 a decrease in the net pension asset of $704 million (2010 - $337 million) for the underfunded status of the plans, a decrease in regulatory liabilities of $304 million (2010 - $138 million), a decrease in future tax liability of $114 million (2010 - $58 million) and a decrease in AOCI of $286 million (2010 - $141 million) at December 31, 2011.

Under Canadian GAAP, an unrecognized net transitional asset was recognized as part of the net pension asset on the adoption of CICA Handbook Section 3461, Employee Future Benefits. There is no corresponding asset under U.S. GAAP. At December 31, 2011, this adjustment resulted in a $2 million (2010 - $3 million) increase to the net pension asset with an offset to retained earnings, and a $1 million decrease to earnings (2010 - $1 million; 2009 - $1 million).

Under Canadian GAAP, a regulatory asset is recorded in relation to recoverable costs associated with OPEB plans. There is no corresponding regulatory asset under U.S. GAAP. At December 31, 2011, this adjustment resulted in a $88 million (2010 - $85 million) decrease to regulatory assets with a corresponding decrease to retained earnings, and a $6 million decrease to earnings (2010 - $6 million; 2009 - $6 million).

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

	*2011*	2010	2009
(millions of Canadian dollars)
Prior service cost	-	1	-
Net loss	10	7	5
	10	8	5

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

	*2011*	2010	2009
(millions of Canadian dollars)
Prior service cost	3	4	1
Accumulated net loss	*283*	137	102
	*286*	141	103

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

	*2011*		2010	2009
(millions of Canadian dollars)
Unamortized prior service cost	(1	)	3	-
Net loss/(gain)	*146*		35	(10	)
	*145*		38	(10	)

The Company estimates that approximately $25 million related to pension and OPEB plans at December 31, 2011 will be reclassified into earnings in the next twelve months, as follows:

	Pension Benefits	OPEB	Total
(millions of Canadian dollars)
Prior service costs	-	1	1
Loss	22	2	24
	22	3	25

4 Consolidation of a Limited Partnership

Under U.S. GAAP the Company is deemed to have control of EEP and therefore consolidates its 23.0 % interest in the partnership, resulting in an increase to assets of $8,920 million (2010 - $7,972 million), an increase in liabilities of $6,398 million (2010 - $6,098 million) and an increase in noncontrolling interests of $2,519 million (2010 - $1,871 million) at December 31, 2011. During the year ended December 31, 2011, dilution gains of $88 million, net of tax of $53 million (2010 - $52 million, net of tax of $30 million) were reclassified from earnings to equity as a result of the consolidation of EEP.

5 Redeemable Noncontrolling Interests

Under Canadian GAAP, a subsidiary’s redeemable units classified as equity are eliminated on consolidation when held by the parent, or presented by the parent in the Consolidated Statements of Financial Position as noncontrolling interest in equity. Under U.S. GAAP, noncontrolling interest in a redeemable equity security is classified outside of permanent equity. Further, under U.S. GAAP, noncontrolling interest in a redeemable equity security is required to be presented at its redemption value with changes in value recognized in retained earnings. At December 31, 2011, this difference resulted in an increase to noncontrolling interests, with a corresponding decrease to retained earnings, of $411 million (2010 - $255 million).

6 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 be accounted for using the equity method. However, under an accommodation of the SEC, 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.

7 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, 2011, $92 million (2010 - $89 million) of transaction costs were reclassified.

8 Common Control Transactions

U.S. GAAP requires common control transactions to be measured at the carrying amount, with any difference between the carrying value and consideration reflected as a charge or credit to equity. At December 31, 2011, a decrease in assets of $408 million (2010 - $414 million), a decrease in liabilities of $54 million (2010 - $61 million), and a decrease in retained earnings of $354 million (2010 - $353 million), related to a historic transaction with the Fund were retroactively reflected in the U.S. GAAP Statement of Financial Position. There was a $1 million decrease to earnings (2010 - $1 million; 2009 - $1 million).

9 Accounting for Leases

The criteria for determining whether an arrangement contains a lease are consistent under both Canadian and U.S. GAAP; however, the U.S. GAAP guidance was effective prior to the Canadian GAAP guidance. As a result, one of the Company’s pipeline transportation agreements is considered a lease under U.S. GAAP, resulting in an increase in assets of $122 million (2010 - $129 million), an increase in liabilities of $114 million (2010 - $122 million), an increase in retained earnings of $8 million (2010 - $7 million) and an increase in earnings of $1 million (2010 - $1 million; 2009 - $1 million).

10 Unrecognized Tax Benefits

	*2011*		2010
(millions of Canadian dollars)
Unrecognized tax benefits at beginning of year	17		22
Gross increases for tax positions of current year	3		2
Gross increases for tax positions of prior years	-		-
Gross decreases for tax positions of prior years	(1	)	(2	)
Reduction for lapse of statute of limitations	(1	)	(2	)
Changes in translation of foreign currency	-		-
Decreases relating to settlements with taxing authority	-		(3	)
Unrecognized tax benefits at end of year	18		17

The unrecognized tax benefits at December 31, 2011, 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 12 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, 2011 includes a $1 million expense (2010 - $2 million recovery; 2009 - $1 million expense) of interest and penalties. As at December 31, 2011, interest and penalties of $9 million (2010 - $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 2006. Generally, all United States federal income tax returns and state and local income tax returns are closed through 2007.

11 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, 2011 were approximately $524 million (2010 - $491 million; 2009 - $406 million).

12 Unrealized Foreign Exchange Loss

Under Canadian GAAP, an unrealized foreign exchange loss in AOCI was recognized in earnings during the year ended December 31, 2011 due to a dividend paid by a subsidiary. Under U.S. GAAP, this foreign exchange loss should remain in AOCI until the subsidiary is sold. At December 31, 2011, this difference resulted in an increase to earnings of $155 million with a corresponding decrease in OCI. This difference did not result in an adjustment at December 31, 2010 or December 31, 2009.

FUTURE ACCOUNTING STANDARDS UNDER U.S. GAAP

The following standards will be effective for the Company beginning on January 1, 2012. Management does not expect the adoption of any of these standards to significantly impact the consolidated financial statements.

Fair Value Measurement

In May 2011, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) 2011-04, which revises the existing guidance on fair value measurement under U.S. GAAP as part of the FASB’s joint project with the International Accounting Standards Board. Under the revised standard, the Company will be required to provide additional disclosures about fair value measurements, including information about the unobservable inputs and assumptions used in Level 3 fair value measurements, a description of the valuation methodologies used in Level 3 fair value measurements, and the level in the fair value hierarchy of items that are not measured at fair value but whose fair value disclosure is required. The adoption of this pronouncement is not anticipated to have a material impact on the Company’s financial statements. This accounting update is effective for the first reporting period beginning after December 15, 2011.

Statement of Comprehensive Income

In June 2011, the FASB issued ASU 2011-05, which updates the existing guidance on comprehensive income under U.S. GAAP, requiring presentation of net income and OCI either in one continuous statement, referred to as the Statement of Comprehensive Income, or in two separate but consecutive statements of net income and OCI. The adoption of this pronouncement does not affect the Company’s presentation of comprehensive income, and will not have an impact on the Company’s financial statements. This accounting update is effective for the first reporting period beginning after December 15, 2011.

Goodwill Impairment

In September 2011, the FASB issued ASU 2011-08, which is intended to reduce the overall costs and complexity of goodwill impairment testing. The standard allows an entity to first assess qualitative factors to determine whether it is necessary to perform the current two-step goodwill impairment test. An entity will not be required to calculate the fair value of a reporting unit unless the entity determines, based on a qualitative assessment, that it is more likely than not that its fair value is less than its carrying amount. The standard does not change the current two-step test and applies to all entities that have goodwill reported in their financial statements. The adoption of this pronouncement is not anticipated to have a material impact on the Company’s financial statements. This accounting update is effective for annual and interim goodwill impairment tests performed for fiscal years beginning after December 15, 2011.

Balance Sheet Offsetting

In December 2011, the FASB issued ASU 2011-11, which provides enhanced disclosures on the effect or potential effect of netting arrangements on an entity’s financial position. The adoption of the pronouncement affects financial statement disclosures only and is not anticipated to have a material impact on the Company’s financial statements. This accounting update is effective for annual and interim beginning on or after January 1, 2013.

(millions of Canadian dollars)

Average EaR during the year

High EaR during the year

Low EaR during the year

Closing EaR at year end