Exhibit 99.6

ENBRIDGE INC.

CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2012

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 accounting principles generally accepted in the United States of America 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 at December 31, 2012, 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, 2012.

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”
Al Monaco	J. Richard Bird
President & Chief Executive Officer	Executive Vice President &
	Chief Financial Officer
February 14, 2013

1

Independent Auditor’s Report

To the Shareholders of Enbridge Inc.

We have completed an integrated audit of Enbridge Inc.’s 2012 consolidated financial statements and its internal control over financial reporting as at December 31, 2012 and audits of its 2011 and 2010 consolidated financial statements. 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, 2012 and December 31, 2011 and the consolidated statements of earnings, comprehensive income, changes in equity and cash flows for each of the three years in the period ended December 31, 2012, 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 accounting principles generally accepted in the United States of America 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 the audit to obtain reasonable assurance about whether the consolidated financial statements are free from material misstatement. Canadian generally accepted auditing standards also 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, 2012 and December 31, 2011 and results of its operations and its cash flows for each of the three years in the period ended December 31, 2012 in accordance with accounting principles generally accepted in the United States of America.

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.

2

Report on internal control over financial reporting

We have also audited Enbridge Inc.’s internal control over financial reporting as at December 31, 2012, based on criteria established in Internal Control - Integrated Framework, issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).

Management’s responsibility for internal control over financial reporting

Management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying management’s report on internal control over financial reporting.

Auditor’s responsibility

Our responsibility is to express an opinion on the company’s internal control over financial reporting based on our audit. We conducted our audit of internal control over financial reporting in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects.

An audit of internal control over financial reporting includes obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control, based on the assessed risk, and performing such other procedures as we consider necessary in the circumstances.

We believe that our audit provides a reasonable basis for our audit opinion on the company’s internal control over financial reporting.

Definition of internal control over financial reporting

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with 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, 2012, based on criteria established in Internal Control - Integrated Framework issued by COSO.

“signed” PricewaterhouseCoopers LLP

Chartered Accountants

Calgary, Alberta, Canada

February 14, 2013

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.

3

CONSOLIDATED STATEMENTS OF EARNINGS

Year ended December 31,	2012	2011	2010
(millions of Canadian dollars, except per share amounts)
Revenues
Commodity sales	19,101	20,611	15,863
Gas distribution sales	1,910	1,906	1,814
Transportation and other services	4,295	4,536	3,843
	25,306	27,053	21,520
Expenses
Commodity costs	18,566	19,864	15,276
Gas distribution costs	1,220	1,281	1,249
Operating and administrative	2,890	2,281	2,032
Depreciation and amortization	1,206	1,112	1,017
Environmental costs, net of recoveries (Note 28)	(88)	(116)	619
	23,794	24,422	20,193
	1,512	2,631	1,327
Income from equity investments (Note 11)	160	210	228
Other income (Note 25)	240	117	318
Interest expense (Note 16)	(841)	(928)	(865)
	1,071	2,030	1,008
Income taxes (Note 23)	(128)	(526)	(227)
Earnings before extraordinary loss	943	1,504	781
Extraordinary loss, net of tax (Note 5)	-	(262)	-
Earnings	943	1,242	781
(Earnings)/loss attributable to noncontrolling interests and redeemable noncontrolling interests	(228)	(409)	170
Earnings attributable to Enbridge Inc.	715	833	951
Preference share dividends	(105)	(13)	(7)
Earnings attributable to Enbridge Inc. common shareholders	610	820	944
Earnings attributable to Enbridge Inc. common shareholders
Earnings before extraordinary loss	610	1,082	944
Extraordinary loss, net of tax (Note 5)	-	(262)	-
	610	820	944
Earnings per common share attributable to Enbridge Inc. common shareholders (Note 19)
Earnings before extraordinary loss	0.79	1.44	1.27
Extraordinary loss, net of tax	-	(0.35)	-
	0.79	1.09	1.27
Diluted earnings per common share attributable to Enbridge Inc. common shareholders (Note 19)
Earnings before extraordinary loss	0.78	1.42	1.26
Extraordinary loss, net of tax	-	(0.34)	-
	0.78	1.08	1.26

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

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CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

Year ended December 31,	2012	2011	2010
(millions of Canadian dollars)
Earnings	943	1,242	781
Other comprehensive income/(loss), net of tax
Change in unrealized loss on cash flow hedges	(176)	(582)	(156)
Change in unrealized gain/(loss) on net investment hedges	13	(19)	51
Other comprehensive income/(loss) from equity investees	2	(17)	4
Reclassification to earnings of realized cash flow hedges	7	14	(15)
Reclassification to earnings of unrealized cash flow hedges (Note 22)	20	12	(3)
Reclassification to earnings of pension plans and other postretirement benefits amortization amounts	18	21	16
Actuarial loss on pension plans and other postretirement benefits	(56)	(165)	(54)
Change in foreign currency translation adjustment	(159)	151	(376)
Other comprehensive loss	(331)	(585)	(533)
Comprehensive income	612	657	248
Comprehensive (income)/loss attributable to noncontrolling interests and redeemable noncontrolling interests	(164)	(329)	331
Comprehensive income attributable to Enbridge Inc.	448	328	579
Preference share dividends	(105)	(13)	(7)
Comprehensive income attributable to Enbridge Inc. common shareholders	343	315	572

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

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CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY

Year ended December 31,	2012	2011	2010
(millions of Canadian dollars, except per share amounts)
Preference shares (Note 19)
Balance at beginning of year	1,056	125	125
Preference shares issued	2,651	931	-
Balance at end of year	3,707	1,056	125
Common shares (Note 19)
Balance at beginning of year	3,969	3,683	3,379
Common shares issued	388	-	-
Dividend reinvestment and share purchase plan	297	229	224
Shares issued on exercise of stock options	78	57	80
Balance at end of year	4,732	3,969	3,683
Additional paid-in capital
Balance at beginning of year	242	131	90
Stock-based compensation	26	18	13
Options exercised	(17)	(7)	(8)
Issuance of treasury stock (Note 11)	236	-	-
Dilution gains and other	35	100	36
Balance at end of year	522	242	131
Retained earnings
Balance at beginning of year	3,926	3,993	3,828
Earnings attributable to Enbridge Inc.	715	833	951
Preference share dividends	(105)	(13)	(7)
Common share dividends declared	(895)	(759)	(648)
Dividends paid to reciprocal shareholder	20	25	19
Redemption value adjustment attributable to redeemable noncontrolling interests (Note 18)	(197)	(153)	(150)
Balance at end of year	3,464	3,926	3,993
Accumulated other comprehensive loss (Note 21)
Balance at beginning of year	(1,532)	(1,027)	(654)
Other comprehensive loss attributable to Enbridge Inc. common shareholders	(267)	(505)	(373)
Balance at end of year	(1,799)	(1,532)	(1,027)
Reciprocal shareholding (Note 11)
Balance at beginning of year	(187)	(154)	(154)
Issuance of treasury stock	61	-	-
Acquisition of equity investment	-	(33)	-
Balance at end of year	(126)	(187)	(154)
Total Enbridge Inc. shareholders’ equity	10,500	7,474	6,751
Noncontrolling interests (Note 18)
Balance at beginning of year	3,141	2,424	2,740
Earnings/(loss) attributable to noncontrolling interests	241	416	(182)
Other comprehensive income/(loss) attributable to noncontrolling interests, net of tax
Change in unrealized loss on cash flow hedges	(39)	(84)	(12)
Change in foreign currency translation adjustment	(60)	66	(121)
Reclassification to earnings/(loss) of realized cash flow hedges	23	(63)	(13)
Reclassification to earnings/(loss) of unrealized cash flow hedges	13	4	(2)
	(63)	(77)	(148)
Comprehensive income/(loss) attributable to noncontrolling interests	178	339	(330)
Distributions (Note 18)	(421)	(355)	(318)
Contributions (Note 18)	382	735	358
Dilution gains	6	22	15
Acquisitions (Note 6)	(25)	(27)	(41)
Other	(3)	3	-
Balance at end of year	3,258	3,141	2,424
Total equity	13,758	10,615	9,175
Dividends paid per common share	1.13	0.98	0.85

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

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CONSOLIDATED STATEMENTS OF CASH FLOWS

Year ended December 31,	2012	2011	2010
(millions of Canadian dollars)
Operating activities
Earnings	943	1,242	781
Depreciation and amortization	1,206	1,112	1,017
Deferred income taxes (recovery)/expense (Note 23)	(40)	368	203
Changes in unrealized (gains)/loss on derivative instruments, net	665	(73)	-
Cash distributions in excess of equity earnings	474	125	102
Regulatory asset write-off (Note 5)	-	262	-
Gain on acquisition (Note 6)	-	-	(22)
Asset impairment (Note 9)	166	11	11
Allowance for equity funds used during construction	(1)	(3)	(96)
Other	110	14	9
Changes in regulatory assets and liabilities	37	28	29
Changes in environmental liabilities, net of recoveries (Note 28)	(26)	(118)	267
Changes in operating assets and liabilities (Note 26)	(660)	403	(424)
	2,874	3,371	1,877
Investing activities
Additions to property, plant and equipment	(5,468)	(3,508)	(3,053)
Long-term investments	(531)	(1,515)	(35)
Additions to intangible assets	(163)	(154)	(56)
Acquisitions, net of cash acquired (Note 6)	(340)	(33)	(850)
Affiliate loans, net	8	7	14
Proceeds on sale of investments and net assets	18	-	23
Government grant	-	145	-
Changes in restricted cash	(2)	(2)	(5)
Changes in construction payable	274	(19)	60
	(6,204)	(5,079)	(3,902)
Financing activities
Net change in bank indebtedness and short-term borrowings	412	224	(165)
Net change in commercial paper and credit facility draws	(294)	(630)	(212)
Net change in Southern Lights project financing	(13)	(62)	14
Debenture and term note issues	2,199	1,604	3,220
Debenture and term note repayments	(349)	(234)	(631)
Repayment of acquired debt	(160)	-	-
Contributions from noncontrolling interests	448	873	439
Distributions to noncontrolling interests	(421)	(355)	(318)
Contributions from redeemable noncontrolling interests	213	210	-
Distributions to redeemable noncontrolling interests	(49)	(35)	(23)
Preference shares issued	2,634	926	-
Common shares issued	465	46	66
Preference share dividends	(93)	(7)	(7)
Common share dividends	(597)	(530)	(426)
	4,395	2,030	1,957
Effect of translation of foreign denominated cash and cash equivalents	(12)	25	(12)
Increase/(decrease) in cash and cash equivalents	1,053	347	(80)
Cash and cash equivalents at beginning of year	723	376	456
Cash and cash equivalents at end of year	1,776	723	376
Supplementary cash flow information
Income taxes (received)/paid	267	(28)	115
Interest paid	988	955	871

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

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CONSOLIDATED STATEMENTS OF FINANCIAL POSITION

December 31,	2012	2011
(millions of Canadian dollars; number of shares in millions)
Assets
Current assets
Cash and cash equivalents	1,776	723
Restricted cash	19	17
Accounts receivable and other (Note 7)	4,014	4,029
Accounts receivable from affiliates	12	55
Inventory (Note 8)	779	823
	6,600	5,647
Property, plant and equipment, net (Note 9)	33,318	29,074
Long-term investments (Note 11)	3,386	3,081
Deferred amounts and other assets (Note 12)	2,622	2,500
Intangible assets, net (Note 13)	817	711
Goodwill (Note 14)	419	440
Deferred income taxes (Note 23)	10	41
	47,172	41,494
Liabilities and equity
Current liabilities
Bank indebtedness	479	102
Short-term borrowings (Note 16)	583	548
Accounts payable and other (Note 15)	5,052	4,753
Accounts payable to affiliates	-	48
Interest payable	196	185
Environmental liabilities (Note 28)	107	175
Current maturities of long-term debt (Note 16)	652	354
	7,069	6,165
Long-term debt (Note 16)	20,203	19,251
Other long-term liabilities (Note 17)	2,541	2,208
Deferred income taxes (Note 23)	2,601	2,615
	32,414	30,239
Commitments and contingencies (Note 28)
Redeemable noncontrolling interests (Note 18)	1,000	640
Equity
Share capital (Note 19)
Preference shares	3,707	1,056
Common shares (805 and 781 outstanding at December 31, 2012 and 2011, respectively)	4,732	3,969
Additional paid-in capital	522	242
Retained earnings	3,464	3,926
Accumulated other comprehensive loss (Note 21)	(1,799)	(1,532)
Reciprocal shareholding (Note 11)	(126)	(187)
Total Enbridge Inc. shareholders’ equity	10,500	7,474
Noncontrolling interests (Note 18)	3,258	3,141
	13,758	10,615
	47,172	41,494

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

8

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 business 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, Seaway Pipeline, Spearhead Pipeline, Feeder Pipelines and Other.

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 and gathering facilities and the Company’s energy services businesses, along with renewable energy projects.

Investments in natural gas pipelines include the Company’s interests in the United States portion of the Alliance System (Alliance Pipeline US), the Vector Pipeline (Vector) 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 located at the terminus of the Alliance System. The energy services businesses undertake physical commodity marketing activity and manage the Company’s volume commitments on the Alliance System, the Vector Pipeline and other pipeline systems.

SPONSORED INVESTMENTS

Sponsored Investments includes the Company’s 21.8% (2011 - 23.0%) ownership interest in Enbridge Energy Partners, L.P. (EEP), Enbridge’s 66.7% (2011 - 66.7%) investment in the United States segment of the Alberta Clipper Project through EEP and Enbridge Energy, Limited Partnership and an overall 67.7% (2011 - 69.2%) economic interest in Enbridge Income Fund (the Fund), held both directly and indirectly through Enbridge Income Fund Holdings Inc. (ENF). 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 NGL. The primary operations of the Fund include renewable power generation projects, crude oil and liquids pipeline and storage businesses in Western Canada and a 50% interest in the Canadian portion of the Alliance System (Alliance Pipeline Canada).

CORPORATE

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

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2.SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

These consolidated financial statements are prepared in accordance with accounting principles generally accepted in the United States of America (U.S. GAAP). Amounts are stated in Canadian dollars unless otherwise noted.

The Company commenced reporting using U.S. GAAP as its primary basis of accounting effective January 1, 2012, including restatement of comparative periods. As a Securities and Exchange Commission registrant, the Company is permitted to use U.S. GAAP for purposes of meeting both its Canadian and United States continuous disclosure requirements.

BASIS OF PRESENTATION AND USE OF ESTIMATES

The preparation of financial statements in conformity with U.S. 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 the 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 stock-based compensation (Note 20); fair value of financial instruments (Note 22); provisions for income taxes (Note 23); assumptions used to measure retirement and other postretirement benefit obligations (OPEB) (Note 24); commitments and contingencies (Note 28); fair value of asset retirement obligations (ARO); and estimates of losses related to environmental remediation obligations (Note 28). Actual results could differ from these estimates.

PRINCIPLES OF CONSOLIDATION

The consolidated financial statements include the accounts of Enbridge, its subsidiaries and a variable interest entity (VIE) for which the Company is the primary beneficiary. The consolidated financial statements also include the accounts of any limited partnerships where the Company represents the general partner and, based on all facts and circumstances, controls such limited partnerships.

All significant intercompany accounts and transactions are eliminated upon consolidation. Ownership interests in subsidiaries represented by other parties that do not control the entity are presented in the consolidated financial statements as activities and balances attributable to noncontrolling interests and redeemable noncontrolling interests. Investments and entities over which the Company exercises significant influence are accounted for using the equity method.

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 U.S. 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.

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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, the amount of revenue can be reliably measured and collectability is reasonably assured. 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 rate-regulated businesses, revenues are recognized in a manner that is consistent with the underlying agreements as approved by the regulators. From July 1, 2011 onward, Canadian Mainline (excluding Lines 8 and 9) earnings are governed by the Competitive Toll Settlement (CTS), under which revenues are recorded when services are performed. Effective on that date, the Company prospectively discontinued the application of rate-regulated accounting for those assets 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. Estimates are based on historical consumption patterns and heating degree days experienced. Heating degree days is a measure of coldness that is indicative of volumetric requirements for natural gas utilized for heating purposes in the Company’s distribution franchise area.

For natural gas and marketing businesses, an estimate of revenues and commodity costs for the month of December is included in the Consolidated Statements of Earnings for each year based on the best available volume and price data for the commodity delivered and received.

DERIVATIVE INSTRUMENTS AND HEDGING

Non-qualifying Derivatives

Non-qualifying derivative instruments are used primarily to economically hedge foreign exchange, interest rate and commodity price earnings exposure. Non-qualifying derivatives are measured at fair value with changes in fair value recognized in earnings in Transportation and other services revenues, Commodity costs, Operating and administrative expense, Other income and Interest expense.

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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 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 Other comprehensive income/(loss) (OCI) and is reclassified to earnings when the hedged item impacts earnings. Any hedge ineffectiveness is recorded in current period earnings.

If a derivative instrument designated as a cash flow hedge ceases to be effective or is terminated, hedge accounting is discontinued and the gain or loss at that date is deferred in OCI and recognized concurrently with the related transaction. If a hedged anticipated transaction is no longer probable, the gain or loss is recognized immediately in earnings. Subsequent gains and losses from derivative instruments for which hedge accounting has been discontinued 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 at December 31, 2012 or 2011.

Net Investment Hedges

The Company uses net investment hedges to manage the carrying values of United States dollar denominated foreign operations. The effective portion of the change in the fair value of the hedging instrument is recorded in OCI. Any ineffectiveness is recorded in current period earnings. Amounts recorded in Accumulated other comprehensive income/(loss) (AOCI) are recognized in earnings when there is a reduction of the hedged net investment resulting from a disposal of the foreign operation.

Classification of Derivatives

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

Cash inflows and outflows related to derivative instruments are classified as Operating activities on the Consolidated Statements of Cash Flows.

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 Deferred amounts and other assets. These costs are amortized using the effective interest rate method over the life of the related debt instrument.

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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. To the extent an equity investee undertakes activities necessary to commence its planned principal operations, the Company capitalizes interest costs associated with its investment during such period.

OTHER INVESTMENTS

Generally, the Company classifies equity investments in entities over which it does not exercise significant influence and that do not trade on an actively quoted market as other investments carried at cost. Financial assets in this category are initially recorded at fair value with no subsequent re-measurement. Any investments which do trade on an active market are measured at fair value through OCI. Dividends received from these financial assets are recognized in earnings when the right to receive payment is established.

NONCONTROLLING INTERESTS

Noncontrolling interests represent the outstanding ownership interests attributable to third parties in certain consolidated subsidiaries, limited partnerships and VIEs. The portion of equity in entities not owned by the Company is reflected as noncontrolling interests within the equity section of the Consolidated Statements of Financial Position and, in the case of redeemable noncontrolling interests, within the mezzanine section of the Consolidated Statements of Financial Position between long-term liabilities and equity.

The Fund’s noncontrolling interest holders have the option to redeem the Fund trust units for cash, subject to certain limitations. Redeemable noncontrolling interests are recognized at the maximum redemption value of the trust units held by third parties, which references the market price of ENF common shares. On a quarterly basis, changes in estimated redemption values are reflected as a charge or credit to retained earnings.

INCOME TAXES

The liability method of accounting for income taxes is followed. Deferred 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. Deferred 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 deferred income tax liability is recognized along with a corresponding regulatory asset. Any interest and/or penalty incurred related to tax is reflected in Income taxes.

FOREIGN CURRENCY TRANSACTIONS AND 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, referred to as the functional currency. Transactions denominated in foreign currencies are translated into the functional currency using the exchange rate prevailing at the date of transaction. Monetary assets and liabilities denominated in foreign currencies are translated to the functional currency using the rate of exchange in effect at the balance sheet date. 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.

Gains and losses arising from translation of foreign operations’ functional currencies to the Company’s Canadian dollar presentation currency are included in the cumulative translation adjustment component of AOCI and are recognized in earnings upon sale of the foreign operation. Asset and liability accounts are translated at the exchange rates in effect on the balance sheet date, while revenues and expenses are translated using monthly average exchange rates.

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CASH AND CASH EQUIVALENTS

Cash and cash equivalents include short-term investments with a term to maturity of three months or less when purchased.

RESTRICTED CASH

Cash and cash equivalents that are restricted, in accordance with specific customer agreements, as to withdrawal or usage are presented as Restricted cash on the Consolidated Statements of Financial Position.

LOANS AND RECEIVABLES

Affiliate long-term notes receivable are measured at amortized cost using the effective interest rate method, net of any impairment losses recognized. Accounts receivable and other are measured at cost.

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 comprised of natural gas in storage held in EGD and crude oil and natural gas held primarily by energy services businesses. Natural gas in storage in EGD 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 commodities inventory is recorded at the lower of cost, as determined on a weighted average basis, or market value. Upon disposition, other commodities inventory is recorded to Commodity costs in the Consolidated Statements of Earnings at the weighted average cost of inventory, including any adjustments recorded to reduce inventory to market value.

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.

For non rate-regulated assets depreciation is provided on a straight-line basis over the estimated useful lives of the assets commencing when the asset is placed in service.

DEFERRED AMOUNTS AND OTHER ASSETS

Deferred amounts and other assets primarily include: costs which regulatory authorities have permitted, or are expected to permit, to be recovered through future rates including deferred income taxes; contractual receivables under the terms of long-term delivery contracts; derivative financial instruments; and deferred financing costs. Deferred financing costs are amortized using the effective interest method over the term of the related debt.

INTANGIBLE ASSETS

Intangible assets consist primarily of acquired long-term transportation or power purchase agreements, natural gas supply opportunities and certain software costs. Natural gas supply opportunities are growth opportunities, identified upon acquisition, present in gas producing zones where certain of EEP’s gas systems are located. The Company capitalizes costs incurred during the application development stage of internal use software projects. Intangible assets are amortized on a straight-line basis over their expected lives, commencing when the asset is available for use.

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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, 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. The Company has the option to first assess qualitative factors to determine whether it is necessary to perform the two-step goodwill impairment test. If the two-step goodwill impairment test is performed, 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

ARO 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. ARO 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 ARO due to the indeterminate timing and scope of the asset retirements.

RETIREMENT AND POSTRETIREMENT 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 including discount rates. The Company determines discount rates by reference to rates of high-quality long-term corporate bonds with maturities that approximate the timing of future payments the Company anticipates making under each of the respective plans. During the year ended December 31, 2012, the Company refined the methodology by which it determines discount rates, in particular, refining the method by which it estimates spreads for bonds with longer term maturities. Pension cost is charged to earnings and includes:

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

·Amortization of the 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, changes in headcount 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 OPEB other than pensions, including group health care and life insurance benefits for eligible retirees, their spouses and qualified dependents. The cost of such benefits is accrued during the years in which employees render service.

The overfunded or underfunded status of defined benefit pension and OPEB plans is recognized as Deferred amounts and other assets or Other long-term liabilities on the Consolidated Statements of Financial Position. A plan’s funded status is measured as the difference between the fair value of plan assets and the plan’s projected benefit obligation. Any unrecognized actuarial gains and losses and prior service costs and credits that arise during the period are recognized as a component of OCI, net of tax.

Certain regulated utility operations of the Company expect to recover pension expense in future rates and therefore record a corresponding regulatory asset to the extent such recovery is deemed to be probable. For years prior to 2012 an offsetting regulatory asset related to OPEB obligations was not recorded given recovery in rates was not probable. Commencing in 2012, pursuant to a specific rate order allowing for recovery in rates of OPEB costs determined on an accrual basis, an offsetting OPEB regulatory asset was recognized. In the absence of rate regulation, regulatory balances would not be recorded and pension and OPEB costs would be charged to earnings on an accrual basis.

STOCK-BASED COMPENSATION

Incentive Stock Options (ISOs) granted are recorded using the fair value method. Under this method, compensation expense is measured at the grant date based on the fair value of the ISOs granted 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 Additional paid-in capital. Balances in Additional paid-in capital 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 of the PBSOs granted as calculated by the Bloomberg barrier option valuation model and is recognized over the vesting period with a corresponding credit to Additional paid-in capital. The options become exercisable when both performance targets and time vesting requirements have been met. Balances in Additional paid-in capital are transferred to Share capital when the options are exercised.

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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.

COMMITMENTS, CONTINGENCIES AND ENVIRONMENTAL LIABILITIES

The Company expenses or capitalizes, as appropriate, expenditures for ongoing compliance with environmental regulations that relate to past or current operations. The Company expenses costs incurred for remediation of existing environmental contamination caused by past operations that do not benefit future periods by preventing or eliminating future contamination. The Company records liabilities for environmental matters when assessments indicate that remediation efforts are probable and the costs can be reasonably estimated. Estimates of environmental liabilities are based on currently available facts, existing technology and presently enacted laws and regulations taking into consideration the likely effects of inflation and other factors. These amounts also consider prior experience in remediating contaminated sites, other companies’ clean-up experience and data released by government organizations. The Company’s estimates are subject to revision in future periods based on actual costs or new information and are included in Environmental liabilities and Other long-term liabilities in the Consolidated Statements of Financial Position at their undiscounted amounts. There is always a potential of incurring additional costs in connection with environmental liabilities due to variations in any or all of the categories described above, 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. The Company evaluates recoveries from insurance coverage separately from the liability and, when recovery is probable, the Company records and reports an asset separately from the associated liability in the Consolidated Statements of Financial Position.

Liabilities for other commitments and contingencies are recognized when, after fully analyzing available information, the Company determines it is either probable that an asset has been impaired, or that a liability has been incurred, and the amount of impairment or loss can be reasonably estimated. When a range of probable loss can be estimated, the Company recognizes the most likely amount, or if no amount is more likely than another, the minimum of the range of probable loss is accrued. The Company expenses legal costs associated with loss contingencies as such costs are incurred.

3.CHANGES IN ACCOUNTING POLICIES

FAIR VALUE MEASUREMENT

Effective January 1, 2012, the Company adopted Accounting Standards Update (ASU) 2011-04, which revised the existing guidance on the disclosure of fair value measurements. Under the revised standard, the Company is required to provide additional disclosures about fair value measurements, including a description of the valuation methodologies used and information about the unobservable inputs and assumptions used in Level 3 fair value measurements, as well as the level in the fair value hierarchy of items that are not measured at fair value but whose fair value disclosure is required. As the adoption of this update impacted disclosure only, there was no impact to the Company’s earnings or cash flows for the current or prior periods presented.

STATEMENT OF COMPREHENSIVE INCOME

Effective January 1, 2012, the Company adopted ASU 2011-05, which updates the existing guidance on comprehensive income, requiring presentation of earnings and OCI either in one continuous statement, referred to as the statement of comprehensive income, or in two separate, but consecutive, statements of earnings and OCI. The adoption of this pronouncement did not affect the Company’s presentation of comprehensive income and did not impact the Company’s consolidated financial statements.

GOODWILL IMPAIRMENT

Effective January 1, 2012, the Company adopted ASU 2011-08 which is intended to reduce the overall costs and complexity of goodwill impairment testing. The standard allows an entity the option to first assess qualitative factors to determine whether it is necessary to perform the current two-step goodwill impairment test. Under this option, an entity is not required to calculate the fair value of a reporting unit unless the entity determines, based on a qualitative assessment, it is more likely than not its fair value is less than its carrying amount. Adoption of this standard does not change the current two-step goodwill impairment test.

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FUTURE ACCOUNTING POLICY CHANGES

Balance Sheet Offsetting

ASU 2011-11 was issued in December 2011 and 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 consolidated financial statements. This accounting update is effective for annual and interim periods beginning on or after January 1, 2013.

Accumulated Other Comprehensive Income

ASU 2013-02 was issued in February 2013 and provides enhanced disclosures on amounts reclassified out of AOCI. The adoption of the pronouncement affects financial statement disclosures only and is not anticipated to have a material impact on the Company’s consolidated financial statements. This accounting update is effective for annual and interim periods beginning after December 15, 2012.

4.SEGMENTED INFORMATION

Year ended December 31, 2012	Liquids Pipelines1	Gas Distribution	Gas Pipelines, Processing and Energy Services1	Sponsored Investments1	Corporate2	Consolidated
(millions of Canadian dollars)
Revenues	2,452	2,438	13,745	6,671	-	25,306
Commodity and gas distribution costs	-	(1,220)	(14,283)	(4,283)	-	(19,786)
Operating and administrative	(943)	(528)	(289)	(1,076)	(54)	(2,890)
Depreciation and amortization	(363)	(336)	(62)	(431)	(14)	(1,206)
Environmental costs, net of recoveries	-	-	-	88	-	88
	1,146	354	(889)	969	(68)	1,512
Income/(loss) from equity investments	46	-	108	53	(47)	160
Other income/(expense)	(7)	83	30	49	85	240
Interest income/(expense)	(250)	(164)	(51)	(397)	21	(841)
Income taxes recovery/(expense)	(205)	(66)	325	(169)	(13)	(128)
Earnings/(loss)	730	207	(477)	505	(22)	943
Earnings attributable to noncontrolling interests and redeemable noncontrolling interests	(4)	-	(1)	(223)	-	(228)
Preference share dividends	-	-	-	-	(105)	(105)
Earnings/(loss) attributable to Enbridge Inc. common shareholders	726	207	(478)	282	(127)	610
Additions to property, plant and equipment3	2,092	438	837	1,993	109	5,469
Total assets	15,252	7,416	5,119	15,780	3,605	47,172

Year ended December 31, 2011	Liquids Pipelines1	Gas Distribution	Gas Pipelines, Processing and Energy Services1	Sponsored Investments1	Corporate2	Consolidated
(millions of Canadian dollars)
Revenues	1,942	2,516	13,599	8,996	-	27,053
Commodity and gas distribution costs	-	(1,282)	(13,051)	(6,812)	-	(21,145)
Operating and administrative	(752)	(508)	(138)	(847)	(36)	(2,281)
Depreciation and amortization	(322)	(320)	(75)	(383)	(12)	(1,112)
Environmental costs, net of recoveries	-	-	-	116	-	116
	868	406	335	1,070	(48)	2,631
Income/(loss) from equity investments	5	-	153	57	(5)	210
Other income/(expense)	31	(12)	40	68	(10)	117
Interest expense	(256)	(166)	(56)	(350)	(100)	(928)
Income taxes recovery/(expense)	(140)	(54)	(166)	(171)	5	(526)
Earnings/(loss) before extraordinary loss	508	174	306	674	(158)	1,504
Extraordinary loss, net of tax	-	(262)	-	-	-	(262)
Earnings/(loss)	508	(88)	306	674	(158)	1,242
Earnings attributable to noncontrolling interests and redeemable noncontrolling interests	(3)	-	(1)	(405)	-	(409)
Preference share dividends	-	-	-	-	(13)	(13)
Earnings/(loss) attributable to Enbridge Inc. common shareholders	505	(88)	305	269	(171)	820
Additions to property, plant and equipment3	958	483	850	1,187	33	3,511
Total assets	12,348	7,189	4,468	13,492	3,997	41,494

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Year ended December 31, 2010	Liquids Pipelines1	Gas Distribution	Gas Pipelines, Processing and Energy Services1	Sponsored Investments1	Corporate2	Consolidated
(millions of Canadian dollars)
Revenues	1,627	2,484	9,604	7,805	-	21,520
Commodity and gas distribution costs	-	(1,249)	(9,386)	(5,890)	-	(16,525)
Operating and administrative	(579)	(508)	(105)	(807)	(33)	(2,032)
Depreciation and amortization	(303)	(310)	(55)	(339)	(10)	(1,017)
Environmental costs	-	-	-	(619)	-	(619)
	745	417	58	150	(43)	1,327
Income from equity investments	9	-	151	59	9	228
Other income/(expense)	139	(17)	28	36	132	318
Interest expense	(224)	(179)	(51)	(280)	(131)	(865)
Income taxes recovery/(expense)	(136)	(66)	(61)	(44)	80	(227)
Earnings/(loss)	533	155	125	(79)	47	781
(Earnings)/loss attributable to noncontrolling interests and redeemable noncontrolling interests	(2)	(5)	-	177	-	170
Preference share dividends	-	-	-	-	(7)	(7)
Earnings attributable to Enbridge Inc. common shareholders	531	150	125	98	40	944
Additions to property, plant and equipment3	764	387	1,114	884	-	3,149

1In December 2012 and October 2011, certain crude oil storage and renewable energy assets were transferred to the Fund within the Sponsored Investments segment. Earnings from the assets prior to the date of transfer of $33 million (2011 - $71 million; 2010 - $42 million) have not been reclassified among segments for presentation purposes.

2Included within the Corporate segment was Interest income of $336 million (2011 - $239 million; 2010 - $188 million) charged to other operating segments.

3Includes allowance for equity funds used during construction.

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

GEOGRAPHIC INFORMATION

Revenues1 

Year ended December 31,	2012	2011	2010
(millions of Canadian dollars)
Canada	12,171	12,097	9,385
United States	13,135	14,956	12,135
	25,306	27,053	21,520

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

Property, Plant and Equipment

December 31,	2012	2011
(millions of Canadian dollars)
Canada	19,293	16,690
United States	14,025	12,384
	33,318	29,074

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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. 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 and is subject to regulation by the NEB. Canadian Mainline tolls (excluding Lines 8 and 9) are currently governed by the CTS and do not attract rate-regulated accounting with the exception of flow-through income taxes covered by a specific rate order.

Prior to July 1, 2011, the effective date of the CTS, the Incentive Tolling Settlement (ITS) defined the methodology for calculation of tolls on the core component of Canadian Mainline and was recorded in accordance with rate-regulated accounting guidance. 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.

Upon transition to the CTS on July 1, 2011 and the discontinuance of rate-regulated accounting at that time, a regulatory asset of approximately $470 million continued to be recognized as a NEB rate order governing flow-through income tax treatment permits future recovery.

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, which expire in 2025, 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 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. For the years ended December 31, 2012, 2011 and 2010, EGD’s annual rates were set based on a revenue per customer cap incentive regulation methodology which adjusted revenues, and consequently rates, annually and relied on an annual process to forecast volume and customer additions. EGD’s after-tax rate of return on common equity embedded in rates was 8.4% for the years ended December 31, 2012, 2011 and 2010 based on a 36% deemed common equity component of capital for regulatory purposes for each of those years.

In November 2012, EGD received a rate order from the OEB permitting recovery of OPEB costs in the amount of $89 million ($63 million after-tax). The amount will be collected in rates over a 20-year period commencing in 2013. The gain is presented within Other income on the Consolidated Statements of Earnings. The rate order further provides for future OPEB costs, determined on an accrual basis, to be recovered in rates.

Enbridge Gas New Brunswick

Enbridge Gas New Brunswick (EGNB) is regulated by the EUB. As at December 31, 2011, EGNB discontinued rate-regulated accounting due to amendments in the rate setting methodology enacted by the Government of New Brunswick, and consequently wrote-off a deferred regulatory asset of $180 million and a regulatory asset with respect to capitalized operating costs of $103 million, net of an income tax recovery of $21 million. The write-off of $262 million, net of tax, was presented as an extraordinary loss on the Consolidated Statements of Earnings for the year ended December 31, 2011.

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FINANCIAL STATEMENT EFFECTS

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

December 31,	2012		2011
(millions of Canadian dollars)
Regulatory assets/(liabilities)
Liquids Pipelines
Deferred income taxes1	605		527
Deferred transportation revenues2	155		84
Gas Distribution
Deferred income taxes3	201		170
Future removal and site restorationreserves4	(882	)	(836	)
Pension plans and OPEB5	212		108
Sponsored Investments
Deferred income taxes3	73		83

1	The asset represents the regulatory offset to deferred income tax liabilities that are expected to be recovered under flow-through income tax treatment. The recovery period depends on future temporary differences.
2	Deferred transportation revenues are related to the cumulative difference between U.S. GAAP depreciation expense for Southern Lights and the negotiated depreciation rates included in the regulated transportation tolls. The Company expects to recover this difference after 2020 when depreciation rates in the transportation agreements are expected to exceed U.S. GAAP depreciation rates.
3	The asset represents the regulatory offset to deferred income tax liabilities to the extent that deferred 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.
4	The future removal and site restoration reserves balance results from amounts collected from customers by certain businesses, with the approval of the regulator, to fund future costs for removal and site restoration relating to property, plant and equipment. These costs are collected as part of depreciation charged on property, plant and equipment. The balance represents the amount that has been collected from customers, net of actual costs expended on removal and site restoration. The settlement of this balance will occur as future removal and site restoration costs are incurred.
5	The pension plans and OPEB balances represent the regulatory offset to pension plan and OPEB obligations to the extent the amounts are expected to be collected from customers in future rates. An OPEB balance of $89 million is expected to be collected on a straight-line basis over a 20-year period commencing in 2013, whereas the settlement period for the pension regulatory asset is not determinable.

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, certain 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, 2012, cumulative costs relating to this consulting contract of $144 million (2011 - $133 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.

21

6.ACQUISITIONS

ACQUISITIONS

Silver State North Solar Project

On March 22, 2012, Enbridge acquired a 100% interest in the Silver State North Solar Project (Silver State), a solar farm located in Nevada for cash consideration of $195 million (US$190 million). Silver State expands the Company’s renewable energy business. Revenues and earnings of $10 million and $1 million, respectively, were recognized in the year ended December 31, 2012. No revenues or earnings were recognized in any prior period as the solar project commenced operations in the second quarter of 2012. Silver State is included within the Gas Pipelines, Processing and Energy Services segment.

March 22,	2012
(millions of Canadian dollars)
Fair value of net assets acquired:
Accounts receivable and other1	54
Property, plant and equipment	141
	195
Purchase price:
Cash	195

1The Company acquired the right to apply for a $54 million (US$55 million) United States Treasury grant under a program which reimburses eligible applicants for a portion of costs related to installing specified renewable energy property. The grant, which was applied for subsequent to commercial operations, was received in October 2012.

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. Tonbridge is included within the Corporate segment.

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 revenues from Tonbridge were recognized in 2011 as the transmission line was not in service. A net loss of $1 million was recognized in earnings for the period from October 13, 2011 to December 31, 2011 related to operating and administrative expense. An unaudited proforma net loss of $38 million, including $6 million of transaction costs, would have been recognized in earnings in 2011 had the acquisition occurred on January 1, 2011.

Elk City Natural Gas Gathering and Processing System

On September 16, 2010, EEP acquired a 100% ownership interest in entities that comprise the Elk City Natural Gas Gathering and Processing System (Elk City System) for $705 million (US$686 million). The results of operations of Elk City System have been included within the Sponsored Investments segment from the date of acquisition.

22

September 16,	2010
(millions of Canadian dollars)
Fair value of net assets acquired:
Current assets	4
Property, plant and equipment	503
Intangible assets1	194
Other assets	5
Other long-term liabilities	(1	)
	705
Purchase price:
Cash	705

1Intangible assets acquired are natural gas supply opportunities, which are being amortized on a straight line basis over the weighted average estimated useful life of the underlying reserves at the time of acquisition, which approximate 25 to 30 years.

Other Acquisitions

In November 2012, Enbridge acquired certain sour gas gathering and compression facilities for a purchase price of $118 million. These facilities, which are currently in service or under construction, are located in the Peace River Arch region of northwest Alberta and are presented within the Gas Pipelines, Processing and Energy Services segment. As at December 31, 2012, the allocation of consideration paid to the assets was not complete as the Company had not yet concluded its valuation.

In May 2012, Enbridge acquired the remaining 10% interest in the Greenwich Wind Energy Project (Greenwich) through Greenwich Windfarm, LP, for cash consideration of $27 million, increasing its ownership interest to 100%. The Company’s interest in Greenwich was consolidated and presented within the Gas Pipelines, Processing and Energy Services segment until such time as it was transferred to the Fund in December 2012 (Note 18).

In October 2011, the Company acquired the remaining 10% interest in Talbot Windfarm, LP (Talbot) for $28 million, increasing its ownership interest to 100%. The Company’s interest in Talbot was consolidated and presented within the Gas Pipelines, Processing and Energy Services segment until such time as it was transferred to the Fund in October 2011.

In August 2010, the Company acquired an additional 20% interest in Olympic Pipe Line Company (Olympic), a refined products pipeline, for $12 million, increasing its ownership interest to 85%. As the Company now controlled the entity, it consolidated its interest in Olympic. Prior to August 2010, the entity was accounted for as a joint venture using the equity method.

In June 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%. The original equity interest and noncontrolling interests were re-measured to fair value on the date control was obtained and a $22 million gain was recorded in Other income (Note 25) for the year ended December 31, 2010.

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

Other acquisitions during 2010 totaled $29 million (US$27 million) and are included within the Sponsored Investments segment.

Unaudited proforma consolidated revenues and earnings that give effect to all of the Company’s other acquisitions as if they had occurred as of January 1 in the year of acquisition are not presented as the information would not be materially different from the information presented in the accompanying Consolidated Statements of Earnings.

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7.  ACCOUNTS RECEIVABLE AND OTHER

December 31,	2012		2011
(millions of Canadian dollars)
Unbilled revenues	2,289		2,210
Trade receivables	677		802
Taxes receivable	123		157
Regulatory assets	-		42
Short-term portion of derivative assets (Note 22)	383		486
Prepaid expenses and deposits	132		54
Current deferred income taxes (Note 23)	167		135
Dividends receivable	26		30
Other	266		171
Allowance for doubtful accounts	(49	)	(58	)
	4,014		4,029

8.  INVENTORY

December 31,	2012	2011
(millions of Canadian dollars)
Natural gas	448	566
Other commodities	331	257
	779	823

Commodity costs on the Consolidated Statements of Earnings included non-cash charges of $10 million (2011 - $9 million; 2010 - $9 million) for the year ended December 31, 2012 to reduce the cost basis of inventory to market value.

24

9.PROPERTY, PLANT AND EQUIPMENT

	Weighted Average
December 31,	Depreciation Rate	2012		2011
(millions of Canadian dollars)
Liquids Pipelines
Pipeline	2.6%	8,249		7,538
Pumping equipment, buildings, tanks and other1	3.1%	5,094		5,017
Land and right-of-way	2.4%	225		232
Under construction	-	1,675		1,111
		15,243		13,898
Accumulated depreciation		(3,432	)	(3,170	)
		11,811		10,728
Gas Distribution
Gas mains, services and other	4.3%	7,583		6,846
Land and right-of-way	2.5%	79		79
Under construction	-	102		137
		7,764		7,062
Accumulated depreciation		(1,912	)	(1,419	)
		5,852		5,643
Gas Pipelines, Processing and Energy Services
Pipeline	4.6%	544		568
Wind turbines, solar panels and other1	4.9%	519		781
Land and right-of-way	4.9%	6		7
Under construction	-	1,477		512
		2,546		1,868
Accumulated depreciation		(350	)	(213	)
		2,196		1,655
Sponsored Investments
Pipeline	3.0%	6,890		6,600
Pumping equipment, buildings, tanks and other1	3.3%	4,787		3,792
Wind turbines, solar panels and other1	4.0%	1,544		1,074
Land and right-of-way	2.4%	642		611
Under construction	-	2,002		913
		15,865		12,990
Accumulated depreciation		(2,770	)	(2,213	)
		13,095		10,777
Corporate
Other	9.4%	105		71
Under construction	-	296		230
		401		301
Accumulated depreciation		(37	)	(30	)
		364		271
		33,318		29,074

1In December 2012, wholly-owned subsidiaries of Enbridge sold two crude oil storage and three renewable energy assets to the Fund. As a result, at December 31, 2012, $599 million and $338 million of Property, plant and equipment were reclassified from Liquids Pipelines and Gas Pipelines, Processing and Energy Services, respectively, to Sponsored Investments. The December 31, 2011 balances of $600 million and $354 million, in Liquids Pipelines and Gas Pipelines, Processing and Energy Services, respectively, have not been reclassified for presentation purposes.

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Depreciation expense for the year ended December 31, 2012 was $1,174 million (2011 - $1,089 million; 2010 - $987 million).

GAS PIPELINES, PROCESSING AND ENERGY SERVICES

In December 2012, the Company recorded an impairment charge of $166 million ($105 million after-tax) related to certain of its Enbridge Offshore Pipelines (Offshore) assets, predominantly located within the Stingray and Garden Banks corridors in the Gulf of Mexico. The Company had been pursuing alternative uses for these assets; however, due to changing competitive conditions in the fourth quarter of 2012, the Company concluded that such alternatives were no longer likely to proceed. In addition, unique to these assets is their significant reliance on natural gas production from shallow water areas of the Gulf of Mexico which have been challenged by macro-economic factors including prevalence of onshore shale gas production, hurricane disruptions, additional regulation and the low natural gas commodity price environment.

The impairment charge was based on the amount by which the carrying values of the assets exceeded fair value, determined using expected discounted future cash flows, and is presented within Operating and administrative expense on the Consolidated Statements of Earnings. The charge is inclusive of $50 million related to abandonment costs now reasonably determined given the expected timing and scope of certain asset retirements.

10. VARIABLE INTEREST ENTITY

The Fund is an unincorporated open-ended trust established by a trust indenture under the laws of the Province of Alberta and is considered a VIE by virtue of its capital structure. The Company is the primary beneficiary of the Fund through its combined 67.7% (2011 - 69.2%; 2010 - 72%) economic interest, held indirectly through a common investment in ENF, a direct common trust unit investment in the Fund and a preferred unit investment in a wholly-owned subsidiary of the Fund. Enbridge also serves in the capacity of Manager of ENF, the Fund and its subsidiaries.

The summarized impact of the Company’s interest in the Fund on earnings, cash flows and financial position is presented below. Earnings include the results of operations of certain assets acquired by the Fund from wholly-owned subsidiaries of Enbridge from the dates of acquisition of October 2011 and December 2012 (Note 18). Earnings, cash flows and financial position information exclude the effect of intercompany transactions.

Year ended December 31,	2012		2011		2010
(millions of Canadian dollars)
Revenues	288		146		89
Operating and administrative expense	(83	)	(66	)	(52	)
Depreciation and amortization	(87	)	(47	)	(19	)
Income from equity investments	52		60		60
Interest expense and other	(68	)	(32	)	(13	)
Income taxes	(35	)	(21	)	(17	)
Earnings	67		40		48
(Earnings)/loss attributable to noncontrolling interest	13		7		(11	)
Earnings attributable to Enbridge	80		47		37
Cash flows
Cash provided by operating activities	198		140		29
Cash used in investing activities	(158	)	(98	)	(107	)
Cash provided by financing activities	1,495		381		85
Increase in cash and cash equivalents	1,535		423		7

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December 31,	2012		2011
(millions of Canadian dollars)
Current assets	224		109
Property, plant and equipment, net	2,390		1,349
Long-term investments	314		343
Deferred amounts and other assets	179		125
Current liabilities	(250	)	(90	)
Long-term debt	(1,864	)	(675	)
Other long-term liabilities	(22	)	(36	)
Deferred income taxes	(438	)	(403	)
Net assets before noncontrolling interests	533		722

11. LONG-TERM INVESTMENTS

	Ownership
December 31,	Interest	2012	2011
(millions of Canadian dollars)
Equity Investments
Joint Ventures
Liquids Pipelines
Chicap Pipeline	43.8%	27	27
Mustang Pipeline	30.0%	21	27
Seaway Pipeline	50.0%	1,385	1,186
Gas Pipelines, Processing and Energy Services
Offshore - various joint ventures	22.0%-74.3%	391	420
Vector	60.0%	142	160
Alliance Pipeline US	50.0%	282	293
Aux Sable1	42.7%-50.0%	266	217
Other	33.3%-70.0%	10	21
Sponsored Investments
Alliance Pipeline Canada	50.0%	277	296
Texas Express Pipeline	35.0%	183	11
Other	50.0%	35	47
Other Equity Investments
Corporate
Noverco Common Shares	38.9%	-	-
Other	8.9%-41.0%	55	34
Other Long-Term Investments
Corporate
Noverco Preferred Shares		246	285
Other		66	57
		3,386	3,081

1In 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.

Equity investments include the unamortized excess of the purchase price over the underlying net book value of the investees’ assets at the purchase date which is comprised of $636 million (2011 - $651 million) in Goodwill and $493 million (2011 - $450 million) in amortizable assets.

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JOINT VENTURES

Summarized combined financial information of the Company’s interest in unconsolidated equity investments of joint ventures is as follows:

Year ended December 31,	2012		2011		2010
(millions of Canadian dollars)
Revenues	921		804		771
Commodity costs	(236	)	(138	)	(92	)
Operating and administrative expense	(244	)	(200	)	(203	)
Depreciation and amortization	(159	)	(158	)	(158	)
Other expense	4		(3	)	(1	)
Interest expense	(81	)	(87	)	(96	)
Earnings before income taxes	205		218		221

December 31,	2012		2011
(millions of Canadian dollars)
Current assets	299		231
Property, plant and equipment, net	3,192		2,864
Deferred amounts and other assets	204		273
Intangible assets	74		87
Goodwill	639		651
Current liabilities	(333	)	(230	)
Long-term debt	(895	)	(926	)
Other long-term liabilities	(161	)	(245	)
Net assets	3,019		2,705

Alliance Pipeline

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

OTHER EQUITY INVESTMENTS

Noverco

At December 31, 2012, Enbridge owned an equity interest in Noverco through ownership of 38.9% (2011 - 38.9%; 2010 - 32.1%) of its common shares and an investment in preferred shares. The preferred shares are entitled to a cumulative preferred dividend based on the average yield of Government of Canada bonds maturing in 10 years plus a range of 4.3% to 4.4%.

At December 31, 2011, Noverco owned an approximate 8.9% reciprocal shareholding in the Common Shares of the Company. During the year ended December 31, 2012, Noverco sold 22.5 million Enbridge Common Shares through a secondary offering, thereby reducing the Company’s reciprocal shareholding to 6.0%. Both the Company’s equity investment in Noverco and Equity increased by $297 million, net of tax, as a result of this transaction. The Company’s share of the proceeds of approximately $317 million was received as a dividend from Noverco in May 2012.

As a result of Noverco’s 6.0% (2011 - 8.9%; 2010 - 9.0%) reciprocal shareholding in Enbridge shares, the Company has an indirect pro-rata interest of 2.1% (2011 - 3.5%) in its own shares. Both the equity investment in Noverco and shareholders’ equity have been reduced by the reciprocal shareholding of $126 million at December 31, 2012 (2011 - $187 million; 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.

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12.DEFERRED AMOUNTS AND OTHER ASSETS

December 31,	2012	2011
(millions of Canadian dollars)
Regulatory assets	1,284	1,000
Long-term portion of derivative assets (Note 22)	408	562
Affiliate long-term note receivable (Note 27)	182	194
Contractual receivables	303	288
Deferred financing costs	127	132
Other	318	324
	2,622	2,500

At December 31, 2012, deferred amounts of $265 million (2011 - $255 million) were subject to amortization and are presented net of accumulated amortization of $123 million (2011 - $106million). Amortization expense for the year ended December 31, 2012 was $25million (2011 - $20million; 2010 - $20million).

13.INTANGIBLE ASSETS

	Weighted Average		Accumulated
December 31, 2012	Amortization Rate	Cost	Amortization	Net
(millions of Canadian dollars)
Software	11.9%	622	180	442
Natural gas supply opportunities	3.8%	291	50	241
Power purchase agreements	4.7%	85	4	81
Transportation agreements	2.9%	50	13	37
Other	5.6%	20	4	16
		1,068	251	817
	Weighted Average		Accumulated
December 31, 2011	Amortization Rate	Cost	Amortization	Net
(millions of Canadian dollars)
Software	12.7%	471	155	316
Natural gas supply opportunities	3.6%	296	39	257
Power purchase agreements	4.6%	78	2	76
Transportation agreements	2.9%	53	10	43
Other	6.0%	27	8	19
		925	214	711

Total amortization expense for intangible assets was $64 million (2011 - $58 million; 2010 - $52 million) for the year ended December 31, 2012. The Company expects aggregate amortization expense for the years ending December 31, 2013 through 2017 of $67 million, $61 million, $55 million, $49 million and $44 million, respectively.

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14.GOODWILL

	Liquids Pipelines		Gas Distribution	Gas Pipelines, Processing and Energy Services		Sponsored Investments		Corporate	Consolidated
(millions of Canadian dollars)
Balance at January 1, 2011	47		-	29		355		-	431
Foreign exchange and other	1		-	1		7		-	9
Balance at December 31, 2011	48		-	30		362		-	440
Transfer of assets to the Fund	(29	)	-	-		29		-	-
Foreign exchange and other	3		-	(17	)	(7	)	-	(21	)
Balance at December 31, 2012	22		-	13		384		-	419

The Company did not recognize any goodwill impairments for the years ended December 31, 2012 and 2011.

15.ACCOUNTS PAYABLE AND OTHER

December 31,	2012	2011
(millions of Canadian dollars)
Operating accrued liabilities	2,729	2,751
Trade payables	123	176
Construction payables	568	327
Current derivative liabilities (Note 22)	1,075	880
Contractor holdbacks	86	46
Taxes payable	206	339
Security deposits	69	81
Current deferred income taxes (Note 23)	-	7
Other	196	146
	5,052	4,753

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16.DEBT

	Weighted Average
December 31,	Interest Rate	Maturity	2012		2011
(millions of Canadian dollars)
Liquids Pipelines
Debentures	8.2%	2024	200		200
Medium-term notes	4.9%	2015-2112	2,435		2,435
Southern Lights project financing1	2.7%	2014	1,413		1,449
Commercial paper and credit facility draws			25		26
Other2			12		13
Gas Distribution
Debentures	9.9%	2024	85		85
Medium-term notes	5.5%	2014-2050	2,295		2,295
Commercial paper and credit facility draws			590		556
Sponsored Investments
Junior subordinated notes3	8.1%	2067	398		406
Medium-term notes	3.8%	2013-2023	1,615		415
Senior notes4	6.2%	2013-2040	4,129		4,322
Commercial paper and credit facility draws5			1,405		540
Corporate
United States dollar term notes6	5.5%	2014-2017	1,094		1,119
Medium-term notes	4.5%	2013-2042	4,268		3,518
Commercial paper and credit facility draws7			1,488		2,785
Other8			(14	)	(11	)
Total debt			21,438		20,153
Current maturities			(652	)	(354	)
Short-term borrowings9			(583	)	(548	)
Long-term debt			20,203		19,251

12012 - $357 million and US$1,061 million (2011 - $360 million and US$1,071 million).

2Primarily capital lease obligations.

32012 - US$400 million (2011 - US$400 million).

42012 - US$4,150 million (2011 - US$4,250 million).

52012 - $250 million and US$1,160 million (2011 - $260 million and US$275 million).

62012 - US$1,100 million (2011 - US$1,100 million).

72012 - $1,140 million and US$350 million (2011 - $1,655 million and US$1,111 million).

8Primarily debt discount.

9    Weighted average interest rate - 1.1% (2011 - 1.1%).

For the years ending December 31, 2013 through 2017, debenture and term note maturities are $649 million, $1,287 million, $908 million, $998 million, $1,321 million, respectively, and $11,356 million thereafter. The Company’s debentures and term notes bear interest at fixed rates and interest obligations for the years ending December 31, 2013 through 2017 are $997 million, $976 million, $926 million, $901 million and $826 million, respectively. At December 31, 2012 and 2011, all debt is unsecured except for the Southern Lights project financing which is collateralized by the Southern Lights project assets.

INTEREST EXPENSE

Year ended December 31,	2012		2011		2010
(millions of Canadian dollars)
Debentures and term notes	986		891		835
Commercial paper and credit facility draws	33		74		66
Southern Lights project financing	38		38		37
Capitalized	(216	)	(75	)	(73	)
	841		928		865

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CREDIT FACILITIES

December 31, 2012	Maturity Dates1	Total Facilities	Draws2	Available
(millions of Canadian dollars)
Liquids Pipelines	2014	300	25	275
Gas Distribution	2014	712	590	122
Sponsored Investments	2014-2017	3,162	1,645	1,517
Corporate	2014-2017	9,108	1,520	7,588
		13,282	3,780	9,502
Southern Lights project financing3	2014	1,484	1,429	55
Total credit facilities		14,766	5,209	9,557

1Total facilities include $35 million in demand facilities with no maturity date.

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

3Total facilities inclusive of $60 million for debt service reserve letters of credit.

Credit facilities carry a weighted average standby fee of 0.2%per annum on the unused portion and draws bear interest at market rates. Certain credit facilities serve as a back-stop to the commercial paper programs and the Company has the option to extend the facilities, which are currently set to mature from 2014 to 2017.

Commercial paper and credit facility draws, net of short-term borrowings, of $2,925 million (2011 - $3,359 million) are supported by the availability of long-term committed credit facilities and therefore have been classified as long-term debt.

17.OTHER LONG-TERM LIABILITIES

December 31,	2012	2011
(millions of Canadian dollars)
Future removal and site restoration liabilities (Note 5)	882	836
Derivative liabilities (Note 22)	763	557
Pension and OPEB liabilities (Note 24)	573	515
Other	323	300
	2,541	2,208

18.NONCONTROLLING INTERESTS

December 31,	2012	2011
(millions of Canadian dollars)
EEP	2,636	2,528
Enbridge Energy Management, L.L.C. (EEM)	498	464
EGD preferred shares	100	100
Greenwich (Note 6)	-	26
Other	24	23
	3,258	3,141

Noncontrolling interests in EEP represent the 78.2% interest in EEP not owned by the Company. During the year ended December 31, 2012, EEP completed a listed share issuance, in which the Company did not participate, resulting in an increase in the noncontrolling interests from 77.0% to 78.2%. The listed share issuance during the year ended December 31, 2012 resulted in contributions of $382 million (2011 - $695 million; 2010 - $330 million) from noncontrolling interest holders. During the year ended December 31, 2012, EEP also distributed $419 million (2011 - $353 million; 2010 - $311 million) to its noncontrolling interest holders in line with EEP’s objective to make quarterly distributions in an amount equal to its available cash, as defined in its partnership agreement and as approved by EEP’s Board of Directors.

32

Noncontrolling interests in EEM represent the 83.2% of the listed shares of EEM not held by the Company. A listed share issuance during the year ended December 31, 2011 resulted in contributions of $26 million from noncontrolling interest holders.

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 preferred shares have no fixed maturity date and have floating adjustable cash dividends that are payable at 80% of the prime rate. EGD may, at is 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, 2012, no preferred shares have been redeemed.

REDEEMABLE NONCONTROLLING INTERESTS

Year ended December 31,	2012		2011		2010
(millions of Canadian dollars)
Balance at beginning of year	640		362		236
Earnings/(loss)	(13	)	(7	)	12
Other comprehensive loss
Change in unrealized loss on cash flow hedges, net of tax	(1	)	(3	)	(13	)
Comprehensive loss	(14	)	(10	)	(1	)
Distributions to unitholders	(49	)	(33	)	(23	)
Contributions from unitholders	226		168		-
Redemption value adjustment	197		153		150
Balance at end of year	1,000		640		362

Redeemable noncontrolling interests in the Fund at December 31, 2012 represented 67.7% (2011 - 64.6%; 2010 - 58.2%) of interests in the Fund’s trust units that are held by third parties.

In December 2012, the Fund acquired Greenwich, Amherstburg and Tilbury solar energy projects, Hardisty Caverns and Hardisty Contract Terminals from Enbridge and wholly-owned subsidiaries of Enbridge for proceeds of $1.2 billion. In October 2011, the Fund acquired the Ontario Wind, Sarnia Solar and Talbot Wind energy projects from a wholly-owned subsidiary of Enbridge for $1.2 billion. In both cases, ordinary trust units were issued by the Fund to partially finance these acquisitions, resulting in an increase in interests held by third parties in 2012 and 2011 and contributions from noncontrolling unitholders of $226 million and $168 million, respectively.

Distributions to noncontrolling unitholders are made on a monthly basis in line with the Fund’s objective of distributing a high proportion of its cash available for distribution, as approved by its Board of Trustees.

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19. 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

	2012		2011		2010
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	781	3,969	770	3,683	756	3,379
Common Shares issued1	10	388	-	-	-	-
Shares issued on exercise of stock options	6	78	4	57	6	80
Dividend Reinvestment and Share
Purchase Plan (DRIP)	8	297	7	229	8	224
Balance at end of year	805	4,732	781	3,969	770	3,683

1   Gross proceeds - $400 million; net issuance costs - $12 million.

PREFERENCE SHARES

	2012		2011		2010
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	20	500	20	500	-	-
Preference Shares, Series D	18	450	18	450	-	-
Preference Shares, Series F	20	500	-	-	-	-
Preference Shares, Series H	14	350	-	-	-	-
Preference Shares, Series J	8	199	-	-	-	-
Preference Shares, Series L	16	411	-	-	-	-
Preference Shares, Series N	18	450	-	-	-	-
Preference Shares, Series P	16	400	-	-	-	-
Preference Shares, Series R	16	400	-	-	-	-
Issuance costs		(78)		(19)		-
Balance at end of year		3,707		1,056		125

34

Characteristics of the preference shares are as follows:

	Initial Yield	Dividend1	Per Share Base Redemption Value2	Redemption and Conversion Option Date2,3	Right to Convert Into3,4
(Canadian dollars unless otherwise stated)
Preference Shares, Series A	5.5%	$1.375	$25	-	-
Preference Shares, Series B	4.0%	$1.000	$25	June 1, 2017	Series C
Preference Shares, Series D	4.0%	$1.000	$25	March 1, 2018	Series E
Preference Shares, Series F	4.0%	$1.000	$25	June 1, 2018	Series G
Preference Shares, Series H	4.0%	$1.000	$25	September 1, 2018	Series I
Preference Shares, Series J	4.0%	US$1.000	US$25	June 1, 2017	Series K
Preference Shares, Series L	4.0%	US$1.000	US$25	September 1, 2017	Series M
Preference Shares, Series N	4.0%	$1.000	$25	December 1, 2018	Series O
Preference Shares, Series P	4.0%	$1.000	$25	March 1, 2019	Series Q
Preference Shares, Series R5	4.0%	$1.000	$25	June 1, 2019	Series S

1The holder is entitled to receive a fixed, cumulative, quarterly preferential dividend per year, as declared by the Board of Directors of the Company.

2Preference Shares, Series A may be redeemed any time at the Company’s option. For all other series of Preference Shares, 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.

3The 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.

4Holders 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 + 2.4% (Series C), 2.4% (Series E), 2.5% (Series G), 2.1% (Series I), 2.7% (Series O), 2.5% (Series Q) or 2.5% (Series S)); or US$25 x (number of days in quarter/365) x (90-day United States Government treasury bill rate + 3.1% (Series K) or 3.2% (Series M)).

5A cash dividend of $0.2356 per share will be paid on March 1, 2013 to Series R shareholders. The regular quarterly dividend of $0.25 per share will begin in the second quarter of 2013.

EARNINGS PER COMMON SHARE

Earnings per common share is calculated by dividing earnings attributable 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 20 million (2011 - 25 million; 2010 - 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,	2012	2011	2010
(number of common shares in millions)
Weighted average shares outstanding	772	751	741
Effect of dilutive options	13	10	7
Diluted weighted average shares outstanding	785	761	748

For the year ended December 31, 2012, 5,733,000 anti-dilutive stock options (2011 - 48,000; 2010 - 92,000) with a weighted average exercise price of $38.32 (2011 - $32.02; 2010 - $27.84) 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.

35

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.

20.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 46 million have been issued to date. In 2007, a new reserve of 33 million 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 common shares being available for the 2007 ISO and PBSO plans, of which four 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.

December 31, 2012	Number	Weighted Average Exercise Price	Weighted Average Remaining Contractual Life (years)	Aggregate Intrinsic Value
(options in thousands; intrinsic value in millions of Canadian dollars)
Options outstanding at beginning of year	27,465	21.19
Options granted	5,802	38.32
Options exercised1	(5,796)	16.99
Options cancelled or expired	(103)	27.78
Options outstanding at end of year	27,368	25.69	6.7	375
Options vested at end of year2	13,703	20.33	5.2	261

1The total intrinsic value of ISOs exercised during the year ended December 31, 2012 was $130 million (2011 - $68 million; 2010 - $38 million) and cash received on exercise was $69 million (2011 - $56 million; 2010 - $50 million).

2The total fair value of options vested under the ISO Plan during the year ended December 31, 2012 was $19 million (2011 - $17 million; 2010 - $14 million).

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

Year ended December 31,	2012	2011	2010
Fair value per option (Canadian dollars)1	4.81	4.19	3.44
Valuation assumptions
Expected option term (years)2	5	6	6
Expected volatility3	19.7%	18.6%	19.7%
Expected dividend yield4	3.0%	3.4%	3.6%
Risk-free interest rate5	1.3%	2.9%	2.7%

1Options 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 and the Canadian options. The fair values per option were $4.65 (2011 - $4.01; 2010 - $3.28) for Canadian employees and US$5.58 (2011 - US$5.11; 2010 - US$4.00) for United States employees.

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

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

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

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

Compensation expense recorded for the year ended December 31, 2012 for ISOs was $23 million (2011 - $16 million; 2010 - $11 million). At December 31, 2012, unrecognized compensation cost related to non-vested stock-based compensation arrangements granted under the ISO Plan was $30 million. The cost is expected to be fully recognized over a weighted average period of approximately three years.

PERFORMANCE BASED STOCK OPTIONS

PBSOs are granted to executive officers and become exercisable when both performance targets and time vesting requirements have been met. PBSOs were granted on September 16, 2002 under the 2002 plan and on August 15, 2007, February 19, 2008 and August 15, 2012 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 were fulfilled evenly over a five-year period ending on August 15, 2012 with the options being exercisable until August 15, 2015. Time vesting requirements for the 2012 grant will be fulfilled evenly over a five-year term, ending August 15, 2017. The 2012 grant’s performance targets are based on the Company’s share price and must be met by February 15, 2019 or the options expire. If targets are met by February 15, 2019, the options are exercisable until August 15, 2020.

December 31, 2012	Number	Weighted Average Exercise Price	Weighted Average Remaining Contractual Life (years)	Aggregate Intrinsic Value
(options in thousands; intrinsic value in millions of Canadian dollars)
Options outstanding at beginning of year	4,127	18.52
Options granted	3,543	39.34
Options exercised1	(966)	18.29
Options outstanding at end of year	6,704	29.56	5.3	66
Options vested at end of year2	3,061	18.54	2.6	64

1The total intrinsic value of PBSOs exercised during the year ended December 31, 2012 was $20 million (2011 - $2 million; 2010 - $26 million) and cash received on exercise was $12 million (2011 - $3 million; 2010 - $27 million).

2The total fair value of options vested under the PBSO Plan during the year ended December 31, 2012 was $1 million (2011 - $2 million; 2010 - $2 million).

37

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

Year ended December 31,	2012
Fair value per option (Canadian dollars)	4.25
Valuation assumptions
Expected option term (years)1	8
Expected volatility2	16.1%
Expected dividend yield3	2.8%
Risk-free interest rate4	1.6%

1The expected option term is based on historical exercise practice.

2Expected volatility is determined with reference to historic daily share price volatility.

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

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

Compensation expense recorded for the year ended December 31, 2012 for PBSOs was $2 million (2011 - $2 million; 2010 - $2 million). At December 31, 2012, unrecognized compensation cost related to non-vested stock-based compensation arrangements granted under the PBSO Plan was $14 million. The cost is expected to be fully recognized over a weighted average period of approximately two years.

PERFORMANCE STOCK UNITS

The Company has a PSU Plan for executives 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 2010, 2011 and 2012 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 unusual, non-operating or non-recurring items, relative to targets established at the time of grant. To calculate the 2012 expense, multipliers of two, based upon multiplier estimates at December 31, 2012, were used for each of the 2010, 2011 and 2012 PSU grants.

December 31, 2012	Number	Weighted Average Remaining Contractual Life (years)	Aggregate Intrinsic Value
(units in thousands; intrinsic value in millions of Canadian dollars)
Units outstanding at beginning of year	937
Units granted	307
Units matured1	(627)
Dividend reinvestment	35
Units outstanding at end of year	652	1.5	56

1The total amount paid during the year ended December 31, 2012 for PSUs was $25 million (2011 - $17 million; 2010 - $14 million).

Compensation expense recorded for the year ended December 31, 2012 for PSUs was $49 million (2011 - $42 million; 2010 - $27 million). As at December 31, 2012, unrecognized compensation expense related to non-vested units granted under the PSU Plan was $25 million and is expected to be fully recognized over a weighted average period of approximately two years.

RESTRICTED STOCK UNITS

Enbridge has a RSU Plan where cash awards are paid to certain non-executive employees of the Company following a 35 month maturity period. RSU holders receive cash equal to the Company’s weighted average share price for 20 days prior to the maturity of the grant multiplied by the units outstanding on the maturity date.

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December 31, 2012	Number		Weighted Average Remaining Contractual Life (years)	Aggregate Intrinsic Value
(units in thousands; intrinsic value in millions of Canadian dollars)
Units outstanding at beginning of year	1,902
Units granted	891
Units cancelled	(114	)
Units matured1	(939	)
Dividend reinvestment	79
Units outstanding at end of year	1,819		1.5	78

1The total amount paid during the year ended December 31, 2012 for RSUs was $37 million (2011 - $39 million; 2010 - $24 million).

Compensation expense recorded for the year ended December 31, 2012 for RSUs was $32 million (2011 - $31 million; 2010 - $29 million). As at December 31, 2012, unrecognized compensation expense related to non-vested units granted under the RSU Plan was $37 million and is expected to be fully recognized over a weighted average period of approximately two years.

21.COMPONENTS OF ACCUMULATED OTHER COMPREHENSIVE LOSS

Changes in AOCI attributable to Enbridge common shareholders for the years ended December 31, 2012, 2011 and 2010, are as follows:

	Cash Flow Hedges		Net Investment Hedges		Cumulative Translation Adjustment		Equity Investees		Pension and OPEB Actuarial Gain/(Loss) Adjustment		Total
(millions of Canadian dollars)
Balance at January 1, 2010	69		429		(1,033	)	(15	)	(104	)	(654	)
Changes during the year	(136	)	61		(255	)	3		(52	)	(379	)
Tax impact	1		(10	)	-		1		14		6
	(135	)	51		(255	)	4		(38	)	(373	)
Balance at December 31, 2010	(66	)	480		(1,288	)	(11	)	(142	)	(1,027	)
Changes during the year	(563	)	(21	)	85		(20	)	(200	)	(719	)
Tax impact	153		2		-		3		56		214
	(410	)	(19	)	85		(17	)	(144	)	(505	)
Balance at December 31, 2011	(476	)	461		(1,203	)	(28	)	(286	)	(1,532	)
Changes during the year	(190	)	16		(99	)	7		(52	)	(318	)
Tax impact	45		(3	)	-		(5	)	14		51
	(145	)	13		(99	)	2		(38	)	(267	)
Balance at December 31, 2012	(621	)	474		(1,302	)	(26	)	(324	)	(1,799	)

22.DERIVATIVE FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES

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.

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.

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Foreign Exchange Risk

The Company’s earnings, cash flows, and OCI are subject to foreign exchange rate variability, primarily arising from its United States dollar denominated investments and subsidiaries, and certain revenues denominated in United States dollars and certain expenses denominated in Euros. 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 denominated in United States dollars.

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 rate movements. The Company has implemented a program to significantly mitigate the impact of short-term interest rate volatility on interest expense through 2016 with an average swap rate of 2.2%.

The Company’s earnings and cash flows are also exposed to variability in longer term interest rates ahead of anticipated fixed rate debt issuances. Forward starting interest rate swaps are used to hedge against the effect of future interest rate movements. The Company has implemented a program to significantly mitigate its exposure to long-term interest rate variability on select forecast term debt issuances through 2016. A total of $10,547 million of future fixed rate term debt issuances have been hedged at an average swap rate of 3.5%.

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.

Commodity Price Risk

The Company’s earnings and cash flows are exposed to changes in commodity prices as a result of ownership interests in certain assets and investments, as well as through the activities of its energy services subsidiaries. These commodities include natural gas, crude oil, power and NGL. 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.

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 20). The Company uses a combination of qualifying and non-qualifying derivative instruments to manage equity price risk.

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TOTAL DERIVATIVE INSTRUMENTS

The following table summarizes the balance sheet location and carrying value of the Company’s derivative instruments. The Company did not have any outstanding fair value hedges at December 31, 2012 or 2011.

December 31, 2012	Derivative Instruments used as Cash Flow Hedges		Derivative Instruments used as Net Investment Hedges		Non- Qualifying Derivative Instruments		Total Gross Derivative Instruments		Effects of Netting		Total Net Derivative Instruments1
(millions of Canadian dollars)
Accounts receivable and other (Note 7)
Foreign exchange contracts	4		16		210		230		-		230
Interest rate contracts	7		-		11		18		(2	)	16
Commodity contracts	18		-		127		145		(17	)	128
Other contracts	3		-		6		9		-		9
	32		16		354		402		(19	)	383
Deferred amounts and other assets (Note 12)
Foreign exchange contracts	11		79		225		315		-		315
Interest rate contracts	21		-		12		33		(3	)	30
Commodity contracts	5		-		60		65		(5	)	60
Other contracts	2		-		1		3		-		3
	39		79		298		416		(8	)	408
Accounts payable and other (Note 15)
Foreign exchange contracts	(5	)	-		(100	)	(105	)	-		(105	)
Interest rate contracts	(673	)	-		(2	)	(675	)	2		(673	)
Commodity contracts	(10	)	-		(304	)	(314	)	17		(297	)
	(688	)	-		(406	)	(1,094	)	19		(1,075	)
Other long-term liabilities (Note 17)
Foreign exchange contracts	(41	)	(5	)	(23	)	(69	)	-		(69	)
Interest rate contracts	(293	)	-		(15	)	(308	)	3		(305	)
Commodity contracts	(6	)	-		(388	)	(394	)	5		(389	)
	(340	)	(5	)	(426	)	(771	)	8		(763	)
Total net derivative asset/(liability)
Foreign exchange contracts	(31	)	90		312		371		-		371
Interest rate contracts	(938	)	-		6		(932	)	-		(932	)
Commodity contracts	7		-		(505	)	(498	)	-		(498	)
Other contracts	5		-		7		12		-		12
	(957	)	90		(180	)	(1,047	)	-		(1,047	)

41

December 31, 2011	Derivative Instruments used as Cash Flow Hedges		Derivative Instruments used as Net Investment Hedges		Non- Qualifying Derivative Instruments		Total Gross Derivative Instruments		Effects of Netting		Total Net Derivative Instruments1
(millions of Canadian dollars)
Accounts receivable and other (Note 7)
Foreign exchange contracts	4		15		315		334		-		334
Interest rate contracts	-		-		12		12		(4	)	8
Commodity contracts	7		-		146		153		(19	)	134
Other contracts	3		-		7		10		-		10
	14		15		480		509		(23	)	486
Deferred amounts and other assets (Note 12)
Foreign exchange contracts	15		79		203		297		-		297
Interest rate contracts	1		-		24		25		(3	)	22
Commodity contracts	12		-		241		253		(15	)	238
Other contracts	3		-		2		5		-		5
	31		79		470		580		(18	)	562
Accounts payable and other (Note 15)
Foreign exchange contracts	(4	)	-		(275	)	(279	)	-		(279	)
Interest rate contracts	(477	)	-		(8	)	(485	)	4		(481	)
Commodity contracts	(32	)	-		(107	)	(139	)	19		(120	)
	(513	)	-		(390	)	(903	)	23		(880	)
Other long-term liabilities (Note 17)
Foreign exchange contracts	(35	)	(5	)	(51	)	(91	)	-		(91	)
Interest rate contracts	(415	)	-		(20	)	(435	)	3		(432	)
Commodity contracts	(29	)	-		(20	)	(49	)	15		(34	)
	(479	)	(5	)	(91	)	(575	)	18		(557	)
Total net derivative asset/(liability)
Foreign exchange contracts	(20	)	89		192		261		-		261
Interest rate contracts	(891	)	-		8		(883	)	-		(883	)
Commodity contracts	(42	)	-		260		218		-		218
Other contracts	6		-		9		15		-		15
	(947	)	89		469		(389	)	-		(389	)

1As presented in the Consolidated Statements of Financial Position.

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

December 31, 2012	2013	2014	2015	2016	2017	Thereafter
Foreign exchange contracts – United States dollar forwards - purchase (millions of United States dollars)	558	468	25	25	413	6
Foreign exchange contracts – United States dollar forwards - sell (millions of United States dollars)	2,088	2,402	2,751	2,323	2,557	158
Foreign exchange contracts - Euro dollar forwards - purchase (millions of Euros)	6	-	-	-	-	-
Interest rate contracts - short-term borrowings (millions of Canadian dollars)	3,644	3,591	3,455	3,157	2,841	171
Interest rate contracts - long-term debt (millions of Canadian dollars)	4,590	3,055	1,760	1,142	-	-
Equity contracts (millions of Canadian dollars)	39	36	-	-	-	-
Commodity contracts - natural gas (billions of cubic feet)	55	19	10	10	11	3
Commodity contracts - crude oil (millions of barrels)	37	38	29	23	18	9
Commodity contracts - NGL (millions of barrels)	1	2	-	-	-	-
Commodity contracts - power (megawatt hours (MWH))	51	67	48	63	83	66

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December 31, 2011	2012	2013	2014	2015	2016	Thereafter
Foreign exchange contracts – United States dollar forwards - purchase (millions of United States dollars)	58	287	468	25	25	418
Foreign exchange contracts – United States dollar forwards - sell (millions of United States dollars)	2,017	1,865	2,182	2,583	2,039	180
Interest rate contracts - short-term borrowings (millions of Canadian dollars)	3,227	3,237	2,787	2,641	2,428	215
Interest rate contracts - long-term debt (millions of Canadian dollars)	2,650	2,000	1,650	750	-	-
Equity contracts (millions of Canadian dollars)	36	26	-	-	-	-
Commodity contracts - natural gas (billions of cubic feet)	20	59	1	1	1	-
Commodity contracts - crude oil (millions of barrels)	11	26	17	8	7	10
Commodity contracts - NGL (millions of barrels)	4	1	-	-	-	-
Commodity contracts - power (MWH)	40	28	40	48	63	58

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, before the effect of income taxes.

Year ended December 31,	2012		2011		2010
(millions of Canadian dollars)
Amount of unrealized gains/(loss) recognized in OCI
Cash flow hedges
Foreign exchange contracts	(12	)	(22	)	(25	)
Interest rate contracts	(46	)	(724	)	(217	)
Commodity contracts	52		72		128
Other contracts	(3	)	6		(1	)
Net investment hedges
Foreign exchange contracts	1		(26	)	19
	(8	)	(694	)	(96	)
Amount of (gains)/loss reclassified from AOCI to earnings (effective portion)
Foreign exchange contracts1	1		1		(7	)
Interest rate contracts2	(1	)	(10	)	61
Commodity contracts3	(3	)	(55	)	(116	)
Other contracts4	2		(2	)	1
	(1	)	(66	)	(61	)
Amount of (gains)/loss reclassified from AOCI to earnings (ineffective portion and amount excluded from effectiveness testing)
Interest rate contracts2	23		11		-
Commodity contracts3	(3	)	5		(3	)
	20		16		(3	)

1Reported within Other income in the Consolidated Statements of Earnings.

2Reported within Interest expense in the Consolidated Statements of Earnings.

3Reported within Commodity costs in the Consolidated Statements of Earnings.

4Reported within Operating and administrative expense in the Consolidated Statements of Earnings.

The Company estimates that $101 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 forecasted transactions, the maximum term over which the Company is hedging exposures to the variability of cash flows is 60 months at December 31, 2012.

43

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,	2012		2011		2010
(millions of Canadian dollars)
Foreign exchange contracts1	120		(179	)	33
Interest rate contracts2	(2	)	9		(3	)
Commodity contracts3	(765	)	280		(12	)
Other contracts4	(2	)	4		-
Total unrealized derivative fair value gains/(loss)	(649	)	114		18

1Reported within Transportation and other services revenues and Other income in the Consolidated Statements of Earnings.

2Reported within Interest expense in the Consolidated Statements of Earnings.

3Reported within Transportation and other services revenues, Commodity costs and Operating and administrative expense in the Consolidated Statements of Earnings.

4Reported within Operating and administrative expense in the Consolidated Statements of Earnings.

LIQUIDITY RISK

Liquidity risk is the risk that the Company will not be able to meet its financial obligations, including commitments and guarantees (Notes 28 and 29), 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 and long-term debt which includes debentures and medium-term notes. The Company maintains current shelf prospectuses with securities regulators, which enables, subject to market conditions, ready access to either the Canadian or United States public capital markets. In addition, the Company maintains sufficient liquidity through committed credit facilities (Note 16) with a diversified group of banks and institutions which, if necessary, enables the Company to fund all anticipated requirements for one year without accessing the capital markets. The Company is in compliance with all the terms and conditions of its committed credit facilities as at December 31, 2012. 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.

CREDIT RISK

Entering into derivative financial instruments may result in exposure to credit risk. Credit risk arises from the possibility that a counterparty will default on its contractual obligations. The Company enters into risk management transactions primarily with institutions that possess investment grade credit ratings. Credit risk relating to derivative counterparties is mitigated by credit exposure limits and contractual requirements, frequent assessment of counterparty credit ratings and netting arrangements.

The Company generally has a policy of entering into individual International Swaps and Derivatives Association (ISDA) agreements, or other similar derivative agreements, with the majority of its 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, 2012 and 2011, the Company had group credit concentrations and maximum credit exposure, with respect to derivative instruments, in the following counterparty segments:

44

December 31,	2012	2011
(millions of Canadian dollars)
Canadian financial institutions	306	431
United States financial institutions	129	287
European financial institutions	244	257
Other1	128	112
	807	1,087

1Other is comprised of commodity clearing house and natural gas and crude physical counterparties.

As at December 31, 2012, the Company had provided letters of credit totaling $273 million in lieu of providing cash collateral to its counterparties pursuant to the terms of the relevant ISDA agreements. The Company holds no cash collateral on asset exposures at December 31, 2012 or 2011.

Gross derivative balances have been presented without the effects of collateral posted. Derivative assets are adjusted for non-performance risk of the Company’s counterparties using their credit default swap spread rates and are reflected in the fair value. For derivative liabilities, the Company’s non-performance risk is considered in the valuation.

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 is mitigated by the large and diversified customer base and the ability to recover an estimate for doubtful accounts through the ratemaking process. The Company actively monitors the financial strength of large industrial customers and, in select cases, has obtained additional security to minimize the risk of default on receivables. Generally, the Company classifies and provides for receivables older than 30 days as past due. The maximum exposure to credit risk related to non-derivative financial assets is their carrying value.

FAIR VALUE MEASUREMENTS

The Company’s financial assets and liabilities measured at fair value on a recurring basis include derivative instruments. The Company also discloses the fair value of other financial instruments not measured at fair value. 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.

Fair Value of Derivatives

The Company categorizes its derivative instruments 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. The Company does not have any other financial instruments categorized as Level 1.

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.

45

The Company has also categorized the fair value of its held to maturity preferred share investment and long-term debt as Level 2. The fair value of the Company’s held to maturity preferred share investment is primarily based on the yield of certain Government of Canada bonds. The fair value of the Company’s long-term debt is based on quoted market prices for instruments of similar yield, credit risk and tenor.

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 primarily include long-dated derivative power contracts and NGL and natural gas contracts. The Company does not have any other financial instruments categorized in Level 3.

The Company uses the most observable inputs available to estimate the fair value of its derivatives. When possible, the Company estimates the fair value of its derivatives based on quoted market prices. If quoted market prices are not available, the Company uses estimates from third party brokers. For non-exchange traded derivatives classified in Levels 2 and 3, the Company uses standard valuation techniques to calculate the estimated fair value. These methods include discounted cash flows for forwards and swaps and Black-Scholes-Merton pricing models for options. Depending on the type of derivative and nature of the underlying risk, the Company uses observable market prices (interest, foreign exchange, commodity and share) and volatility as primary inputs to these valuation techniques. Finally, the Company considers its own credit default swap spread as well as the credit default swap spreads associated with its counterparties in its estimation of fair value.

46

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

December 31, 2012	Level 1		Level 2		Level 3		Total Gross Derivative Instruments		Effects of Netting		Total
(millions of Canadian dollars)
Financial assets
Current derivative assets
Foreign exchange contracts	-		230		-		230		-		230
Interest rate contracts	-		18		-		18		(2	)	16
Commodity contracts	3		24		118		145		(17	)	128
Other contracts	-		9		-		9		-		9
	3		281		118		402		(19	)	383
Long-term derivative assets
Foreign exchange contracts	-		315		-		315		-		315
Interest rate contracts	-		33		-		33		(3	)	30
Commodity contracts	-		56		9		65		(5	)	60
Other contracts	-		3		-		3		-		3
	-		407		9		416		(8	)	408
Financial liabilities
Current derivative liabilities
Foreign exchange contracts	-		(105	)	-		(105	)	-		(105	)
Interest rate contracts	-		(675	)	-		(675	)	2		(673	)
Commodity contracts	(9	)	(229	)	(76	)	(314	)	17		(297	)
	(9	)	(1,009	)	(76	)	(1,094	)	19		(1,075	)
Long-term derivative liabilities
Foreign exchange contracts	-		(69	)	-		(69	)	-		(69	)
Interest rate contracts	-		(308	)	-		(308	)	3		(305	)
Commodity contracts	-		(319	)	(75	)	(394	)	5		(389	)
	-		(696	)	(75	)	(771	)	8		(763	)
Total net financial asset/(liability)
Foreign exchange contracts	-		371		-		371		-		371
Interest rate contracts	-		(932	)	-		(932	)	-		(932	)
Commodity contracts	(6	)	(468	)	(24	)	(498	)	-		(498	)
Other contracts	-		12		-		12		-		12
	(6	)	(1,017	)	(24	)	(1,047	)	-		(1,047	)

47

December 31, 2011	Level 1	Level 2		Level 3		Total Gross Derivative Instruments		Effects of Netting		Total
(millions of Canadian dollars)
Financial assets
Current derivative assets
Foreign exchange contracts	-	334		-		334		-		334
Interest rate contracts	-	12		-		12		(4	)	8
Commodity contracts	1	66		86		153		(19	)	134
Other contracts	-	10		-		10		-		10
	1	422		86		509		(23	)	486
Long-term derivative assets
Foreign exchange contracts	-	297		-		297		-		297
Interest rate contracts	-	25		-		25		(3	)	22
Commodity contracts	-	208		45		253		(15	)	238
Other contracts	-	5		-		5		-		5
	-	535		45		580		(18	)	562
Financial liabilities
Current derivative liabilities
Foreign exchange contracts	-	(279	)	-		(279	)	-		(279	)
Interest rate contracts	-	(485	)	-		(485	)	4		(481	)
Commodity contracts	-	(59	)	(80	)	(139	)	19		(120	)
	-	(823	)	(80	)	(903	)	23		(880	)
Long-term derivative liabilities
Foreign exchange contracts	-	(91	)	-		(91	)	-		(91	)
Interest rate contracts	-	(435	)	-		(435	)	3		(432	)
Commodity contracts	-	(30	)	(19	)	(49	)	15		(34	)
	-	(556	)	(19	)	(575	)	18		(557	)
Total net financial asset/(liability)
Foreign exchange contracts	-	261		-		261		-		261
Interest rate contracts	-	(883	)	-		(883	)	-		(883	)
Commodity contracts	1	185		32		218		-		218
Other contracts	-	15		-		15		-		15
	1	(422	)	32		(389	)	-		(389	)

48

The significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments were as follows:

December 31, 2012	Fair Value	Unobservable Input	Minimum Price	Maximum Price	Weighted Average Price
(Fair value in millions of Canadian dollars)
Commodity contracts - financial1
Natural gas	8	Forward gas price	3.21	4.31	3.54	$/mmbtu3
Crude	(3)	Forward crude price	58.42	108.14	100.40	$/barrel
Power	(60)	Forward power price	50.25	68.25	55.98	$/MWH
Commodity contracts - physical1
Natural gas	(12)	Forward gas price	2.88	5.10	3.67	$/mmbtu3
Crude	37	Forward crude price	51.13	116.56	92.49	$/barrel
NGL	1	Forward NGL price	0.00	2.54	1.42	$/gallon
Power	(1)	Forward power price	30.09	36.35	32.74	$/MWH
Commodity options2
Natural gas	1	Option volatility	29.0%	36.0%	34.0%
NGL	5	Option volatility	33.0%	104.0%	57.0%
	(24)

1	Financial and physical forward commodity contracts are valued using a market approach valuation technique.
2	Commodity options contracts are valued using an option model valuation technique.
3	One million British thermal units (mmbtu).

If adjusted, the significant unobservable inputs disclosed in the table above would have a direct impact on the fair value of the Company’s Level 3 derivative instruments. The significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments include forward commodity prices and, for option contracts, price volatility. Changes in forward commodity prices would result in significantly different fair values for the Company’s Level 3 derivatives. Changes in price volatility would change the value of the option contracts. Generally speaking, a change in the estimate of forward commodity prices is unrelated to a change in the estimate of price volatility.

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,	2012	2011
(millions of Canadian dollars)
Level 3 net derivative asset/(liability) at beginning of year	32	(24)
Total unrealized gains/(loss)
Included in earnings1	(69)	31
Included in OCI	13	(41)
Purchases	-	8
Settlements	-	58
Level 3 net derivative asset/(liability) at end of year	(24)	32

1 Reported within Transportation and other services revenues, Commodity costs and Operating and administrative expense in the Consolidated Statements of Earnings.

The Company’s policy is to recognize transfers as of the last day of the reporting period. There were no transfers between levels as at December 31, 2012 or 2011.

Fair Value of Other Financial Instruments

The Company recognizes equity investments in other entities not categorized as held to maturity at fair value, with changes in fair value recorded in OCI, unless actively quoted prices are not available for fair value measurement in which case these investments are recorded at cost. The carrying value of all equity investments recognized at cost totaled $66 million at December 31, 2012 (2011 - $57 million).

The Company has a held to maturity preferred share investment carried at its amortized cost of $246 million at December 31, 2012 (2011 - $285 million). These preferred shares are entitled to a cumulative preferred dividend based on the average yield of Government of Canada bonds maturing in greater than 10 years plus a range of 4.3% to 4.4%. At December 31, 2012, the fair value of this preferred share investment approximates its face value of $580 million (2011 - $580 million).

49

At December 31, 2012, the Company’s long-term debt had a carrying value of $20,855 million (2011 - $19,605 million) and a fair value of $24,809 million (2011 - $22,620 million).

23. INCOME TAXES

INCOME TAX RATE RECONCILIATION

Year ended December 31,	2012	2011	2010
(millions of Canadian dollars)
Earnings before income taxes and extraordinary loss	1,071	2,030	1,008
Combined statutory income tax rate	25.8%	27.2%	28.8%
Income taxes at statutory rate	276	552	290
Increase/(decrease) resulting from:
Deferred income taxes related to regulated operations	(67)	(35)	(62)
Higher/(lower) foreign tax rates	(56)	65	(38)
Tax rates and legislated tax changes	9	1	(15)
Non-taxable items, net	(6)	(16)	(8)
Intercompany sale of investments1	56	98	-
Noncontrolling interests in Limited Partnerships	(79)	(130)	55
Other	(5)	(9)	5
Income taxes before extraordinary loss	128	526	227
Effective income tax rate	12.0%	25.9%	22.5%

1 In December 2012 and October 2011, Enbridge and certain wholly-owned subsidiaries of Enbridge sold certain assets to the Fund. As these transactions occurred between entities under common control of the Company, the intercompany gains realized as a result of these transfers have been eliminated, although current income tax expense of $56 million and $98 million remain as a charge to earnings in 2012 and 2011, respectively. The Company retains the benefit of cash taxes paid in the form of increased tax basis of its investment in the underlying entities; however, accounting recognition of such benefit is not permitted until such time as the entities are sold outside of the consolidated group.

COMPONENTS OF PRETAX EARNINGS AND INCOME TAXES

Year ended December 31,	2012	2011	2010
(millions of Canadian dollars)
Earnings before income taxes and extraordinary loss
Canada	1,041	694	759
United States	(177)	1,203	118
Other	207	133	131
	1,071	2,030	1,008
Current income taxes
Canada	130	194	(24)
United States	35	(30)	43
Other	3	(6)	5
	168	158	24
Deferred income taxes
Canada	160	30	136
United States	(200)	338	67
	(40)	368	203
Total income taxes before extraordinary loss	128	526	227

50

COMPONENTS OF DEFERRED INCOME TAXES

Deferred tax assets and liabilities are recognized for the future tax consequences of differences between carrying amounts of assets and liabilities and their respective tax bases. Major components of deferred income tax assets and liabilities are:

December 31,	2012	2011
(millions of Canadian dollars)
Deferred income tax liabilities
Property, plant and equipment	(1,325)	(1,499)
Investments	(1,479)	(973)
Regulatory liabilities	(221)	(197)
Other	(144)	(117)
Total deferred income tax liabilities	(3,169)	(2,786)
Deferred income tax assets
Financial instruments	380	37
Pension and OPEB plans	180	145
Loss carryforwards	161	174
Other	51	29
Total deferred income tax assets	772	385
Less valuation allowance	(27)	(45)
Total deferred income tax assets, net	745	340
Net deferred income tax liabilities	(2,424)	(2,446)
Presented as follows:
Assets
Accounts receivable and other (Note 7)	167	135
Deferred income taxes	10	41
Total deferred income tax assets	177	176
Liabilities
Accounts payable and other (Note 15)	-	(7)
Deferred income taxes	(2,601)	(2,615)
Total deferred income tax liabilities	(2,601)	(2,622)
Net deferred income tax liabilities	(2,424)	(2,446)

Valuation allowances have been established for certain loss and credit carryforwards that reduce deferred income tax assets to an amount that will more likely than not be realized.

At December 31, 2012, the Company recognized the benefit of unused tax loss carryforwards of $183 million (2011 - $214 million) in Canada which start to expire in 2022 and beyond.

At December 31, 2012, the Company recognized the benefit of unused tax loss carryforwards of $222 million (2011 - $187 million) in the United States which start to expire in 2022 and beyond.

The Company has not provided for deferred income taxes on $548 million (2011 - $524 million) of foreign subsidiaries’ undistributed earnings as at December 31, 2012 as such earnings are intended to be indefinitely reinvested in the operations and potential acquisitions. Upon distribution of these earnings in the form of dividends or otherwise, the Company would be subject to income taxes. It is not practicable to determine the income tax liability that might be incurred if these earnings were to be distributed.

The Company recognizes accrued interest and penalties related to unrecognized tax benefits as a component of Income taxes. Income tax expense for the year ended December 31, 2012 included $1 million (2011 - $1 million; 2010 - $2 million recovery) of interest and penalties. As at December 31, 2012, interest and penalties of $10 million (2011 - $9 million) have been accrued.

51

The Company and one or more of its subsidiaries are subject to taxation in Canada, the United States and other foreign jurisdictions. The Company is under examination by certain tax authorities for the 2007 to 2011 tax years. The material jurisdictions in which the Company is subject to potential examinations include the United States (Federal and Texas) and Canada (Federal, Alberta and Ontario).

UNRECOGNIZED TAX BENEFITS

Year ended December 31,	2012	2011
(millions of Canadian dollars)
Unrecognized tax benefits at beginning of year	18	17
Gross increases for tax positions of current year	38	3
Gross decreases for tax positions of prior years	3	(1)
Reduction for lapse of statute of limitations	(5)	(1)
Unrecognized tax benefits at end of year	54	18

The unrecognized tax benefits at December 31, 2012, if recognized, would affect the Company’s effective income tax rate. The gross increases for current year positions included $16 million in respect of filing positions based on substantively enacted tax law and $22 million in respect of a request for refund of Texas Gross Margin Tax. Although U.S. GAAP only permits recognition of tax positions based on enacted law it is widely accepted by the Canadian tax authorities to file and remit taxes based on substantively enacted tax law. It is anticipated that the law will be enacted in 2013.

24. RETIREMENT AND POSTRETIREMENT 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, 2012 was used to determine the plan assets and 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, 2011	December 31, 2012
Gas Distribution	December 31, 2009	December 31, 2012
United States Plan	December 31, 2011	December 31, 2012

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.

OTHER POSTRETIREMENT BENEFITS

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

52

BENEFIT OBLIGATIONS AND FUNDED STATUS

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		OPEB
December 31,	2012	2011	2012	2011
(millions of Canadian dollars)
Change in accrued benefit obligation
Benefit obligation at beginning of year	1,686	1,323	243	195
Service cost	84	61	8	6
Interest cost	74	73	10	11
Employees’ contributions	-	-	1	1
Actuarial loss	106	270	14	28
Benefits paid	(64)	(54)	(8)	(7)
Effect of foreign exchange rate changes	(5)	5	(2)	2
Other	(2)	8	(5)	7
Benefit obligation at end of year	1,879	1,686	261	243
Change in plan assets
Fair value of plan assets at beginning of year	1,355	1,314	54	41
Actual return on plan assets	117	16	5	1
Employer’s contributions	97	72	13	13
Employees’ contributions	-	-	1	1
Benefits paid	(64)	(54)	(8)	(7)
Effect of foreign exchange rate changes	(3)	3	(1)	1
Other	(2)	4	(2)	4
Fair value of plan assets at end of year	1,500	1,355	62	54
Underfunded status at end of year	(379)	(331)	(199)	(189)
Presented as follows:
Accounts payable and other	-	-	(5)	(5)
Other long-term liabilities (Note 17)	(379)	(331)	(194)	(184)
	(379)	(331)	(199)	(189)

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

	Pension			OPEB
Year ended December 31,	2012	2011	2010	2012	2011	2010
Discount rate	4.2%	4.5%	5.6%	4.0%	4.4%	5.6%
Average rate of salary increases	3.7%	3.5%	3.5%

53

NET BENEFIT COSTS RECOGNIZED

	Pension			OPEB
Year ended December 31,	2012	2011	2010	2012	2011	2010
(millions of Canadian dollars)
Benefits earned during the year	84	61	48	8	6	5
Interest cost on projected benefitobligations	74	73	72	10	11	11
Expected return on plan assets	(93)	(92)	(80)	(3)	(3)	(2)
Amortization of prior service costs	2	2	2	-	1	-
Amortization of actuarial loss	51	25	19	2	1	1
Net defined benefit costs on an accrual basis	118	69	61	17	16	15
Defined contribution benefit costs	4	4	5	-	-	-
Net benefit cost recognized in the
Consolidated Statements of Earnings	122	73	66	17	16	15
Net amount recognized in OCI
Net actuarial loss1	42	172	35	10	29	11
Net prior service cost/(credit)2	-	-	-	-	(1)	6
Total amount recognized in OCI	42	172	35	10	28	17
Total amount recognized in Comprehensive income	164	245	101	27	44	32

1	Unamortized actuarial losses included in AOCI, before tax, were $388 million (2011 - $346 million) relating to the pension plans and $60 million (2011 - $51 million) relating to OPEB at December 31, 2012.
2	Unamortized prior service costs included in AOCI, before tax, were $4 million (2011 - $5 million) relating to OPEB at December 31, 2012.

The Company estimates that approximately $24 million related to pension plans and $2 million related to OPEB at December 31, 2012 will be reclassified from AOCI into earnings in the next 12 months.

Regulatory adjustments are recorded in the Consolidated Statements of Earnings, the Consolidated Statements of Comprehensive Income and the Consolidated Statements of Financial Position to reflect the difference between pension expense for accounting purposes and pension expense for ratemaking purposes. Offsetting regulatory assets or liabilities are recorded to the extent pension or OPEB costs or gains are expected to be collected from or refunded to customers in future rates (Note 5).

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

	Pension			OPEB
Year ended December 31,	2012	2011	2010	2012	2011	2010
Discount rate	4.5%	5.6%	6.5%	4.4%	5.6%	6.3%
Average rate of return on pension plan assets	7.1%	7.3%	7.3%	6.0%	6.0%	6.0%
Average rate of salary increases	3.5%	3.5%	3.7%

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	8.6%	4.5%	2029
Other Medical	4.5%	4.5%	-
United States Plan	7.6%	4.5%	2030

54

A 1% increase in the assumed medical care trend rate would result in an increase of $36 million in the benefit obligation and an increase of $3 million in benefit and interest costs. A 1% decrease in the assumed medical care trend rate would result in a decrease of $29 million in the benefit obligation and a decrease of $2 million in benefit and interest costs.

PLAN ASSETS

The Company manages the investment risk of its pension funds by setting a long-term asset mix policy for each plan after consideration of: (i) the nature of pension plan liabilities; (ii) the investment horizon of the plan; (iii) the going concern and solvency funded status and cash flow requirements of the plan; (iv) the operating environment and financial situation of the Company and its ability to withstand fluctuations in pension contributions; and (v) the future economic and capital markets outlook with respect to investment returns, volatility of returns and correlation between assets. The overall expected rate of return is based on the asset allocation targets with estimates for returns on equity and debt securities based on long-term expectations.

Expected Rate of Return on Plan Assets

	Pension		OPEB
Year ended December 31,	2012	2011	2012	2011
Canadian Plans	6.9%	7.0%
United States Plan	7.3%	7.5%	6.0%	6.0%

Target Mix for Plan Assets

	Liquids Pipelines Plan	Gas Distribution 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%

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, 2012, the pension assets were invested 59.1% (2011 - 56.7%) in equity securities, 32.4% (2011 - 36.6%) in fixed income securities and 8.5% (2011 - 6.7%) in other. The OPEB assets were invested 58.1% (2011 - 55.3%) in equity securities, 35.5% (2011 - 40.3%) in fixed income securities and 6.4% (2011 - 4.4%) in other.

The following table summarizes the Company’s pension financial instruments at fair value. Non-financial instruments with a carrying value of $59 million (2011 - $77 million) have been excluded from the table below.

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	2012				2011
December 31,	Level 11	Level 22	Level 33	Total	Level 11	Level 22	Level 33	Total
(millions of Canadian dollars)
Pension
Cash and cash equivalents	44	-	-	44	14	-	-	14
Fixed income securities
Canadian government bonds	87	-	-	87	115	-	-	115
Corporate bonds and debentures	-	4	-	4	-	4	-	4
Canadian corporate bond index fund	196	-	-	196	158	-	-	158
Canadian government bond index fund	152	-	-	152	157	-	-	157
United States debt index fund	45	2	-	47	62	-	-	62
Equity
Canadian equity securities	190	-	-	190	148	-	-	148
United States equity securities	24	-	-	24	-	-	-	-
Global equity securities	9	-	-	9	-	-	-	-
Canadian equity funds	64	39	-	103	21	74	-	95
United States equity funds	60	26	-	86	170	89	-	259
Global equity funds	255	159	-	414	191	7	-	198
Private equity investment4	-	-	61	61	-	-	68	68
Real estate5	-	-	24	24	-	-	-	-
OPEB
Cash and cash equivalents	4	-	-	4	3	-	-	3
Fixed income securities
United States government and government agency bonds	22	-	-	22	22	-	-	22
Equity
United States equity funds	17	19	-	36	15	14	-	29

1	Level 1 assets include assets with quoted prices in active markets for identical assets.
2	Level 2 assets include assets with significant observable inputs.
3	Level 3 assets include assets with significant unobservable inputs.
4	The fair value of the investment in United States Limited Partnership - Global Infrastructure Fund is established through the use of valuation models.
5	The fair value of the investment in Bentall Kennedy Prime Canadian Property Fund Ltd 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:

	2012	2011
(millions of Canadian dollars)
Balance at beginning of year	68	65
Unrealized and realized gains	11	8
Purchases and settlements, net	6	(5)
Balance at end of year	85	68

Plan Contributions by the Company

	Pension		OPEB
Year ended December 31,	2012	2011	2012	2011
(millions of Canadian dollars)
Total contributions	97	72	13	13
Contributions expected to be paid in 2013	140		13

Benefits Expected to be Paid by the Company

Year ended December 31,	2013	2014	2015	2016	2017	2018-2022
(millions of Canadian dollars)
Expected future benefit payments	73	78	83	88	93	558

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25.OTHER INCOME

Year ended December 31,	2012	2011	2010
(millions of Canadian dollars)
Net foreign currency gains	71	48	132
Allowance for equity funds used during construction	1	3	96
Interest income on affiliate loans	20	17	20
Interest income	7	3	17
Noverco preferred shares dividend income	42	30	15
OPEB recovery (Note 5)	89	-	-
Gain on acquisition (Note 6)	-	-	22
Other	10	16	16
	240	117	318

26.CHANGES IN OPERATING ASSETS AND LIABILITIES

Year ended December 31,	2012	2011	2010
(millions of Canadian dollars)
Accounts receivable and other	(122)	121	(878)
Accounts receivable from affiliates	43	(17)	8
Inventory	42	93	(124)
Deferred amounts and other assets	(380)	(320)	(16)
Accounts payable and other	(319)	421	642
Accounts payable to affiliates	(48)	41	(22)
Interest payable	15	7	31
Other long-term liabilities	109	57	(65)
	(660)	403	(424)

27.RELATED PARTY TRANSACTIONS

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

Vector, 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 were $6 million for the year ended December 31, 2012 (2011 - $6 million; 2010 - $7 million).

Certain wholly-owned subsidiaries within the Gas Distribution and Gas Pipelines, Processing and Energy Services segments have transportation commitments with several joint venture affiliates that are accounted for using the equity method. Total amounts charged for transportation services were $127 million, $106 million and $102 million for the years ended December 31, 2012, 2011 and 2010, respectively.

LONG-TERM NOTE RECEIVABLE FROM AFFILIATE

Amounts receivable from affiliates include a series of loans to Vector totaling $178 million (2011 - $190 million), included in Deferred amounts and other assets, which require quarterly interest payments at annual interest rates from 5% to 8%.

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28.COMMITMENTS AND CONTINGENCIES

COMMITMENTS

The Company has signed contracts for the purchase of services, pipe and other materials, as well as transportation, totaling $4,668 million which are expected to be paid within the next five years and $1,023 million in total for years thereafter.

Minimum future payments under operating leases are estimated at $329 million in aggregate. Estimated annual lease payments for the years ending December 31, 2013 through 2017 are $40 million, $41 million, $39 million, $38 million and $34 million, respectively, and $137 million thereafter. Total rental expense for operating leases, included in Operating and administrative expense, were $31 million, $28 million and $23 million for the years ended December 31, 2012, 2011 and 2010, respectively.

ENBRIDGE ENERGY PARTNERS, L.P.

Enbridge holds an approximate 21.8% combined direct and indirect ownership interest in EEP, which is consolidated with noncontrolling interests within the Sponsored Investments segment.

Environmental Liabilities

As at December 31, 2012, the Company had $107 million (2011 - $175 million) included in current liabilities and $18 million (2011 - $32 million) included in Other long-term liabilities, which have been accrued for costs incurred primarily to address remediation of contaminated sites, asbestos containing materials, management of hazardous waste material disposal, outstanding air quality measures for certain of EEP’s liquids and natural gas assets and penalties that have been or are expected to be assessed.

Lakehead System Line 14 Crude Oil Release

On July 27, 2012, a release of crude oil was detected on Line 14 of EEP’s Lakehead System near Grand Marsh, Wisconsin. The estimated volume of oil released was approximately 1,700 barrels. EEP received a Corrective Action Order (CAO) from the Pipeline and Hazardous Materials Safety Administration (PHMSA) on July 30, 2012, followed by an amended CAO on August 1, 2012. The CAOs required EEP to take certain corrective actions, some of which have already been completed and some are still ongoing, as part of an overall plan for its Lakehead System. A notable part of the CAOs was to hire an independent third party pipeline expert to review and assess EEP’s overall integrity program. An independent third party expert was contracted during the third quarter of 2012 and its work is currently ongoing.

Upon restart of Line 14 on August 7, 2012, PHMSA restricted the operating pressure to 80% of the pressure in place at the time immediately prior to the incident. The pressure restrictions will remain in place until such time EEP can demonstrate that the root cause of the incident has been remediated.

EEP has revised the disclosed estimate for repair and remediation related costs associated with this crude oil release as at December 31, 2012 to approximately US$10 million ($1 million after-tax attributable to Enbridge), inclusive of approximately US$2 million of lost revenue, and excluding any fines and penalties. Despite the efforts EEP has made to ensure the reasonableness of its estimate, changes to the estimated amounts associated with this release are possible as more reliable information becomes available. EEP will be pursuing claims under Enbridge’s comprehensive insurance policy, although it does not expect any recoveries to be significant.

Lakehead System Lines 6A and 6B Crude Oil Releases

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 released crude oil affected approximately 61 kilometres (38 miles) of shoreline along the Talmadge Creek and Kalamazoo River waterways, including residential areas, businesses, farmland and marshland between Marshall and downstream of Battle Creek, Michigan. In response to the release, a unified command structure was established under the jurisdiction of the Environmental Protection Agency (EPA), the Michigan Department of Natural Resources and Environment and other federal, state and local agencies.

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During the second quarter of 2012, local authorities allowed the Kalamazoo River and Morrow Lake, which were affected by the Line 6B crude oil release, to be re-opened for recreational use. EEP continues to perform necessary remediation, restoration and monitoring of the areas affected by the Line 6B crude oil release. EEP expects to make payments for additional costs associated with submerged oil and sheen monitoring and recovery operations, including reassessment, remediation and restoration of the area, air and groundwater monitoring, scientific studies and hydrodynamic modeling, along with legal, professional and regulatory costs through future periods. All of the initiatives EEP is undertaking in the monitoring and restoration phase are intended to restore the crude oil release area to the satisfaction of the appropriate regulatory authorities.

On July 2, 2012, EEP received a Notice of Probable Violation (NOPV) from the PHMSA related to the July 26, 2010 Line 6B crude oil release, which resulted in payment of a US$3.7 million civil penalty in the third quarter of 2012. EEP included the amount of the penalty in its total estimated cost for the Line 6B crude oil release. In addition, on July 10, 2012 the National Transportation Safety Board presented the results of its investigation into the Line 6B crude oil release and subsequently publicly posted its final report on July 26, 2012.

As at December 31, 2012, EEP revised the total incident cost accrual to US$820 million ($137 million after-tax attributable to Enbridge), primarily due to an estimate of extended oversight by regulators and additional legal costs associated with various lawsuits, which is an increase of US$55 million ($8 million after-tax attributable to Enbridge) from its estimate at December 31, 2011. This total estimate is before insurance recoveries and excludes additional fines and penalties, which may be imposed by federal, state and local government agencies, other than the PHMSA civil penalty described above. On October 3, 2012, EEP received a letter from the EPA regarding a Proposed Order for potential incremental containment and active recovery of submerged oil. EEP is in discussions with the EPA regarding the agency’s intent with respect to certain elements of the Proposed Order and the appropriate scope of these activities. The nature and scope of any additional remediation activities that regulators may require is currently uncertain. Studies and additional technical evaluation by EEP, the EPA and other regulatory agencies may need to be completed before a final determination of any additional remediation activities can be determined. EEP has accrued the estimated costs it deemed likely to be incurred. However, when a final determination of the appropriate nature and scope of any additional remediation is made, it could result in significant cost being accrued.

Expected losses associated with the Line 6B crude oil release included those costs that were considered probable and that could be reasonably estimated at December 31, 2012. Despite the efforts EEP has made to ensure the reasonableness of its estimates, 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 and expenditures associated with litigation and settlement of claims.

Line 6A Crude Oil Release

A release of crude oil from Line 6A of EEP’s Lakehead System was reported in an industrial area of Romeoville, Illinois on September 9, 2010. EEP estimates that 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. Some of the released crude oil went onto a roadway, into a storm sewer, a waste water treatment facility and then into a nearby retention pond. All but a small amount of the crude oil was recovered. EEP completed excavation and replacement of the pipeline segment and returned it to service on September 17, 2010. The cause of the crude oil release remains subject to investigation by 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 near Romeoville, Illinois in September 2010 for any additional requirements; however, the cleanup, remediation and restoration of the areas affected by the release have been completed.

In connection with this crude oil release, the cost estimate as at December 31, 2012 remains at approximately US$48 million ($7 million after-tax attributable to Enbridge), before insurance recoveries and excluding fines and penalties. EEP has the potential of incurring additional costs in connection with this crude oil release, including fines and penalties as well as expenditures associated with litigation. 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.

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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. In the unlikely event multiple insurable incidents occur which exceed coverage limits within the same insurance period, the total insurance coverage will be allocated among the Enbridge entities on an equitable basis based on an insurance allocation agreement EEP has entered into with Enbridge and one of Enbridge’s subsidiaries. The insurance 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 remediation spending through December 31, 2012, Enbridge and its affiliates have exceeded the limits of their coverage under this insurance policy. Additionally, fines and penalties would not be covered under the existing insurance policy.

For the years ended December 31, 2012 and 2011, EEP recognized US$170 million ($24 million after-tax attributable to Enbridge) and US$335 million ($50 million after-tax attributable to Enbridge), respectively, of insurance recoveries as reductions to Environmental costs in the Consolidated Statements of Earnings. As at December 31, 2012, EEP had recorded total insurance recoveries of US$505 million ($74 million after-tax attributable to Enbridge) for the Line 6B crude oil release and expects to recover the balance of the aggregate liability insurance coverage of US$145 million from its insurers in future periods. EEP will record receivables for additional amounts received through insurance recoveries during the period it deems recovery to be probable.

Effective May 1, 2012, Enbridge renewed its comprehensive insurance program, through April 30, 2013, with a current liability aggregate limit of US$660 million, including sudden and accidental pollution liability.

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 30 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. Based on the current status of these cases, EEP does not expect the outcome of these actions to be material. As noted above, on July 2, 2012, PHMSA announced a NOPV related to the Line 6B crude oil release, including a civil penalty of US$3.7 million that EEP paid in the third quarter of 2012. 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 the Illinois 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.

29.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.

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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. Examples include indemnifying counterparties pursuant to sale agreements for assets or businesses in matters such as breaches of representations; warranties or covenants; loss or damages to property; environmental liabilities; changes in laws; valuation differences; litigation; and contingent liabilities. 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 Company may also indemnify for breaches of representations; warranties or covenants; changes in laws; intellectual property rights infringement; and litigations.

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. 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.

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