Exhibit 99.6

ENBRIDGE INC.

CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2016

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 and all related financial information contained in the annual report, including Management’s Discussion and Analysis. The consolidated financial statements have been prepared in accordance with generally accepted accounting principles in the United States of America (U.S. GAAP) and necessarily include amounts that reflect management’s judgment and best estimates.

The Board of Directors (the Board) and its committees are responsible for all aspects related to governance of the Company. The Audit, Finance & Risk Committee (the AF&RC) of the Board, composed of directors who are unrelated and independent, has a specific responsibility to oversee management’s efforts to fulfill 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. The internal auditors and independent auditors have unrestricted access to the AF&RC.

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 U.S. GAAP 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, 2016, based on the framework established in Internal Control – Integrated Framework (2013) 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, 2016.

PricewaterhouseCoopers LLP, independent auditors appointed by the shareholders of the Company, have conducted an audit of the consolidated financial statements of the Company and its internal control over financial reporting in accordance with Canadian generally accepted auditing standards and the standards of the Public Company Accounting Oversight Board (United States) and have issued an unqualified audit report, which is accompanying the consolidated financial statements.

/s/ Al Monaco	/s/ John K. Whelen
Al Monaco	John K. Whelen
President & Chief Executive Officer	Executive Vice President &
	Chief Financial Officer

February 17, 2017

1

Independent Auditor’s Report

To the Shareholders of Enbridge Inc.

We have completed integrated audits of Enbridge Inc.’s 2016, 2015 and 2014 consolidated financial statements and its internal control over financial reporting as at December 31, 2016. 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, 2016 and December 31, 2015 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, 2016, 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 2016 and December 31, 2015 and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2016 in accordance with accounting principles generally accepted in the United States of America.

Report on internal control over financial reporting

We have also audited Enbridge Inc.’s internal control over financial reporting as at December 31, 2016, based on criteria established in Internal Control - Integrated Framework (2013), 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, 2016, based on criteria established in Internal Control - Integrated Framework (2013) issued by COSO.

/s/ “PricewaterhouseCoopers LLP”

Chartered Professional Accountants
Calgary, Alberta

February 17, 2017

CONSOLIDATED STATEMENTS OF EARNINGS

Year ended December 31,	2016		2015		2014
(millions of Canadian dollars, except per share amounts)
Revenues
Commodity sales	22,816		23,842		28,281
Gas distribution sales	2,486		3,096		2,853
Transportation and other services	9,258		6,856		6,507
	34,560		33,794		37,641
Expenses
Commodity costs	22,409		22,949		27,504
Gas distribution costs	1,596		2,292		1,979
Operating and administrative	4,360		4,152		3,281
Depreciation and amortization	2,240		2,024		1,577
Environmental costs, net of recoveries	(2	)	(21	)	100
Impairment of property, plant and equipment (Note 9)	1,376		96		-
Goodwill impairment (Note 15)	-		440		-
	31,979		31,932		34,441
	2,581		1,862		3,200
Income from equity investments (Note 11)	428		475		368
Other income/(expense) (Note 27)	1,032		(702	)	(266	)
Interest expense (Note 17)	(1,590	)	(1,624	)	(1,129	)
	2,451		11		2,173
Income taxes (Note 25)	(142	)	(170	)	(611	)
Earnings/(loss) from continuing operations	2,309		(159	)	1,562
Discontinued Operations
Earnings from discontinued operations before income taxes	-		-		73
Income taxes from discontinued operations	-		-		(27	)
Earnings from discontinued operations	-		-		46
Earnings/(loss)	2,309		(159	)	1,608
(Earnings)/loss attributable to noncontrolling interests and redeemable noncontrolling interests	(240	)	410		(203	)
Earnings attributable to Enbridge Inc.	2,069		251		1,405
Preference share dividends	(293	)	(288	)	(251	)
Earnings/(loss) attributable to Enbridge Inc. common shareholders	1,776		(37	)	1,154
Earnings/(loss) attributable to Enbridge Inc. common shareholders
Earnings/(loss) from continuing operations	1,776		(37	)	1,108
Earnings from discontinued operations, net of tax	-		-		46
	1,776		(37	)	1,154
Earnings/(loss) per common share attributable to Enbridge Inc. common shareholders
Continuing operations	1.95		(0.04	)	1.34
Discontinued operations	-		-		0.05
	1.95		(0.04	)	1.39
Diluted earnings/(loss) per common share attributable to Enbridge Inc. common shareholders
Continuing operations	1.93		(0.04	)	1.32
Discontinued operations	-		-		0.05
	1.93		(0.04	)	1.37

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

2

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

Year ended December 31,	2016		2015		2014
(millions of Canadian dollars)
Earnings/(loss)	2,309		(159	)	1,608
Other comprehensive income/(loss), net of tax
Change in unrealized gains/(loss) on cash flow hedges	(138	)	198		(833	)
Change in unrealized gains/(loss) on net investment hedges	166		(903	)	(270	)
Other comprehensive income from equity investees	-		30		10
Reclassification to earnings of realized cash flow hedges	98		(191	)	76
Reclassification to earnings of unrealized cash flow hedges	18		(121	)	158
Reclassification to earnings of pension plans and other postretirement benefits (OPEB) amortization amounts	17		21		15
Actuarial gains/(loss) on pension plans and other postretirement benefits	(34	)	51		(191	)
Change in foreign currency translation adjustment	(712	)	3,347		1,238
Reclassification to earnings of derecognized cash flow hedges	-		(247	)	-
Other comprehensive income/(loss), net of tax	(585	)	2,185		203
Comprehensive income	1,724		2,026		1,811
Comprehensive (income)/loss attributable to noncontrolling interests and redeemable noncontrolling interests	(229	)	292		(242	)
Comprehensive income attributable to Enbridge Inc.	1,495		2,318		1,569
Preference share dividends	(293	)	(288	)	(251	)
Comprehensive income attributable to Enbridge Inc. common shareholders	1,202		2,030		1,318

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

3

CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY

Year ended December 31,	2016		2015		2014
(millions of Canadian dollars, except per share amounts)
Preference shares (Note 21)
Balance at beginning of year	6,515		6,515		5,141
Preference shares issued	740		-		1,374
Balance at end of year	7,255		6,515		6,515
Common shares (Note 21)
Balance at beginning of year	7,391		6,669		5,744
Common shares issued	2,241		-		446
Dividend reinvestment and share purchase plan	795		646		428
Shares issued on exercise of stock options	65		76		51
Balance at end of year	10,492		7,391		6,669
Additional paid-in capital
Balance at beginning of year	3,301		2,549		746
Stock-based compensation	41		35		31
Options exercised	(24	)	(19	)	(14	)
Issuance of treasury stock	-		-		22
Drop down of interest to Enbridge Energy Partners, L.P. (Note 20)	-		218		-
Enbridge Energy Partners, L.P. equity restructuring (Note 20)	-		-		1,601
Transfer of interest to Enbridge Income Fund	-		-		176
Drop down of interest to Midcoast Energy Partners, L.P.	-		-		(18	)
Dilution gain on Enbridge Income Fund issuance of trust units (Note 20)	4		355		-
Dilution gain on Enbridge Income Fund equity investment (Note 20)	73		132		-
Dilution gain/(loss) on Enbridge Income Fund indirect equity investment (Note 20)	4		(5	)	-
Dilution gains and other	-		36		5
Balance at end of year	3,399		3,301		2,549
Retained earnings/(deficit)
Balance at beginning of year	142		1,571		2,550
Earnings attributable to Enbridge Inc.	2,069		251		1,405
Preference share dividends	(293	)	(288	)	(251	)
Common share dividends declared	(1,945	)	(1,596	)	(1,177	)
Dividends paid to reciprocal shareholder	26		22		17
Reversal of cumulative redemption value adjustment attributable to Enbridge Commercial Trust (Note 20)	-		541		-
Redemption value adjustment attributable to redeemable noncontrolling interests (Note 20)	(686	)	(359	)	(973	)
Adjustment relating to equity method investment	(29	)	-		-
Balance at end of year	(716	)	142		1,571
Accumulated other comprehensive income/(loss) (Note 23)
Balance at beginning of year	1,632		(435	)	(599	)
Other comprehensive income/(loss) attributable to Enbridge Inc. common shareholders	(574	)	2,067		164
Balance at end of year	1,058		1,632		(435	)
Reciprocal shareholding
Balance at beginning of year	(83	)	(83	)	(86	)
Issuance of treasury stock	(19	)	-		3
Balance at end of year	(102	)	(83	)	(83	)
Total Enbridge Inc. shareholders’ equity	21,386		18,898		16,786
Noncontrolling interests
Balance at beginning of year	1,300		2,015		4,014
Earnings/(loss) attributable to noncontrolling interests	(28	)	(407	)	214
Other comprehensive income/(loss) attributable to noncontrolling interests, net of tax
Change in unrealized gains/(loss) on cash flow hedges	4		161		(192	)
Change in foreign currency translation adjustment	(44	)	273		146
Reclassification to earnings of realized cash flow hedges	33		(236	)	18
Reclassification to earnings of unrealized cash flow hedges	7		(83	)	77
	-		115		49
Comprehensive income/(loss) attributable to noncontrolling interests	(28	)	(292	)	263
Distributions	(720	)	(680	)	(535	)
Contributions	28		615		212
Drop down of interest to Enbridge Energy Partners, L.P. (Note 20)	-		(304	)	-
Enbridge Energy Partners, L.P. equity restructuring	-		-		(2,330	)
Drop down of interest to Midcoast Energy Partners, L.P.	-		-		39
Dilution loss	-		(53	)	-
Acqusitions - Magic Valley and Wildcat wind farms (Note 6)	-		-		351
Other	(3	)	(1	)	1
Balance at end of year	577		1,300		2,015
Total equity	21,963		20,198		18,801
Dividends paid per common share	2.12		1.86		1.40

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

4

CONSOLIDATED STATEMENTS OF CASH FLOWS

Year ended December 31,	2016		2015		2014
(millions of Canadian dollars)
Operating activities
Earnings/(loss)	2,309		(159	)	1,608
Earnings from discontinued operations	-		-		(46	)
Depreciation and amortization	2,240		2,024		1,577
Deferred income taxes (Note 25)	43		7		587
Changes in unrealized (gains)/loss on derivative instruments, net	(509	)	2,373		(96	)
Cash distributions in excess of equity earnings	171		244		196
Impairment	1,620		536		18
Gains on dispositions (Note 27)	(848	)	(94	)	(38	)
Hedge ineffectiveness	61		(20	)	210
Inventory revaluation allowance	245		410		174
Unrealized (gains)/loss on intercompany loan	43		(131	)	(16	)
Other	198		69		131
Changes in environmental liabilities, net of recoveries	(4	)	(43	)	(78	)
Changes in operating assets and liabilities (Note 29)	(358	)	(645	)	(1,699	)
Cash provided by continuing operations	5,211		4,571		2,528
Cash provided by discontinued operations	-		-		19
	5,211		4,571		2,547
Investing activities
Additions to property, plant and equipment	(5,128	)	(7,273	)	(10,524	)
Joint venture financing	(1	)	-		-
Long-term investments	(467	)	(622	)	(854	)
Restricted long-term investments	(46	)	(49	)	-
Additions to intangible assets	(127	)	(101	)	(208	)
Acquisitions	(644	)	(106	)	(394	)
Proceeds from dispositions	1,379		146		85
Affiliate loans, net	(118	)	59		13
Changes in restricted cash	(40	)	13		(13	)
Cash used in continuing operations	(5,192	)	(7,933	)	(11,895	)
Cash provided by discontinued operations	-		-		4
	(5,192	)	(7,933	)	(11,891	)
Financing activities
Net change in bank indebtedness and short-term borrowings	14		(588	)	734
Net change in commercial paper and credit facility draws	(2,297	)	1,507		4,212
Southern Lights project financing repayments	-		-		(1,519	)
Debenture and term note issues - Southern Lights	-		-		1,507
Debenture and term note issues	4,080		3,767		5,414
Debenture and term note repayments	(1,946	)	(1,023	)	(1,348	)
Contributions from noncontrolling interests	28		615		212
Distributions to noncontrolling interests	(720	)	(680	)	(535	)
Contributions from redeemable noncontrolling interests	591		670		323
Distributions to redeemable noncontrolling interests	(202	)	(114	)	(79	)
Preference shares issued	737		-		1,365
Common shares issued	2,260		57		478
Preference share dividends	(293	)	(288	)	(245	)
Common share dividends	(1,150	)	(950	)	(749	)
	1,102		2,973		9,770
Effect of translation of foreign denominated cash and cash equivalents	(19	)	143		59
Increase/(decrease) in cash and cash equivalents	1,102		(246	)	485
Cash and cash equivalents at beginning of year - continuing operations	1,015		1,261		756
Cash and cash equivalents at beginning of year - discontinued operations	-		-		20
Cash and cash equivalents at end of year	2,117		1,015		1,261
Cash and cash equivalents - discontinued operations	-		-		-
Cash and cash equivalents - continuing operations	2,117		1,015		1,261
Supplementary cash flow information
Income taxes paid	194		80		9
Interest paid	1,820		1,835		1,435

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

5

CONSOLIDATED STATEMENTS OF FINANCIAL POSITION

December 31,	2016		2015
(millions of Canadian dollars; number of shares in millions)
Assets
Current assets
Cash and cash equivalents	2,117		1,015
Restricted cash	68		34
Accounts receivable and other (Note 7)	4,978		5,430
Accounts receivable from affiliates	14		7
Inventory (Note 8)	1,233		1,111
	8,410		7,597
Property, plant and equipment, net (Note 9)	64,284		64,434
Long-term investments (Note 11)	6,836		7,008
Restricted long-term investments (Note 12)	90		49
Deferred amounts and other assets (Note 13)	3,113		3,160
Intangible assets, net (Note 14)	1,573		1,348
Goodwill (Note 15)	78		80
Deferred income taxes (Note 25)	1,170		839
Assets held for sale (Note 6)	278		-
	85,832		84,515
Liabilities and equity
Current liabilities
Bank indebtedness	623		361
Short-term borrowings (Note 17)	351		599
Accounts payable and other (Note 16)	7,295		7,351
Accounts payable to affiliates	122		48
Interest payable	333		324
Environmental liabilities	142		141
Current maturities of long-term debt (Note 17)	4,100		1,990
	12,966		10,814
Long-term debt (Note 17)	36,494		39,391
Other long-term liabilities (Note 18)	4,981		6,056
Deferred income taxes (Note 25)	6,036		5,915
	60,477		62,176
Commitments and contingencies (Note 31)
Redeemable noncontrolling interests (Note 20)	3,392		2,141
Equity
Share capital (Note 21)
Preference shares	7,255		6,515
Common shares (943 and 868 outstanding at December 31, 2016 and December 31, 2015, respectively)	10,492		7,391
Additional paid-in capital	3,399		3,301
Retained earnings/(deficit)	(716	)	142
Accumulated other comprehensive income (Note 23)	1,058		1,632
Reciprocal shareholding	(102	)	(83	)
Total Enbridge Inc. shareholders’ equity	21,386		18,898
Noncontrolling interests (Note 20)	577		1,300
	21,963		20,198
	85,832		84,515

Variable Interest Entities (Note 10)

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

Approved by the Board of Directors:

/s/ David A. Arledge	/s/ J. Herb England
David A. Arledge	J. Herb England
Chair	Director

6

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 and Processing; Green Power and Transmission; and Energy Services. These reporting 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 Canadian Mainline, Lakehead Pipeline System (Lakehead System), Regional Oil Sands System, Mid-Continent and Gulf Coast, Southern Lights Pipeline, Bakken System and 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 and the Company’s investment in Noverco Inc. (Noverco).

GAS PIPELINES AND PROCESSING

Gas Pipelines and Processing consists of investments in natural gas pipelines and gathering and processing facilities. Investments in natural gas pipelines include the Company’s interests in Alliance Pipeline, 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 extraction and fractionation business located near the terminus of the Alliance Pipeline, Canadian Midstream assets located in northeast British Columbia and northwest Alberta and United States Midstream assets located primarily in Texas and Oklahoma.

GREEN POWER AND TRANSMISSION

Green Power and Transmission consists of the Company’s investments in renewable energy assets and transmission facilities. Renewable energy assets consist of wind, solar, geothermal and waste heat recovery facilities and are located in Canada primarily in the provinces of Alberta, Ontario and Quebec and in the United States primarily in Colorado, Texas, Indiana and West Virginia. The Company also has assets under development located in Europe.

ENERGY SERVICES

The Energy Services businesses in Canada and the United States undertake physical commodity marketing activity and logistical services, oversee refinery supply services and manage the Company’s volume commitments on various pipeline systems.

ELIMINATIONS AND OTHER

In addition to the segments noted above, Eliminations and Other includes operating and administrative costs and foreign exchange costs which are not allocated to business segments. Also included in Eliminations and Other are new business development activities, general corporate investments and elimination of transactions between segments required to present financial performance and financial position on a consolidated basis.

7

CANADIAN RESTRUCTURING PLAN

Effective September 1, 2015, under an agreement with Enbridge Income Fund (the Fund) and Enbridge Income Fund Holdings Inc. (ENF), Enbridge transferred its Canadian Liquids Pipelines business, held by Enbridge Pipelines Inc. (EPI) and Enbridge Pipelines (Athabasca) Inc. (EPAI), and certain Canadian renewable energy assets to the Fund Group (comprising the Fund, Enbridge Commercial Trust (ECT), Enbridge Income Partners LP (EIPLP) and the subsidiaries of EIPLP) for consideration valued at $30.4 billion plus incentive distribution and performance rights (the Canadian Restructuring Plan). The consideration that Enbridge received included $18.7 billion of units in the Fund Group, comprised of $3 billion of Fund units and $15.7 billion of equity units of EIPLP, in which the Fund has an interest. The Fund Group also assumed debt of EPI and EPAI of approximately $11.7 billion.

2.   SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

These consolidated financial statements are prepared in accordance with generally accepted accounting principles in the United States of America (U.S. GAAP). Amounts are stated in Canadian dollars unless otherwise noted. 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 14); measurement of goodwill (Note 15); fair value of asset retirement obligations (ARO) (Note 19); valuation of stock-based compensation (Note 22); fair value of financial instruments (Note 24); provisions for income taxes (Note 25); assumptions used to measure retirement and other postretirement benefit obligations (OPEB) (Note 26); commitments and contingencies (Note 31); and estimates of losses related to environmental remediation obligations (Note 31). Actual results could differ from these estimates.

PRINCIPLES OF CONSOLIDATION

The consolidated financial statements include the accounts of Enbridge, its subsidiaries and variable interest entities (VIEs) for which the Company is the primary beneficiary. A VIE is a legal entity that does not have sufficient equity at risk to finance its activities without additional subordinated financial support or is structured such that equity investors lack the ability to make significant decisions relating to the entity’s operations through voting rights or do not substantively participate in the gains and losses of the entity. Upon inception of a contractual agreement, the Company performs an assessment to determine whether the arrangement contains a variable interest in a legal entity and whether that legal entity is a VIE. The primary beneficiary has both the power to direct the activities of the VIE that most significantly impact the entity’s economic performance and the obligation to absorb losses or the right to receive benefits from the VIE entity that could potentially be significant to the VIE. Where the Company concludes it is the primary beneficiary of a VIE, the Company will consolidate the accounts of that entity. The Company assesses all variable interests in the entity and uses its judgment when determining if the Company is the primary beneficiary. Other qualitative factors that are considered include decision-making responsibilities, the VIE capital structure, risk and rewards sharing, contractual agreements with the VIE, voting rights and level of involvement of other parties. A reconsideration of whether an entity is a VIE occurs when there are certain changes in the facts and circumstances related to a VIE. The Company assesses the primary beneficiary determination for a VIE on an ongoing basis, as there are changes in the facts and circumstances related to a VIE. 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, unless the limited partner has substantive participating rights or substantive kick-out rights. For certain investments where the Company retains an undivided interest in assets and liabilities, Enbridge records its proportionate share of assets, liabilities, revenues and expenses.

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.

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As a result of the Canadian Restructuring Plan, ECT, a subsidiary of the Company, determines its equity investment earnings from EIPLP using the Hypothetical Liquidation at Book Value (HLBV) method. ECT applies the HLBV method to its equity method investments where cash distributions, including both preference and residual distributions, are not based on the investor’s ownership percentages. Under the HLBV method, a calculation is prepared at each balance sheet date to determine the amount that ECT would receive if EIPLP were to liquidate all of its assets, as valued in accordance with U.S. GAAP, and distribute that cash to the investors. The difference between the calculated liquidation distribution amounts at the beginning and the end of the reporting period, after adjusting for capital contributions and distributions, is ECT’s share of the earnings or losses from the equity investment for the period.

While ECT and EIPLP are both consolidated in these financial statements, the use of the HLBV method by ECT impacts the earnings attributable to redeemable noncontrolling interests reported on Enbridge’s Consolidated Statements of Earnings. The Company continues to recognize Redeemable noncontrolling interests on the Consolidated Statements of Financial Position at the maximum redemption value of the trust units held by third parties, which references the market price of ENF common shares.

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 Alberta Energy Regulator, 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 or expected to be paid to cover future abandonment costs in relation to the NEB’s Land Matters Consultation Initiative (LMCI). 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. A regulatory asset or liability is recognized in respect of deferred income taxes when it is expected the amounts will be recovered or settled through future regulator-approved rates.

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, whereas the capitalized equity component, the corresponding earnings during the construction phase and the subsequent depreciation would not be recognized.

For certain regulated operations to which U.S. GAAP guidance for phase-in plans applies, negotiated depreciation rates recovered in transportation tolls may be less than the depreciation expense calculated in accordance with U.S. GAAP in early years of long-term contracts but recovered in future periods when tolls exceed depreciation. Depreciation expense on such assets is recorded in accordance with U.S. GAAP and no deferred regulatory asset is recorded (Note 5).

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With the approval of the regulator, EGD and certain distribution operations capitalize a percentage of specified 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 that 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 revenues from liquids and gas pipeline businesses are recognized under the terms of committed delivery contracts rather than the cash tolls received.

Long-term take-or-pay contracts, under which shippers are obligated to pay fixed amounts rateably over the contract period regardless of volumes shipped, may contain make-up rights. Make-up rights are earned by shippers when minimum volume commitments are not utilized during the period but under certain circumstances can be used to offset overages in future periods, subject to expiry periods. The Company recognizes revenues associated with make-up rights at the earlier of when the make-up volume is shipped, the make-up right expires or when it is determined that the likelihood that the shipper will utilize the make-up right is remote.

Certain offshore pipeline transportation contracts require the Company to provide transportation services for the life of the underlying producing fields. Under these arrangements, shippers pay the Company a fixed monthly toll for a defined period of time which may be shorter than the estimated reserve life of the underlying producing fields, resulting in a contract period which extends past the period of cash collection. Fixed monthly toll revenues are recognized rateably over the committed volume made available to shippers throughout the contract period, regardless of when cash is received.

For rate-regulated businesses, revenues are recognized in a manner that is consistent with the underlying agreements as approved by the regulators. Since 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, revenues are 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/(expense) and Interest expense.

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Derivatives in Qualifying Hedging Relationships

The Company uses derivative financial instruments to manage its exposure to 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 its exposure to 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.

Net Investment Hedges

Gains and losses arising from translation of net investment in foreign operations from their functional currencies to the Company’s Canadian dollar presentation currency are included in cumulative translation adjustments (CTA). The Company designates foreign currency derivatives and United States dollar denominated debt as hedges of net investments in United States dollar denominated foreign operations. As a result, the effective portion of the change in the fair value of the foreign currency derivatives as well as the translation of United States dollar denominated debt are reflected in OCI and any ineffectiveness is reflected in current period earnings. Amounts recognized previously in Accumulated other comprehensive income/(loss) (AOCI) are reclassified to earnings when there is a reduction of the hedged net investment resulting from disposal of a 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 may be 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 from the issuance of debt and accounts for these costs as a deduction from Long-term debt on the Statements of Financial Position.

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These costs are amortized using the effective interest rate method over the term of the related debt instrument and are recorded in Interest expense.

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.

RESTRICTED LONG-TERM INVESTMENTS

Long-term investments that are restricted as to withdrawal or usage, for the purposes of the NEB’s LMCI, are presented as Restricted long-term investments on the Consolidated Statements of Financial Position.

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 classified as available for sale investments measured at fair value through OCI. Dividends received from investments carried at cost are recognized in earnings when the right to receive payment is established.

NONCONTROLLING INTERESTS

Noncontrolling interests represent ownership interests attributable to third parties in certain consolidated subsidiaries, limited partnerships and VIEs. The portion of equity not owned by the Company in such entities 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.

The use of the HLBV method by ECT impacts the earnings attributable to redeemable noncontrolling interests reported on Enbridge’s Consolidated Statements of 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 with a corresponding regulatory asset to the extent taxes can be recovered through rates. 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 in which they arise.

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Gains and losses arising from translation of foreign operations’ functional currencies to the Company’s Canadian dollar presentation currency are included in the CTA 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.

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 as to withdrawal or usage, in accordance with specific commercial arrangements, 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

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 in the Energy Services segment. 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 on 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.

Two primary methods of depreciation are utilized. For distinct assets, depreciation is generally provided on a straight-line basis over the estimated useful lives of the assets commencing when the asset is placed in service. For largely homogeneous groups of assets with comparable useful lives, the pool method of accounting for property, plant and equipment is followed whereby similar assets are grouped and depreciated as a pool. When group assets are retired or otherwise disposed of, gains and losses are not reflected in earnings but are booked as an adjustment to accumulated depreciation.

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; and derivative financial instruments.

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INTANGIBLE ASSETS

Intangible assets consist primarily of certain software costs, natural gas supply opportunities, acquired power purchase agreements, customer relationships and land leases and permits. The Company capitalizes costs incurred during the application development stage of internal use software projects. Natural gas supply opportunities are growth opportunities, identified upon acquisition, present in gas producing zones where certain United States gas systems are located. Customer relationships represent the underlying relationship from long term agreements with customers that are capitalized upon acquisition. Intangible assets are amortized on a straight-line basis over their expected lives, commencing when the asset is available for use.

GOODWILL

Goodwill represents the excess of the purchase price over the fair value of net identifiable assets on acquisition of a business. The carrying value of goodwill, which is not amortized, is assessed for impairment annually, 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, the first step involves determining the fair value of the Company’s reporting units inclusive of goodwill and comparing those values to the carrying value of each reporting unit. If 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 reporting unit’s assets and liabilities.

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 Accounts payable and other or 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.

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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 estimates of future salary levels, other cost escalations, retirement ages of employees and other actuarial factors including discount rates and mortality.

Effective January 1, 2016, the Company refined the method to estimate current service cost and interest cost for pension and other postretirement benefits. Previously, these were estimated utilizing a single weighted-average discount rate derived from the yield curve used to measure the defined benefit obligation at the beginning of the year. Under the refined method, different discount rates are derived from the same yield curve, reflecting the different timing of benefit payments for past service (the defined benefit obligation) and future service (the current service cost). Differentiating in this way represents a refinement in the basis of estimation applied in prior periods. This change does not affect the measurement of the total defined benefit obligation recorded on the Consolidated Statements of Financial Position as at December 31, 2016 or any other period. The refinement compared to the previous method resulted in a decrease in the current service cost and interest components with an equal offset to actuarial gains (losses) with no net impact on the total benefit obligation. The refinement did not have a material impact on the Consolidated Statements of Earnings for the year ended December 31, 2016. This change was accounted for prospectively as a change in accounting estimate.

In 2014, new mortality tables were issued by the Society of Actuaries in the United States which were further revised in 2015. These tables, along with the Canadian Institute of Actuaries tables that were revised in 2013, were used by the Company for measurement of its benefit obligations of its United States pension plan (the United States Plan) and the Canadian pension plans (the Canadian Plans), respectively. 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. Pension cost is charged to earnings and includes:

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

·Interest cost of pension plan obligations;

·Expected return on pension plan assets;

·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; 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.

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The overfunded or underfunded status of defined benefit pension and OPEB plans is recognized as Deferred amounts and other assets, Accounts payable and other 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 record regulatory adjustments to reflect the difference between pension expense and OPEB costs for accounting purposes and the pension expense and OPEB costs for ratemaking purposes. Offsetting regulatory assets or liabilities are recorded to the extent pension expense or OPEB costs are expected to be collected from or refunded to customers, respectively, in future rates. In the absence of rate regulation, regulatory balances would not be recorded and pension and OPEB costs would be charged to earnings and OCI on an accrual basis.

STOCK-BASED COMPENSATION

Incentive Stock Options (ISO) granted are recorded using the fair value method. Under this method, compensation expense is measured at the grant date based on the fair value of the ISO 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 stock options (PSO) 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 PSO 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.

Performance Stock Units (PSU) and Restricted Stock Units (RSU) are cash settled awards for which the related liability is remeasured each reporting period. PSU vest at the completion of a three-year term and RSU vest at the completion of a 35-month term. During the vesting term, compensation 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 to Other long-term liabilities. The value of the PSU 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.

An estimated loss for commitments and contingencies is recognized when, after fully analysing 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.

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3.   CHANGES IN ACCOUNTING POLICIES

ADOPTION OF NEW STANDARDS

Classification of Deferred Taxes on the Statements of Financial Position

Effective January 1, 2016, the Company elected to early adopt Accounting Standards Update (ASU) 2015-17 and applied the standard on a prospective basis. The amendments require that deferred tax liabilities and assets be classified as noncurrent in the Consolidated Statements of Financial Position. The adoption of the pronouncement did not have a material impact on the Company’s consolidated financial statements.

Simplifying the Accounting for Measurement-Period Adjustments in Business Combinations

Effective January 1, 2016, the Company adopted ASU 2015-16 on a prospective basis. The new standard requires that an acquirer must recognize adjustments to provisional amounts that are identified during the measurement period in the reporting period in which the adjustment amounts are determined. The adoption of the pronouncement did not have a material impact on the Company’s consolidated financial statements.

Measurement Date of Defined Benefit Obligation and Plan Assets

Effective January 1, 2016, the Company adopted ASU 2015-04 on a prospective basis. The revised criteria simplify the fair value measurement of defined benefit plan assets and obligations. The adoption of the pronouncement did not have a material impact on the Company’s consolidated financial statements.

Simplifying the Presentation of Debt Issuance Costs

Effective January 1, 2016, the Company adopted ASU 2015-03 on a retrospective basis which, as at December 31, 2015, resulted in a decrease in Deferred amounts and other assets of $149 million and a corresponding decrease in Long-term debt of $149 million. The new standard requires debt issuance costs related to a recognized debt liability to be presented in the Consolidated Statements of Financial Position as a direct deduction from the carrying amount of that debt liability, as consistent with the presentation of debt discounts or premiums. ASU 2015-15 was adopted in conjunction with the above standard and did not have a material impact on the Company’s consolidated financial statements. ASU 2015-15 clarifies the presentation and subsequent measurement of debt issuance costs associated with line-of-credit arrangements, whereby an entity may defer debt issuance costs as an asset and subsequently amortize them over the term of the line-of-credit.

Amendments to the Consolidation Analysis

Effective January 1, 2016, the Company adopted ASU 2015-02 on a modified retrospective basis, which amended and clarified the guidance on VIEs. There was a significant change in the assessment of limited partnerships and other similar legal entities as VIEs, including the removal of the presumption that the general partner should consolidate a limited partnership. As a result, the Company has determined that a majority of the limited partnerships that are currently consolidated or equity accounted for are VIEs. The amended guidance did not impact the Company’s accounting treatment of such entities, however, material disclosures for VIEs have been provided, as necessary.

Hybrid Financial Instruments Issued in the Form of a Share

Effective January 1, 2016, the Company adopted ASU 2014-16 on a modified retrospective basis. The revised criteria eliminate the use of different methods in practice in the accounting for hybrid financial instruments issued in the form of a share. The new standard clarifies the evaluation of the economic characteristics and risks of a host contract in these hybrid financial instruments. The adoption of the pronouncement did not have a material impact on the Company’s consolidated financial statements.

Development Stage Entities

Effective January 1, 2016, the Company adopted ASU 2014-10 on a retrospective basis. The new standard amends the consolidation guidance to eliminate the development stage entity relief when applying the VIE model and evaluating the sufficiency of equity at risk. The adoption of the pronouncement did not have a material impact on the Company’s consolidated financial statements.

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FUTURE ACCOUNTING POLICY CHANGES

Clarifying the Definition of a Business in an Acquisition

ASU 2017-01 was issued in January 2017 with the intent of clarifying the definition of a business with the objective of adding guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions (disposals) of assets or businesses. The Company is currently assessing the impact of the new standard on the consolidated financial statements. The accounting update is effective for annual and interim periods beginning on or after December 15, 2017 and is to be applied on a prospective basis.

Clarifying the Presentation of Restricted Cash in the Statement of Cash Flows

ASU 2016-18 was issued in November 2016 with the intent to add or clarify guidance on the classification and presentation of changes in restricted cash and restricted cash equivalents within the cash flow statement. The amendments require that changes in restricted cash and restricted cash equivalents should be included within cash and cash equivalents when reconciling the opening and closing period amounts shown on the statement of cash flows. The Company is currently assessing the impact of the new standard on its consolidated financial statements. The accounting update is effective for fiscal years beginning after December 15, 2017 and is to be applied on a retrospective basis.

Accounting for Intra-Entity Asset Transfers

ASU 2016-16 was issued in October 2016 with the intent of improving the accounting for the income tax consequences of intra-entity asset transfers other than inventory. Under the new guidance, an entity should recognize the income tax consequences of an intra-entity transfer of an asset, other than inventory, when the transfer occurs. The accounting update is effective for annual and interim periods beginning on or after December 15, 2017 and is to be applied on a modified retrospective basis, with early adoption permitted. Effective January 1, 2017, the Company elected to early adopt ASU 2016-16. The adoption of the pronouncement is not anticipated to have a material impact on the Company’s consolidated financial statements.

Simplifying Cash Flow Classification

ASU 2016-15 was issued in August 2016 with the intent of reducing diversity in practice of how certain cash receipts and cash payments are classified in the Consolidated Statements of Cash Flows. The new guidance addresses eight specific presentation issues. The Company is currently assessing the impact of the new standard on its consolidated financial statements. The accounting update is effective for annual and interim periods beginning on or after December 15, 2017 and is to be applied on a retrospective basis.

Accounting for Credit Losses

ASU 2016-13 was issued in June 2016 with the intent of providing financial statement users with more useful information about the expected credit losses on financial instruments and other commitments to extend credit held by a reporting entity at each reporting date. Current treatment uses the incurred loss methodology for recognizing credit losses that delays the recognition until it is probable a loss has been incurred. The amendment adds a new impairment model, known as the current expected credit loss model that is based on expected losses rather than incurred losses. Under the new guidance, an entity recognizes as an allowance its estimate of expected credit losses, which the Financial Accounting Standards Board believes will result in more timely recognition of such losses. The Company is currently assessing the impact of the new standard on its consolidated financial statements. The accounting update is effective for annual and interim periods beginning on or after December 15, 2019.

Improvements to Employee Share-Based Payment Accounting

ASU 2016-09 was issued in March 2016 with the intent of simplifying and improving several aspects of accounting for share-based payment transactions including the income tax consequences, classification of awards as either equity or liabilities, and classification on the Consolidated Statements of Cash Flows. The accounting update is effective for annual and interim periods beginning on or after December 15, 2016 and is to be applied on a prospective or retrospective basis. The adoption of the pronouncement is not anticipated to have a material impact on the Company’s consolidated financial statements.

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Recognition of Leases

ASU 2016-02 was issued in February 2016 with the intent to increase transparency and comparability among organizations by recognizing lease assets and lease liabilities on the Consolidated Statements of Financial Position and disclosing additional key information about leasing arrangements. The Company is currently assessing the impact of the new standard on its consolidated financial statements. The accounting update is effective for fiscal years beginning after December 15, 2018, and is to be applied using a modified retrospective approach.

Recognition and Measurement of Financial Assets and Liabilities

ASU 2016-01 was issued in January 2016 with the intent to address certain aspects of recognition, measurement, presentation, and disclosure of financial assets and liabilities. The amendments revise accounting related to the classification and measurement of investments in equity securities, the presentation of certain fair value changes for financial liabilities measured at fair value, and the disclosure requirements associated with the fair value of financial instruments. The Company is currently assessing the impact of the new standard on its consolidated financial statements. The accounting update is effective for fiscal years beginning after December 15, 2017, and is to be applied by means of a cumulative-effect adjustment to the Statements of Financial Position as of the beginning of the fiscal year of adoption, with amendments related to equity securities without readily determinable fair values to be applied prospectively.

Revenue from Contracts with Customers

ASU 2014-09 was issued in 2014 with the intent of significantly enhancing consistency and comparability of revenue recognition practices across entities and industries. The new standard establishes a single, principles-based five-step model to be applied to all contracts with customers and introduces new and enhanced disclosure requirements. The standard is effective January 1, 2018. The new revenue standard permits either a full retrospective method of adoption with restatement of all prior periods presented, or a modified retrospective method with the cumulative effect of applying the new standard recognized as an adjustment to opening retained earnings in the period of adoption. The Company is currently assessing which transition method to use.

The Company has reviewed a sample of its revenue contracts in order to evaluate the effect of the new standard on its revenue recognition practices. Based on the Company’s initial assessment, the application of the standard may result in a change in presentation in the Gas Distribution business related to payments to customers under the earnings sharing mechanism which are currently shown as an expense in the Consolidated Statements of Earnings. Under the new standard, these payments would be reflected as a reduction of revenue. Additionally, estimates of variable consideration which will be required under the new standard for certain Liquids Pipelines, Gas Pipelines and Processing and Green Power and Transmission revenue contracts as well as the allocation of the transaction price for certain Liquids Pipelines revenue contracts, may result in changes to the pattern or timing of revenue recognition for those contracts. While the Company has not yet completed the assessment, the Company’s preliminary view is that it does not expect these changes will have a material impact on revenue or earnings (loss). The Company is also developing processes to generate the disclosures required under the new standard.

4.   SEGMENTED INFORMATION

Effective January 1, 2016, the Company revised its reportable segments. Revisions to the segmented information presentation on a retrospective basis include:

·The replacement of the previous segments: Liquids Pipelines; Gas Distribution; Gas Pipelines, Processing and Energy Services; Sponsored Investments; and Corporate with new segments: Liquids Pipelines; Gas Distribution; Gas Pipelines and Processing; Green Power and Transmission; and Energy Services; and

·Presenting the Earnings before interest and income taxes of each segment as opposed to Earnings attributable to Enbridge Inc. common shareholders. Amounts related to Interest expense, Income taxes, Earnings attributable to noncontrolling interests and redeemable noncontrolling interests and Preference share dividends are now reported on a consolidated basis.

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On May 12, 2016, the Company filed amended financial statements for the year ended December 31, 2015 to retrospectively apply the revisions of its reportable segments to the 2015 financial statements of the Company that were previously filed on February 19, 2016.

Segmented information for the years ended December 31, 2016, 2015 and 2014 are as follows:

			Gas
			Pipelines	Green Power
	Liquids	Gas	and	and	Energy	Eliminations
Year ended December 31, 2016	Pipelines	Distribution	Processing	Transmission	Services	and Other	Consolidated
(millions of Canadian dollars)
Revenues	8,176	2,976	2,877	502	20,364	(335)	34,560
Commodity and gas distribution costs	(12)	(1,653)	(2,206)	5	(20,473)	334	(24,005)
Operating and administrative	(2,910)	(553)	(447)	(173)	(63)	(214)	(4,360)
Depreciation and amortization	(1,369)	(339)	(292)	(190)	(2)	(48)	(2,240)
Environmental costs, net of recoveries	2	-	-	-	-	-	2
Impairment of property, plant and equipment	(1,365)	-	(11)	-	-	-	(1,376)
	2,522	431	(79)	144	(174)	(263)	2,581
Income/(loss) from equity investments	194	12	223	2	(3)	-	428
Other income/(expense)	841	49	27	8	(8)	115	1,032
Earnings/(loss) before interest and income taxes	3,557	492	171	154	(185)	(148)	4,041
Interest expense							(1,590)
Income taxes							(142)
Earnings							2,309
Earnings attributable to noncontrolling interests and redeemable noncontrolling interests							(240)
Preference share dividends							(293)
Earnings attributable to Enbridge Inc. common shareholders							1,776
Additions to property, plant and equipment1	3,957	713	176	251	-	32	5,129
Total assets	52,043	10,204	11,182	5,571	1,951	4,881	85,832

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				Gas
				Pipelines	Green Power
		Liquids	Gas	and	and	Energy	Eliminations
Year ended December 31, 2015		Pipelines	Distribution	Processing	Transmission	Services	and Other	Consolidated
(millions of Canadian dollars)
Revenues		5,589	3,609	3,803	498	20,842	(547)	33,794
Commodity and gas distribution costs		(9)	(2,349)	(3,002)	4	(20,443)	558	(25,241)
Operating and administrative		(2,769)	(536)	(506)	(143)	(66)	(132)	(4,152)
Depreciation and amortization		(1,227)	(308)	(272)	(186)	1	(32)	(2,024)
Environmental costs, net of recoveries		21	-	-	-	-	-	21
Impairment of property, plant and equipment		(80)	-	(16)	-	-	-	(96)
Goodwill impairment		-	-	(440)	-	-	-	(440)
		1,525	416	(433)	173	334	(153)	1,862
Income/(loss) from equity investments		296	(10)	200	2	(9)	(4)	475
Other income/(expense)		(15)	49	4	2	-	(742)	(702)
Earnings/(loss) before interest and income taxes		1,806	455	(229)	177	325	(899)	1,635
Interest expense								(1,624)
Income taxes								(170)
Loss								(159)
Loss attributable to noncontrolling interests and redeemable noncontrolling interests								410
Preference share dividends								(288)
Loss attributable to Enbridge Inc. common shareholders								(37)
Additions to property, plant and equipment1		5,884	858	385	68	-	80	7,275
Total assets		52,015	9,901	11,559	4,977	1,889	4,174	84,515
				Gas
				Pipelines	Green Power
		Liquids	Gas	and	and	Energy	Eliminations
Year ended December 31, 2014		Pipelines	Distribution	Processing	Transmission	Services	and Other	Consolidated
(millions of Canadian dollars)
Revenues		4,805	3,319	6,650	360	23,099	(592)	37,641
Commodity and gas distribution costs		(1)	(2,082)	(5,686)	3	(22,314)	597	(29,483)
Operating and administrative		(1,985)	(531)	(533)	(94)	(58)	(80)	(3,281)
Depreciation and amortization		(911)	(304)	(221)	(124)	2	(19)	(1,577)
Environmental costs, net of recoveries		(100)	-	-	-	-	-	(100)
		1,808	402	210	145	729	(94)	3,200
Income/(loss) from equity investments		161	(14)	224	3	-	(6)	368
Other income/(expense)		11	44	33	1	1	(356)	(266)
Earnings/(loss) before interest and income taxes		1,980	432	467	149	730	(456)	3,302
Interest expense								(1,129)
Income taxes								(611)
Earnings from continuing operations								1,562
Discontinuing operations
Earnings from discontinued operations before income taxes								73
Income taxes from discontinued operations								(27)
Earnings from discontinued operations								46
Earnings								1,608
Earnings attributable to noncontrolling interests and redeemable noncontrolling interests								(203)
Preference share dividends								(251)
Earnings attributable to Enbridge Inc. common shareholders								1,154
Additions to property, plant and equipment1		8,914	610	593	333	3	74	10,527
1	Includes allowance for equity funds used during construction.

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

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OUT-OF-PERIOD ADJUSTMENT

Earnings attributable to Enbridge Inc. common shareholders for the year ended December 31, 2015 were increased by an out-of-period adjustment of $71 million in respect of an overstatement of deferred income tax expense in 2013 and 2014.

GEOGRAPHIC INFORMATION

Revenues1

Year ended December 31,	2016	2015	2014
(millions of Canadian dollars)
Canada	12,470	11,087	14,963
United States	22,090	22,707	22,678
	34,560	33,794	37,641

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

Property, Plant and Equipment

December 31,	2016	2015
(millions of Canadian dollars)
Canada	32,008	30,656
United States	32,276	33,778
	64,284	64,434

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 by the NEB. The Company also collects and sets aside funds to cover future pipeline abandonment costs for all NEB regulated pipelines as a result of the NEB’s regulatory requirements under LMCI (Note 12). Amounts expected to be paid to cover future abandonment costs are recognized as long-term regulatory liabilities. The Company’s significant regulated businesses and other related accounting impacts, are described below.

Liquids Pipelines

Canadian Mainline

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 10-year CTS, which establishes a Canadian Local Toll for all volumes shipped on the Canadian Mainline and an International Joint Tariff for all volumes shipped from western Canadian receipt points to delivery points on the Lakehead System and delivery points on the Canadian Mainline downstream of the Lakehead System. The CTS was negotiated with shippers in accordance with NEB guidelines, was approved by the NEB in June 2011 and took effect July 1, 2011. Under the CTS, a regulatory asset is recognized to offset deferred income taxes as a NEB rate order governing flow-through income tax treatment permits future recovery. No other material regulatory assets or liabilities are recognized under the terms of the CTS.

Southern Lights Pipeline

The United States portion of the Southern Lights Pipeline (Southern Lights US) is regulated by the FERC and the Canadian portion of the Southern Lights Pipeline (Southern Lights Canada) is regulated by the NEB. Shippers on the Southern Lights Pipeline are subject to long-term transportation contracts under a cost of service toll methodology. Toll adjustments are filed annually with the regulators. Tariffs provide for recovery of allowable operating and debt financing costs, plus a pre-determined after-tax rate of return on equity (ROE) of 10%. Southern Lights Pipeline tolls are based on a deemed 70% debt and 30% equity structure.

Gas Distribution

Enbridge Gas Distribution

EGD’s gas distribution operations are regulated by the OEB. Rates for the years ended December 31, 2016 and 2015 were set in accordance with parameters established by the customized incentive rate plan (IR Plan). The customized IR Plan was approved in 2014 by the OEB, with modifications, for 2014 through 2018, inclusive of the requested capital investment amounts and an incentive mechanism providing the opportunity to earn above the allowed ROE.

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Within annual rate proceedings for 2015 through 2018, the customized IR Plan requires allowed revenues, and corresponding rates, to be updated annually for select items. The OEB also approved the adoption of a new approach for determining net salvage percentages to be included within EGD’s approved depreciation rates, as compared with the traditional approach previously employed. The new approach results in lower net salvage percentages for EGD, and therefore lowers depreciation rates and future removal and site restoration reserves. The customized IR Plan includes an earnings sharing mechanism, whereby any return over the allowed rate of return for a given year under the customized IR Plan will be shared equally with customers.

EGD’s after-tax rate of return on common equity embedded in rates was 9.2% for the year ended December 31, 2016 (2015 - 9.3%) based on a 36% (2015 - 36%) deemed common equity component of capital for regulatory purposes.

Enbridge Gas New Brunswick

Enbridge Gas New Brunswick Inc. is regulated by the EUB and currently sets tolls at either market-based or cost of service rates.

FINANCIAL STATEMENT EFFECTS

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

December 31,	2016		2015
(millions of Canadian dollars)
Regulatory assets/(liabilities)
Liquids Pipelines
Deferred income taxes1	1,270		1,048
Tolling deferrals2	(37	)	(39	)
Recoverable income taxes3	51		54
Pipeline future abandonment costs4	(88	)	(47	)
Transportation revenue adjustments5	-		11
Gas Distribution
Deferred income taxes6	385		328
Purchased gas variance7	5		129
Pension plans and OPEB8	116		104
Constant dollar net salvage adjustment9	38		42
Unabsorbed demand cost10	-		66
Future removal and site restoration reserves11	(606	)	(581	)
Site restoration clearance adjustment12	(109	)	(193	)
Transaction services deferral13	(4	)	(9	)

1The deferred income tax 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 reversal of temporary differences.

2The tolling deferrals reflect net tax benefits expected to be refunded through future transportation tolls on Southern Lights Canada. The balance is expected to continue to accumulate through 2018 before being refunded through tolls. Tolling deferrals are not included in the rate base.

3The recoverable income tax asset represents future revenues to be collected from shippers for Southern Lights US to recover federal income taxes payable on the equity component of AFUDC. The recovery period commenced in 2010 and is approximately 30 years.

4The pipeline future abandonment costs liability results from amounts collected and set aside in accordance with the NEB’s LMCI to cover future abandonment costs for NEB regulated Canadian pipelines. Funds collected are included in Restricted long-term investments (Note 12). Concurrently, the Company reflects the future abandonment cost as a regulatory liability. The settlement of this balance will occur as pipeline abandonment costs are incurred.

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5The transportation revenue adjustments are the cumulative differences between actual expenses incurred and estimated expenses included in transportation tolls. Transportation revenue adjustments are not included in the rate base.

6The deferred income tax asset represents the regulatory offset to deferred income tax liabilities to the extent that it is expected to be included in regulator-approved future rates and recovered from future customers. The recovery period depends on the timing of the reversal of the temporary differences.

7Purchased gas variance (PGVA) is the difference between the actual cost and the approved cost of natural gas reflected in rates. Enbridge Gas Distribution has been granted OEB approval to refund this balance to, or to collect this balance from, customers on a rolling 12 month basis via the Quarterly Rate Adjustment Mechanism process. In May 2014, the OEB issued a decision allowing a portion of the PGVA balance as at June 30, 2014 to be recovered over a 24-month period from July 1, 2014 to June 30, 2016.

8The 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 being collected over a 20-year period that commenced in 2013. The balance at December 31, 2016 was $71 million (2015 - $75 million). The settlement period for the pension regulatory asset is not determinable. The balances are excluded from the rate base and do not earn an ROE.

9The constant dollar net salvage adjustment represents the cumulative variance between the amount proposed for clearance and the actual amount cleared, relating specifically to the site restoration clearance adjustment. At the end of 2018, any residual balance will be cleared in a post 2018 true up.

10The unabsorbed demand cost deferral account represents the actual cost consequences of unutilized transportation capacity contracted by Enbridge Gas Distribution to meet requirements resulting from its Peak Gas Design Day Criteria.

11The 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.

12The site restoration clearance adjustment represents the amount, that was determined by the OEB, of previously collected costs for future removal and site restoration that is now considered to be in excess of future requirements and will be refunded to customers over the customized IR term. This was a result of the OEB’s approval of the adoption of a new approach for determining net negative salvage percentages. The new approach resulted in lower depreciation rates and lower future removal and site restoration reserves.

13The transaction services deferral represents the customer portion of additional earnings generated from optimization of storage and pipeline capacity. Enbridge Gas Distribution has historically been required to refund the amount to customers in the following year.

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 and 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 specified 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, 2016, cumulative costs relating to this consulting contract of $181 million (2015 - $179 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.

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6.   ACQUISITION AND DISPOSITIONS

ACQUISITIONS

Spectra Energy Corp

On September 6, 2016 Enbridge and Spectra Energy Corp (Spectra Energy) announced that they had entered into a definitive merger agreement under which Enbridge and Spectra Energy would combine in a stock-for-stock merger transaction (the Merger Transaction). The Merger Transaction was unanimously approved by the Boards of Directors and shareholders of both companies. Shareholders’ approval for both companies was received in December 2016 and the Merger Transaction is expected to close in the first quarter of 2017, subject to certain regulatory approvals and other customary conditions.

Under the terms of the Merger Transaction, Spectra Energy shareholders will receive 0.984 shares of the combined company for each share of Spectra Energy common stock they own. Upon completion of the Merger Transaction, Enbridge shareholders are expected to own approximately 57% of the combined company and Spectra Energy shareholders are expected to own approximately 43%. The combined company will be called Enbridge Inc.

Tupper Main and Tupper West

On April 1, 2016, Enbridge acquired the Tupper Main and Tupper West gas plants and associated pipelines (the Tupper Plants) located in northeastern British Columbia for cash consideration of $539 million. The purchase price for the Tupper Plants was equal to the fair value of identifiable net assets acquired and accordingly, the Company did not recognize any goodwill as part of the acquisition. Transaction costs incurred by the Company totalled approximately $1 million and are included in Operating and administrative expense within the Consolidated Statements of Earnings. The Tupper Plants are included within the Gas Pipelines and Processing segment.

Since the closing date through December 31, 2016, the Tupper Plants have generated approximately $33 million in revenues and $22 million in earnings before interest and income taxes. If the acquisition had closed on January 1, 2016, the Consolidated Statements of Earnings for the years ended December 31, 2016, would have shown revenues of $44 million and earnings before interest and income taxes of $28 million, respectively.

The final purchase price allocation was as follows:

April 1,	2016
(millions of Canadian dollars)
Fair value of net assets acquired:
Property, plant and equipment	288
Intangible assets	251
	539
Purchase price:
Cash	539

Midstream Business

On February 27, 2015, Enbridge Energy Partners, L.P. (EEP) acquired the midstream business of New Gulf Resources, LLC (NGR) in Leon, Madison and Grimes Counties, Texas for $106 million (US$85 million) in cash and a contingent future payment of up to $21 million (US$17 million), through its partially-owned subsidiary, Midcoast Energy Partners, L.P. (MEP). The acquisition consisted of a natural gas gathering system that is in operation and is presented within the Gas Pipelines and Processing segment. Revenues and earnings of $2 million and nil, respectively, since the date of acquisition were recognized for the year ended December 31, 2015.

If the acquisition had occurred on January 1, 2015, changes to revenues and earnings for the years ended December 31, 2016 and 2015 would have been nominal.

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The final purchase price allocation was as follows:

February 27,	2015
(millions of Canadian dollars)
Fair value of net assets acquired:
Property, plant and equipment	69
Intangible assets	40
	109
Purchase price:
Cash	106
Contingent consideration1	3

1The contingent future payment of up to US$17 million is dependent upon NGR’s ability to deliver specified volumes into MEP’s system over a five-year period. The fair value of the contingent future consideration at the acquisition date was $3 million (US$2 million). During the first quarter of 2016, and upon subsequent reassessments, MEP determined, based on current and forecasted volumes, that it is remote that MEP will be obligated to make any payments at the expiration of the five-year period. Consequently, the liability was reversed and a $4 million (US$3 million) gain was recognized as a reduction to “Operating and administrative” expense, which is reflected in the consolidated statements of income for the year ended December 31, 2016.

Magic Valley and Wildcat Wind Farms

On December 31, 2014, Enbridge acquired an 80% controlling interest in Magic Valley, a wind farm located in Texas, and Wildcat, a wind farm located in Indiana, for cash consideration of $394 million (US$340 million). No revenue or earnings were recognized in the year ended December 31, 2014 as the wind farms were acquired on December 31, 2014. The wind farms are included within the Green Power and Transmission segment.

If the acquisition had occurred on January 1, 2013, proforma consolidated revenues and earnings for the year ended December 31, 2014 would have increased by $64 million (US$58 million) and $8 million (US$7 million), respectively, and proforma consolidated revenues and earnings for the year ended December 31, 2013 would have increased by $44 million (US$43 million) and decreased by $2 million (US$2 million), respectively.

The final purchase price allocation was a follows:

December 31,	2014
(millions of Canadian dollars)
Fair value of net assets acquired:
Property, plant and equipment	747
Intangible assets	12
Other long-term liabilities	(14	)
Noncontrolling interests1	(351	)
	394
Purchase price:
Cash	394

1The fair value of the noncontrolling interests was determined using a combination of the implied purchase price for the remaining 20% interest and discounted cash flow models.

OTHER ACQUISITIONS

Chapman Ranch Wind Project

On September 9, 2016, the Company acquired a 100% interest in the 249 megawatt (MW) Chapman Ranch Wind Project (Chapman Ranch) located in Texas for cash consideration of $65 million (US$50 million), of which $62 million (US$48 million) was allocated to Property, plant and equipment and the balance allocated to Intangible assets. On November 2, 2016, the Company invested a further $40 million (US$30 million) in Chapman Ranch, of which $23 million (US$17 million) was related to Property, plant and equipment and the balance related to Intangible assets. There would have been no effect on earnings if the transaction had occurred on January 1, 2016 as the project is under construction and has not generated revenues to date. Chapman Ranch is included within the Green Power and Transmission segment.

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Other

In November 2015, the Company acquired a 100% interest in the 103 MW New Creek Wind Project (New Creek) for cash consideration of $48 million (US$36 million), with $35 million (US$26 million) of the purchase price allocated to Property, plant and equipment and the remainder allocated to Intangible assets. New Creek was placed into service in December 2016.

In December 2014, the Company acquired an incremental 30% interest in the Massif du Sud Wind Project (Massif du Sud) for cash consideration of $102 million, bringing its total interest in the wind project to 80%. The Company acquired its original 50% interest in Massif du Sud in December 2012. The Company’s interest in Massif du Sud represents an undivided interest, with $97 million of the incremental purchase allocated to Property, plant and equipment and the remainder allocated to Intangible assets. Massif du Sud is operational.

In October 2014, the Company acquired an incremental 17.5% interest in the Lac Alfred Wind Project (Lac Alfred) for cash consideration of $121 million, bringing its total interest in the wind project to 67.5%. The Company acquired its original 50% interest in Lac Alfred in December 2011. The Company’s interest in Lac Alfred represents an undivided interest, with $115 million of the incremental purchase allocated to Property, plant and equipment and the remainder allocated to Intangible assets. Lac Alfred is operational.

The New Creek, Massif du Sud and Lac Alfred wind projects are included within the Green Power and Transmission segment.

ASSETS HELD FOR SALE

In December 2016, the Company entered into an agreement to sell the Ozark Pipeline assets to a subsidiary of MPLX LP for cash proceeds of approximately $294 million (US$219 million), including $13 million (US$10 million) in reimbursable capital costs up to the closing date of the transaction. Subject to certain pre-closing conditions, the transaction is expected to close by the end of the first quarter of 2017. The Ozark Pipeline is included within the Company’s Liquids Pipelines segment.

As at December 31, 2016, the assets of Ozark Pipeline were classified as held for sale and were measured at the lower of their carrying value or fair value less costs to sell, which did not result in a fair value adjustment. Included within Assets held for sale on the Consolidated Statements of Financial Position was $278 million (US$207 million) related to Property, plant and equipment.

DISPOSITIONS

South Prairie Region

On December 1, 2016, the Company completed the sale of the South Prairie Region assets to an unrelated party for cash proceeds of $1.08 billion. A gain on sale of $850 million before tax was recognized in Other income/(expense) on the Consolidated Statements of Earnings. The South Prairie Region assets were included within the Company’s Liquids Pipelines segment. For the year ended December 31, 2016, pre-tax earnings for the South Prairie Region assets were $41 million.

OTHER DISPOSITIONS

In December 2016, the Company sold other miscellaneous non-core assets for cash proceeds of $286 million.

In August 2015, the Company sold its 77.8% controlling interest in the Frontier Pipeline Company, which holds pipeline assets located in the midwest United States, to unrelated parties for gross proceeds of $112 million (US$85 million). A gain of $70 million (US$53 million) was presented within Other income/(expense) on the Consolidated Statements of Earnings. These amounts are included within the Liquids Pipelines segment.

In May 2015, the Fund sold certain of its crude oil pipeline system assets within the Liquids Pipelines segment to an unrelated party for gross proceeds of $26 million. A gain of $22 million was presented within Other income/(expense) on the Consolidated Statements of Earnings.

In November 2014, the Company sold one of its non-core assets within Enbridge Offshore Pipelines (Offshore), which include pipeline facilities located in Louisiana, to an unrelated party for $7 million (US$7 million). A gain of $22 million (US$19 million) was presented within Other income/(expense) on the Consolidated Statements of Earnings. These assets were included within the Gas Pipelines and Processing segment.

27

In July 2014, the Company sold a 35% equity interest in the Southern Access Extension Project within the Liquids Pipelines segment, a pipeline project then under construction, to an unrelated party for gross proceeds of $73 million (US$68 million). As the fair value of the consideration received equalled the carrying value of the asset sold, no gain or loss was recognized on the sale.

In March 2014, the Company sold an Alternative and Emerging Technologies investment within Eliminations and Other to an unrelated party for $19 million. A gain of $16 million was presented within Other income/(expense) on the Consolidated Statements of Earnings.

7.   ACCOUNTS RECEIVABLE AND OTHER

December 31,	2016		2015
(millions of Canadian dollars)
Unbilled revenues	2,886		2,476
Trade receivables	974		1,079
Taxes receivable	222		175
Regulatory assets	66		216
Short-term portion of derivative assets (Note 24)	353		791
Prepaid expenses and deposits	168		181
Current deferred income taxes (Note 25)	-		367
Dividends receivable	26		26
Rebillable receivables	63		-
Agent billing and collection receivable	35		39
Other	231		125
Allowance for doubtful accounts	(46	)	(45	)
	4,978		5,430

Pursuant to a Receivables Purchase Agreement (the Receivables Agreement) executed in 2013, certain trade and accrued receivables (the Receivables) have been sold by certain EEP subsidiaries to an Enbridge wholly-owned special purpose entity (SPE). The Receivables owned by the SPE are not available to Enbridge except through its 100% ownership in such SPE. The Receivables Agreement was amended in June 2016 to extend the termination date that provides for purchases to occur on a monthly basis through to December 2019, provided accumulated purchases net of collections do not exceed US$450 million at any one point. The value of trade and accrued receivables outstanding owned by the SPE totalled US$355 million ($477 million) and US$317 million ($439 million) as at December 31, 2016 and December 31, 2015, respectively.

8.   INVENTORY

December 31,	2016	2015
(millions of Canadian dollars)
Natural gas	594	627
Crude oil	634	477
Other commodities	5	7
	1,233	1,111

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9.   PROPERTY, PLANT AND EQUIPMENT

	Weighted Average
December 31,	Depreciation Rate	2016		2015
(millions of Canadian dollars)
Liquids Pipelines
Pipeline	2.7%	30,809		31,092
Pumping equipment, buildings, tanks and other	3.0%	15,215		14,319
Land and right-of-way	2.4%	1,218		1,221
Under construction	-	5,419		6,002
		52,661		52,634
Accumulated depreciation		(8,996	)	(8,233	)
		43,665		44,401
Gas Distribution
Gas mains, services and other	3.1%	10,022		8,819
Land and right-of-way	1.0%	133		85
Under construction	-	144		902
		10,299		9,806
Accumulated depreciation		(2,524	)	(2,379	)
		7,775		7,427
Gas Pipelines and Processing
Pipeline	3.0%	3,665		3,557
Compressors, meters and other operating equipment	2.4%	4,014		3,864
Processing and treating plants	2.4%	846		869
Pumping equipment, buildings, tanks and other	8.4%	306		275
Land and right-of-way	2.3%	673		680
Under construction	-	791		956
		10,295		10,201
Accumulated depreciation		(2,167	)	(2,003	)
		8,128		8,198
Green Power and Transmission
Wind turbines, solar panels and other	4.1%	4,259		4,311
Power transmission	2.2%	378		387
Land and right-of-way	1.9%	43		45
Under construction	-	612		51
		5,292		4,794
Accumulated depreciation		(778	)	(600	)
		4,514		4,194
Energy Services
Pumping equipment and other	4.0%	33		34
		33		34
Accumulated depreciation		(13	)	(13	)
		20		21
Eliminations and Other
Vehicles, office furniture, equipment and other	9.3%	315		331
		315		331
Accumulated depreciation		(133	)	(138	)
		182		193
		64,284		64,434

Depreciation expense for the year ended December 31, 2016 was $2,049 million (2015 - $1,852 million 2014 - $1,461 million).

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IMPAIRMENT

Northern Gateway Pipeline Project

On November 29, 2016, the Canadian Federal Government directed the NEB to dismiss the Company’s Northern Gateway application and the Certificates of Public Convenience and Necessity have been rescinded. In consultation with potential shippers and Aboriginal equity partners, the Company assessed this decision and concluded that the project cannot proceed as envisioned. After taking into consideration the amount recoverable from potential shippers on Northern Gateway, the Company recognized an impairment of $373 million ($272 million after-tax), which is included in Impairment of property, plant and equipment in the Consolidated Statements of Earnings. This impairment loss is based on the full carrying value of the assets, which have an estimated fair value of nil, and is included within the Liquids Pipelines segment.

Sandpiper Project

On September 1, 2016, Enbridge announced that EEP applied for the withdrawal of regulatory applications pending with the Minnesota Public Utilities Commission for the Sandpiper Project (Sandpiper). In connection with this announcement and other factors, the Company evaluated Sandpiper for impairment. As a result, the Company recognized an impairment loss of $992 million ($81 million after-tax attributable to Enbridge) for the year ended December 31, 2016, which is included in Impairment of property, plant and equipment in the Consolidated Statements of Earnings. Sandpiper is included within the Liquids Pipelines segment. The estimated remaining fair value of $71 million of Sandpiper is based on the estimated price that would be received to sell unused pipe, land and other related equipment in its current condition, considering the current market conditions for sale of these assets. The valuation considered a range of potential selling prices from various alternatives that could be used to dispose of these assets. The estimated fair value, with the exception of $3 million in land, has been reclassified into Deferred amounts and other assets in the Consolidated Statements of Financial Position as at December 31, 2016.

Other

For the year ended December 31, 2016, the Company recorded impairment charges of $11 million related to EEP’s non-core trucking assets and related facilities, included within the Gas Pipelines and Processing segment.

For the year ended December 31, 2015, the Company recorded impairment charges of $96 million, of which $80 million related to EEP’s Berthold rail facility, included within the Liquids Pipelines segment, due to contracts that have not been renewed beyond 2016. The remaining $16 million in impairment charges relate to EEP’s non-core Louisiana propylene pipeline asset, included within the Gas Pipelines and Processing segment, following finalization of a contract restructuring with the primary customer.

Impairment charges were based on the amount by which the carrying values of the assets exceeded fair value, determined using expected discounted future cash flows, and were presented within Impairment of property, plant and equipment on the Consolidated Statements of Earnings.

DISCONTINUED OPERATIONS

In March 2014, the Company completed the sale of certain of its Offshore assets located within the Stingray corridor to an unrelated third party for cash proceeds of $11 million (US$10 million), subject to working capital adjustments. The gain of $70 million (US$63 million), which resulted from the cash proceeds and the disposition of net liabilities held for sale of $59 million (US$53 million), is presented as Earnings from discontinued operations. The results of operations, including revenues of $4 million and related cash flows, have also been presented as discontinued operations for the year ended December 31, 2014. These Offshore assets were included within the Gas Pipelines and Processing segment.

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10.   VARIABLE INTEREST ENTITIES

CONSOLIDATED VARIABLE INTEREST ENTITIES

Enbridge Energy Partners, L.P.

EEP is a publicly-traded Delaware limited partnership and is considered a VIE as its limited partners do not have substantive kick-out rights or participating rights. Enbridge, through its wholly-owned subsidiary, Enbridge Energy Company, Inc. (EECI), has the power to direct EEP’s activities that have a significant impact on EEP’s economic performance. Along with a 35.3% (2015 - 35.7%; 2014 - 33.7%) economic interest held through an indirect common interest and preferred unit interest through EECI, the Company, through its 100% ownership of EECI, is the primary beneficiary of EEP. The public owns the remaining interests in EEP.

Enbridge Income Fund

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 86.9% (2015 - 89.2%; 2014 - 66.4%) economic interest held indirectly through a common investment in ENF, a direct common interest in the Fund, a preferred unit investment in ECT, a direct common interest in Enbridge Income Partners GP Inc. and a direct common interest in EIPLP. As at December 31, 2016, the Company’s direct common interest in the Fund was 43.2% (2015 - 49.2%; 2014 - 11.9%). Enbridge also serves in the capacity of Manager of ENF and the Fund Group.

Enbridge Commercial Trust

Enbridge has the ability to appoint the majority of the Trustees to ECT’s Board of Trustees, resulting in the lack of decision making ability for the holders of the common trust units of ECT. As a result, ECT is considered to be a VIE and although Enbridge does not have a common equity interest in ECT, the Company is considered to be the primary beneficiary of ECT. Enbridge also serves in the capacity of Manager of ECT, as part of the Fund Group.

Enbridge Income Partners LP
EIPLP, formed in 2002, is involved in the generation, transportation and storage of energy through interests in its Liquids Pipelines business, including the Canadian Mainline, the Regional Oil Sands System, a 50.0% interest in the Alliance Pipeline, which transports natural gas, and its renewable and alternative power generation facilities. EIPLP is a partnership between an indirect wholly-owned subsidiary of the Company and ECT. EIPLP is considered a VIE as its limited partners lack substantive kick-out rights and participating rights. Through a majority ownership of EIPLP’s General Partner, 100% ownership of Enbridge Management Services Inc. (a service provider for EIPLP), and 54.2% of direct common interest in EIPLP, the Company has the power to direct the activities that most significantly impact EIPLP’s economic performance and has the obligation to absorb losses and the right to receive residual returns that are potentially significant to EIPLP, making the Company the primary beneficiary of EIPLP. As at December 31, 2016, the Company’s economic interest in EIPLP was 79.1%.

Green Power and Transmission

Through various subsidiaries, Enbridge has majority ownership interest in Magic Valley, Wildcat, Keechi, and New Creek wind farms. These wind farms are considered VIEs as they do not have sufficient equity at risk and are partially financed by tax equity investors. Enbridge is the primary beneficiary of these VIEs by virtue of the Company’s voting rights, its power to direct the activities that most significantly impact the economic performance of the wind farms, and its obligation to absorb losses.

Other Limited PartnershipsBy virtue of a lack of substantive kick-out rights and participating rights, substantially all limited partnerships wholly-owned by Enbridge and/or its subsidiaries are considered VIEs. As these entities are 100% owned and directed by Enbridge with no third parties having the ability to direct any of the significant activities, the Company is considered the primary beneficiary.

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The following table includes assets to be used to settle liabilities of Enbridge’s consolidated VIEs and liabilities of Enbridge’s consolidated VIEs for which creditors do not have recourse to the Company’s general credit as the primary beneficiary. These assets and liabilities are included in the Consolidated Statements of Financial Position.

December 31,	2016	2015
(millions of Canadian dollars)
Assets
Cash and cash equivalents	486	362
Restricted cash	-	26
Accounts receivable and other	781	972
Accounts receivable from affiliates	3	29
Inventory	53	54
	1,323	1,443
Property, plant and equipment, net	45,720	45,882
Long-term investments	954	1,005
Restricted long-term investments	83	45
Deferred amounts and other assets	1,949	1,806
Intangible assets, net	488	525
Goodwill	29	29
Deferred income taxes	231	267
Assets held for sale	278	-
	51,055	51,002
Liabilities
Bank indebtedness	172	33
Accounts payable and other	1,446	2,077
Accounts payable to affiliates	105	92
Interest payable	204	202
Environmental liabilities	140	139
Current maturities of long-term debt	342	760
	2,409	3,303
Long-term debt	20,176	19,998
Other long-term liabilities	1,207	1,340
Deferred income taxes	1,753	1,253
	25,545	25,894
Net assets before noncontrolling interests	25,510	25,108

The Company does not have an obligation to provide financial support to any of the consolidated VIEs, with the exception of EIPLP. The Company is required, when called on by Enbridge Income Fund Holdings Inc., to backstop equity funding required by EIPLP to undertake the growth program embedded in the assets it acquired in the Canadian Restructuring Plan.

UNCONSOLIDATED VARIABLE INTEREST ENTITIES
The Company currently holds several equity investments in limited partnerships that are assessed to be VIEs due to limited partners not having substantive kick-out rights or participating rights. Enbridge has determined that it does not have the power to direct the activities of the VIEs that most significantly impact the VIEs’ economic performance. Specifically, the power to direct the activities of a majority of these VIEs is shared amongst the partners. Each partner has representatives that make up an executive committee who makes significant decisions for the VIE and none of the partners may make major decisions unilaterally.

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The carrying amount of the Company’s interest in VIEs that are unconsolidated and its estimated maximum exposure to loss as at December 31, 2016 and 2015 is presented below.

	Carrying	Enbridge’s
	Amount of	Maximum
	Investment	Exposure to
December 31, 2016	in VIE	Loss
(millions of Canadian dollars)
Vector Pipeline L.P.4	159	289
Aux Sable Liquid Products L.P.2	158	223
Rampion Offshore Wind Limited3	345	457
Eddystone Rail Company, LLC4	19	25
Illinois Extension Pipeline Company, L.L.C.1	759	759
Eolien Maritime France SAS5	58	686
Other1	17	17
	1,515	2,456

	Carrying	Enbridge’s
	Amount of	Maximum
	Investment	Exposure to
December 31, 2015	in VIE	Loss
(millions of Canadian dollars)
Vector Pipeline L.P.4	159	308
Aux Sable Liquid Products L.P.1	175	175
Rampion Offshore Wind Limited3	201	403
Eddystone Rail Company, LLC4	168	220
Illinois Extension Pipeline Company, L.L.C.1	713	713
Other1	15	15
	1,431	1,834

1At December 31, 2016, the maximum exposure to loss for these entities is limited to the Company’s equity investment as these companies are in operation and self-sustaining.

2At December 31, 2016, the maximum exposure to loss includes a guarantee by the Company for its respective share of the VIE’s borrowing on a bank credit facility.

3At December 31, 2016, the maximum exposure to loss includes the portion of the Company’s parental guarantee that has been committed in project construction contracts in which the Company would be liable for in the event of default by the VIE.

4At December 31, 2016 the maximum exposure to loss includes the carrying value of an outstanding loan issued by the Company.

5At December 31, 2016, the maximum exposure to loss includes the portion of the Company’s parental guarantee that has been committed in project construction contracts in which the Company would be liable for in the event of default by the VIE and an outstanding affiliate loan receivable for $136 million held by the Company.

The Company does not have an obligation to and did not provide any additional financial support to the VIEs during the year ended December 31, 2016.

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11.   LONG-TERM INVESTMENTS

	Ownership
December 31,	Interest	2016	2015
(millions of Canadian dollars)
EQUITY INVESTMENTS
Liquids Pipelines
Seaway Crude Pipeline System	50.0%	3,129	3,251
Southern Access Extension Project	65.0%	759	713
Enbridge Rail (Philadelphia) L.L.C.	75.0%	19	168
Other	30.0% - 43.9%	70	69
Gas Distribution
Noverco Common Shares	38.9%	-	-
Gas Pipelines and Processing
Texas Express Pipeline	35.0%	484	515
Alliance Pipeline	50.0%	411	427
Aux Sable	42.7% - 50.0%	324	344
Vector Pipeline	60.0%	159	159
Offshore - various joint ventures	22.0% - 74.3%	435	479
Other	33.3% - 70.0%	4	12
Green Power and Transmission
Rampion offshore wind project1	24.9%	345	201
Eolien Maritime France SAS2	50.0%	58	-
Other	18.9% - 50.0%	100	109
Eliminations and Other
Other	19.0% - 42.7%	15	12
OTHER LONG-TERM INVESTMENTS
Gas Distribution
Noverco Preferred Shares		355	359
Green Power and Transmission
Emerging Technologies and Other		90	106
Eliminations and Other
Other		79	84
		6,836	7,008

1On November 4, 2015, Enbridge acquired a 24.9% equity interest in Rampion Offshore Wind Limited.

2On May 19, 2016, Enbridge acquired a 50% equity interest in Eolien Maritime France SAS.

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 $859 million (2015 - $885 million) in Goodwill and $687 million (2015 - $568 million) in amortizable assets.

For the year ended December 31, 2016, dividends received from equity investments was $825 million (2015 - $719 million; 2014 - $564 million).

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

Year ended December 31,	2016		2015		2014
(millions of Canadian dollars)
Revenues	1,761		1,557		1,790
Commodity costs	(385	)	(369	)	(661	)
Operating and administrative expense	(545	)	(376	)	(444	)
Depreciation and amortization	(293	)	(274	)	(232	)
Other income/(expense)	(41	)	4		(1	)
Interest expense	(69	)	(67	)	(84	)
Earnings before income taxes	428		475		368
December 31,			2016		2015
(millions of Canadian dollars)
Current assets			464		389
Property, plant and equipment, net			6,534		6,602
Deferred amounts and other assets			47		40
Intangible assets, net			118		64
Goodwill			862		885
Current liabilities			(433	)	(500	)
Long-term debt			(792	)	(854	)
Other long-term liabilities			(488	)	(167	)
Net assets			6,312		6,459

Alliance Pipeline

Certain assets of the Alliance Pipeline are pledged as collateral to Alliance Pipeline lenders.

Noverco

As at December 31, 2016, Enbridge owned an equity interest in Noverco through ownership of 38.9% (2015 - 38.9%) 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 margin of 4.38%.

As at December 31, 2016, Noverco owned an approximate 3.4% (2015 - 3.6%; 2014 - 3.6%) reciprocal shareholding in common shares of Enbridge. Through secondary offerings, Noverco purchased 1.2 million common shares in February 2016 and sold 1.3 million common shares in 2014. Shares purchased and sold in these transactions were treated as treasury stock on the Consolidated Statements of Changes in Equity.

As a result of Noverco’s reciprocal shareholding in Enbridge common shares, the Company has an indirect pro-rata interest of 1.3% (2015 - 1.4%; 2014 - 1.4%) in its own shares. Both the equity investment in Noverco and shareholders’ equity have been reduced by the reciprocal shareholding of $102 million at December 31, 2016 (2015 - $83 million; 2014 - $83 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.

Eddystone Rail Company, LLC

During the year ended December 31, 2016, the Company recorded an investment impairment of $184 million related to Enbridge’s 75% joint venture interest in Eddystone Rail Company, LLC (Eddystone Rail), which is held through Enbridge Rail (Philadelphia) L.L.C., a wholly-owned subsidiary. Eddystone Rail is a rail-to-barge transloading facility located in the greater Philadelphia, Pennsylvania area that delivers Bakken and other light sweet crude oil to Philadelphia area refineries. Due to a significant decrease in price spreads between Bakken crude oil and West Africa/Brent crude oil and increased competition in the region, demand for Eddystone Rail services dropped significantly, which led to the completion of an impairment test. The impairment charge is presented within Income from equity investments on the Consolidated Statements of Earnings. The investment in Eddystone Rail is included within the Liquids Pipelines segment.

35

The impairment charge was based on the amount by which the carrying value of the asset exceeded fair value, determined using an adjusted net worth approach. The Company’s estimate of fair value required it to use significant unobservable inputs representative of a Level 3 fair value measurement, including assumptions related to the future performance of Eddystone Rail.

Aux Sable

During the year ended December 31, 2016, Aux Sable recorded an asset impairment charge of $37 million related to certain underutilized assets at Aux Sable US’ NGL extraction and fractionation plant.

Eolien Maritime France SAS

Effective May 19, 2016, Enbridge acquired a 50% interest in Eolien Maritime France SAS (EMF), a French offshore wind development company. EMF is co-owned by Enbridge and EDF Energies Nouvelles, a subsidiary of Électricité de France S.A. EMF holds licenses for three large-scale offshore wind farms off the coast of France, which are currently under development. Enbridge’s portion of the costs incurred to date is approximately $194 million (€136 million) with $58 million presented in Long-term investments, and $136 million presented in Deferred amounts and other assets.

Rampion Offshore Wind Project

In November 2015, Enbridge announced the acquisition of a 24.9% interest in the 400-MW Rampion Offshore Wind Project (the Rampion project) in the United Kingdom (UK), located 13-kilometres (8-miles) off the UK Sussex coast at its nearest point. The Company’s total investment in the project through construction is expected to be approximately $750 million (£370 million). The Rampion project was developed and is being constructed by E.ON Climate & Renewables UK Limited, a subsidiary of E.ON SE (E.ON). Construction of the wind farm began in September 2015 and it is expected to be fully operational in 2018. The Rampion project is backed by revenues from the UK’s fixed price Renewable Obligation certificates program and a 15-year power purchase agreement. Under the terms of the purchase agreement, Enbridge became one of the three shareholders in Rampion Offshore Wind Limited which owns the Rampion project with the UK Green Investment Bank plc holding a 25% interest and E.ON retaining the balance of 50.1% interest. Enbridge’s portion of the costs incurred to date is approximately $345 million (£195 million) presented in Long-term investments.

Southern Access Extension Project

On July 1, 2014, under an agreement with an unrelated third party, the Company sold a 35% equity interest in the Southern Access Extension Project (the Project). Prior to this sale, the subsidiary executing the Project was wholly-owned and consolidated within the Liquids Pipelines segment. The Company concluded that under the agreement, the purchaser of the 35% equity interest is entitled to substantive participating rights; however, the Company continues to exercise significant influence. As a result, effective July 1, 2014, the Company discontinued consolidation of the Project and recognized its remaining 65% equity interest as a long-term equity investment within the Liquids Pipelines segment.

12.   RESTRICTED LONG-TERM INVESTMENTS

Effective January 1, 2015, the Company began collecting and setting aside funds to cover future pipeline abandonment costs for all NEB regulated pipelines as a result of the NEB’s regulatory requirements under LMCI. The funds collected are held in trusts in accordance with the NEB decision. The funds collected from shippers are reported within Transportation and other services revenues on the Consolidated Statements of Earnings and Restricted long-term investments on the Consolidated Statements of Financial Position. Concurrently, the Company reflects the future abandonment cost as an increase to Operating and administrative expense on the Consolidated Statements of Earnings and Other long-term liabilities on the Consolidated Statements of Financial Position.

As at December 31, 2016, the Company had restricted long-term investments held in trust, invested in Canadian Treasury bonds, and are classified as held for sale and carried at fair value of $90 million (2015 - $49 million). As at December 31, 2016, the Company had estimated future abandonment costs of $97 million (2015 - $48 million) related to LMCI.

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13.   DEFERRED AMOUNTS AND OTHER ASSETS

December 31,	2016	2015
(millions of Canadian dollars)
Regulatory assets	1,921	1,661
Long-term portion of derivative assets (Note 24)	151	373
Affiliate long-term notes receivable	270	152
Contractual receivables	441	432
Deferred financing costs	51	52
Other	279	490
	3,113	3,160

As at December 31, 2016, deferred amounts of $150 million (2015 - $141 million) were subject to amortization and are presented net of accumulated amortization of $94 million (2015 - $80 million). Amortization expense for the year ended December 31, 2016 was $20 million (2015 - $18 million; 2014 - $22 million).

14.   INTANGIBLE ASSETS

	Weighted Average		Accumulated
December 31, 2016	Amortization Rate	Cost	Amortization	Net
(millions of Canadian dollars)
Software	11.8%	1,388	607	781
Natural gas supply opportunities	3.2%	435	127	308
Power purchase agreements	3.2%	100	14	86
Customer relationships	3.0%	251	4	247
Land leases, permits and other	4.8%	213	62	151
		2,387	814	1,573

	Weighted Average		Accumulated
December 31, 2015	Amortization Rate	Cost	Amortization	Net
(millions of Canadian dollars)
Software	11.6%	1,295	516	779
Natural gas supply opportunities	4.0%	484	122	362
Power purchase agreements	3.8%	94	11	83
Land leases, permits and other	4.2%	163	39	124
		2,036	688	1,348

Total amortization expense for intangible assets was $177 million (2015 - $158 million; 2014 - $106 million) for the year ended December 31, 2016. The Company expects amortization expense for intangible assets for the years ending December 31, 2017 through 2021 of $198 million, $178 million, $159 million, $143 million and $129 million, respectively.

15.   GOODWILL

				Gas		Green
				Pipelines		Power
	Liquids		Gas	and		and	Energy	Eliminations
	Pipelines		Distribution	Processing		Transmission	Services	and Other	Consolidated
(millions of Canadian dollars)
Balance at January 1, 2015	55		-	428		-	-	-	483
Foreign exchange and other	5		-	30		-	2	-	37
Impairment	-		-	(440	)	-	-	-	(440	)
Balance at December 31, 2015	60		-	18		-	2	-	80
Foreign exchange and other	(1	)	-	(1	)	-	-	-	(2	)
Balance at December 31, 2016	59		-	17		-	2	-	78

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IMPAIRMENT

The Company did not recognize any goodwill impairment for the year ended December 31, 2016.

Gas Pipelines And Processing

During the year ended December 31, 2015, the Company recorded an impairment charge of $440 million ($167 million after-tax attributable to Enbridge) related to EEP’s natural gas and NGL businesses, which EEP holds directly and indirectly through its partially-owned subsidiary, MEP. Due to a prolonged decline in commodity prices, reduction in producers’ expected drilling programs negatively impacted forecasted cash flows from EEP’s natural gas and NGL systems. This change in circumstance led to the completion of an impairment test, resulting in a full impairment of goodwill on EEP’s natural gas and NGL businesses.

In performing the impairment assessment, EEP measured the fair value of its reporting units primarily by using a discounted cash flow analysis and it also considered overall market capitalization of its business, cash flow measurement data and other factors. EEP’s estimate of fair value required it to use significant unobservable inputs representative of a Level 3 fair value measurement, including assumptions related to the future performance of its reporting units.

16.   ACCOUNTS PAYABLE AND OTHER

December 31,	2016	2015
(millions of Canadian dollars)
Operating accrued liabilities	3,487	3,028
Trade payables	328	561
Construction payables	587	750
Current derivative liabilities (Note 24)	1,941	1,945
Contractor holdbacks	125	299
Taxes payable	321	376
Security deposits	52	62
Deferred revenue	138	89
Asset retirement obligations (Note 19)	2	9
Other	314	232
	7,295	7,351

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17.   DEBT

	Weighted Average
December 31,	Interest Rate	Maturity	2016		2015
(millions of Canadian dollars)
Enbridge Inc.
United States dollar term notes1	4.1%	2017-2046	5,639		4,221
Medium-term notes	4.2%	2017-2064	4,998		5,698
Fixed-to-floating subordinated term notes2	6.0%	2077	1,007		-
Commercial paper and credit facility draws3			4,672		5,667
Other4			4		7
Enbridge (U.S.) Inc.
Medium-term notes5	5.1%	2020	14		14
Commercial paper and credit facility draws6			126		1,665
Enbridge Energy Partners, L.P.
Senior notes7	6.2%	2018-2045	6,781		7,404
Junior subordinated notes8	8.1%	2067	537		554
Commercial paper and credit facility draws9			2,226		1,988
Enbridge Gas Distribution Inc.
Medium-term notes	4.4%	2017-2050	3,904		3,603
Debentures	9.9%	2024	85		85
Commercial paper and credit facility draws			351		599
Enbridge Income Fund
Medium-term notes	4.2%	2017-2044	2,075		2,405
Commercial paper and credit facility draws			225		-
Enbridge Pipelines (Southern Lights) L.L.C.
Medium-term notes10	4.0%	2040	1,342		1,425
Enbridge Pipelines Inc.
Medium-term notes11	4.5%	2018-2046	4,525		3,725
Debentures	8.2%	2024	200		200
Commercial paper and credit facility draws			1,032		1,346
Other			4		4
Enbridge Southern Lights LP
Medium-term notes	4.0%	2040	323		336
Midcoast Energy Partners, L.P.
Senior notes12	4.1%	2019-2024	537		554
Commercial paper and credit facility draws13			564		678
Other14			(226	)	(198	)
Total debt			40,945		41,980
Current maturities			(4,100	)	(1,990	)
Short-term borrowings15			(351	)	(599	)
Long-term debt			36,494		39,391

1	2016 - US$4,200 million (2015 - US$3,050 million).
2	2016 - US$750 million (2015 - nil).
3	2016 - $3,600 million and US$799 million (2015 - $4,168 million and US$1,084 million).
4	Primarily capital lease obligations.
5	2016 - US$10 million (2015 - US$10 million).
6	2016 - US$94 million (2015 - US$1,203 million).
7	2016 - US$5,050 million (2015 - US$5,350 million).
8	2016 - US$400 million (2015 - US$400 million).
9	2016 - US$1,658 million (2015 - US$1,436 million).
10	2016 - US$1,000 million (2015 - US$1,030 million).
11	Included in medium-term notes is $100 million with a maturity date of 2112.
12	2016 - US$400 million (2015 - US$400 million).
13	2016 - US$420 million (2015 - US$490 million).
14	Primarily debt discount and debt issue costs.
15	Weighted average interest rate - 0.8% (2015 - 0.8%).

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For the years ending December 31, 2017 through 2021, debenture, term note and non-revolving credit facility maturities are $4,100 million, $1,172 million, $3,111 million, $2,797 million, $1,917 million respectively, and $21,618 million thereafter. The Company’s debentures and term notes bear interest at fixed rates and interest obligations for the years ending December 31, 2017 through 2021 are $1,776 million, $1,645 million, $1,455 million, $1,259 million and $1,135 million, respectively. At December 31, 2016 and 2015, all debt was unsecured.

INTEREST EXPENSE

Year ended December 31,	2016		2015		2014
(millions of Canadian dollars)
Debentures and term notes	1,714		1,805		1,425
Commercial paper and credit facility draws	197		172		71
Southern Lights project financing	-		-		49
Capitalized	(321	)	(353	)	(416	)
	1,590		1,624		1,129

INTEREST EXPENSE

Year ended December 31,	2016		2015		2014
(millions of Canadian dollars)
Enbridge Inc.	571		970		598
Enbridge (U.S.) Inc.	43		54		19
Enbridge Energy Partners, L.P.	609		369		458
Enbridge Gas Distribution Inc.	193		175		154
Enbridge Income Fund	119		106		76
Enbridge Pipelines (Southern Lights) L.L.C.	56		45		36
Enbridge Pipelines Inc.	262		210		171
Enbridge Southern Lights LP	14		14		14
Midcoast Energy Partners, L.P.	44		34		19
Capitalized	(321	)	(353	)	(416	)
	1,590		1,624		1,129

CREDIT FACILITIES

The following table provides details of the Company’s committed credit facilities at December 31, 2016 and December 31, 2015.

		2016			2015
		Total			Total
December 31,	Maturity	Facilities	Draws1	Available	Facilities
(millions of Canadian dollars)
Enbridge Inc.	2017-2020	8,183	4,700	3,483	6,988
Enbridge (U.S.) Inc.	2018-2019	3,934	126	3,808	4,470
Enbridge Energy Partners, L.P.	2018-2020	3,525	2,293	1,232	3,598
Enbridge Gas Distribution Inc.	2018-2019	1,017	360	657	1,010
Enbridge Income Fund	2019	1,500	236	1,264	1,500
Enbridge Pipelines (Southern Lights) L.L.C.	2018	27	-	27	28
Enbridge Pipelines Inc.	2018	3,000	1,032	1,968	3,000
Enbridge Southern Lights LP	2018	5	-	5	5
Midcoast Energy Partners, L.P.	2018	900	564	336	1,121
Total committed credit facilities		22,091	9,311	12,780	21,720

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

In addition to the committed credit facilities noted above, the Company also has $335 million (2015 - $349 million) of uncommitted demand credit facilities, of which $177 million (2015 - $185 million) were unutilized as at December 31, 2015.

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 2017 to 2020.

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As at December 31, 2016, commercial paper and credit facility draws, net of short-term borrowings and non-revolving credit facilities that mature within one year, of $7,344 million (2015 - $11,344 million) are supported by the availability of long-term committed credit facilities and therefore have been classified as long-term debt.

The Company’s credit facility agreements include standard events of default and covenant provisions whereby accelerated repayment may be required if the Company were to default on payment or violate certain covenants. As at December 31, 2016, the Company was in compliance with all debt covenants.

18.   OTHER LONG-TERM LIABILITIES

December 31,	2016	2015
(millions of Canadian dollars)
Regulatory liabilities	793	787
Derivative liabilities (Note 24)	2,713	3,950
Pension and OPEB liabilities (Note 26)	597	517
Asset retirement obligations (Note 19)	230	189
Environmental liabilities	76	89
Other	572	524
	4,981	6,056

19.   ASSET RETIREMENT OBLIGATIONS

The liability for the expected cash flows as recognized in the financial statements reflected discount rates ranging from 1.7% to 11.0% (2015 - 1.7% to 9.4%). A reconciliation of movements in the Company’s ARO is as follows:

December 31,	2016		2015
(millions of Canadian dollars)
Obligations at beginning of year	198		185
Liabilities incurred	2		2
Liabilities settled	(33	)	(45	)
Change in estimate	63		30
Foreign currency translation adjustment	(5	)	21
Accretion expense	7		5
Obligations at end of year	232		198
Presented as follows:
Accounts payable and other (Note 16)	2		9
Other long-term liabilities (Note 18)	230		189
	232		198

In 2014, the Company recognized ARO in the amount of $177 million. Of this amount, $74 million related to the decommissioning of certain portions of Line 6B of EEP’s Lakehead System and $103 million related to the Canadian and United States portions of the Line 3 Replacement Program, which is targeted to be completed in 2019, whereby the Company will replace the existing Line 3 pipeline in Canada and the United States.

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20.   NONCONTROLLING INTERESTS

December 31,	2016		2015
(millions of Canadian dollars)
Enbridge Energy Partners, L.P.	(99	)	412
Enbridge Energy Management, L.L.C. (EEM)	36		203
Enbridge Gas Distribution Inc. preferred shares	100		100
Renewable energy assets	516		561
Other	24		24
	577		1,300

ENBRIDGE ENERGY PARTNERS, L.P.

Noncontrolling interests in EEP represented the 80.2% (2015 - 80.0%) interest in EEP held by public unitholders, as well as interests of third parties in subsidiaries of EEP, including MEP. The net decrease in the carrying value of Noncontrolling interests in EEP was primarily due to EEP distributing $670 million (2015 - $630 million; 2014 - $504 million) to its noncontrolling interest holders in line with EEP’s objective to make quarterly distributions from its available cash, as defined in its partnership agreement and as approved by EEP’s Board of Directors. This decrease was partially offset by comprehensive income attributable to noncontrolling interests in EEP during the year.

For the year ended December 31, 2016, EEP reported a net loss, as well as distributions to partners in excess of earnings attributable to partners, which reduced the carrying value of EEP’s Class A and Class B common units and i-units into deficit positions. The EEP partnership agreement does not permit capital account deficits in the capital account of any limited partner and thus requires that such capital account deficits be brought to zero by additional allocations from other limited partner capital balances, to the extent such capital account balances are positive, and the General Partner on a pro-rata basis. As a result, Earnings attributable to noncontrolling interests and redeemable noncontrolling interests in the Consolidated Statements of Earnings for the year ended December 31, 2016 were higher by $816 million due to this reallocation (2015 - lower by $13 million).

On January 2, 2015, Enbridge transferred its 66.7% interest in the United States segment of the Alberta Clipper pipeline, held through a wholly-owned Enbridge subsidiary in the United States, to EEP for aggregate consideration of $1.1 billion (US$1 billion), consisting of approximately $814 million (US$694 million) of Class E equity units issued to Enbridge by EEP and the repayment of approximately $359 million (US$306 million) of indebtedness owed to Enbridge. Prior to the transfer, EEP owned the remaining 33.3% interest in the United States segment of the Alberta Clipper pipeline.

The Class E units issued to Enbridge are entitled to the same distributions as the Class A units held by the public and are convertible into Class A units on a one-for-one basis at Enbridge’s option. The transaction applies to all distributions declared subsequent to the transfer. The Class E units are redeemable at EEP’s option after 30 years, if not converted by Enbridge prior to that time. The units have a liquidation preference equal to their notional value at December 23, 2014 of US$38.31 per unit, which was determined based on the trailing five-day volume-weighted average price of EEP’s Class A common units. EEP recorded the Class E units at fair value. As a result, the Company recorded a decrease in Noncontrolling interests of $304 million and increases in Additional paid-in capital and Deferred income tax liabilities of $218 million and $86 million, respectively.

On March 13, 2015, EEP completed a public common unit issuance. The Company participated only to the extent to maintain its 2% General Partner (GP) interest. The common unit issuance resulted in contributions of $366 million (US$289 million) from noncontrolling interest holders.

42

Effective July 1, 2014, EECI, a wholly-owned subsidiary of Enbridge and the GP of EEP, entered into an equity restructuring transaction in which the Company irrevocably waived its right to receive cash distributions and allocations in excess of 2% in respect of its GP interest in the existing incentive distribution rights (IDR) in exchange for the issuance of (i) 66.1 million units of a new class of EEP units designated as Class D Units, and (ii) 1,000 units of a new class of EEP units designated as Incentive Distribution Units (IDU). The Class D Units entitle the Company to receive quarterly distributions equal to the distribution paid on EEP’s common units. This restructuring decreased the Company’s share of incremental cash distributions from 48% of all distributions in excess of US$0.495 per unit per quarter down to 23% of all distributions in excess of EEP’s current quarterly distribution of US$0.5435 per unit per quarter. The transaction applies to all distributions declared subsequent to the effective date. EEP recorded the Class D Units and IDU at fair value, which resulted in a reduction to the carrying amounts of the GP and limited partner capital accounts on a pro-rata basis. As a result, the Company recorded a decrease in Noncontrolling interests of $2,363 million inclusive of CTA and increases in Additional paid-in capital and Deferred income tax liabilities of $1,601 million and $762 million, respectively.

On July 1, 2014, EEP completed the sale of an additional 12.6% limited partnership interest in its natural gas and NGL midstream business to MEP for cash proceeds of $376 million (US$350 million). Upon finalization of this transaction, EEP continued to retain a 2% GP interest, an approximate 52% limited partner interest and all IDR in MEP. However, EEP’s direct interest in entities or partnerships holding the natural gas and NGL midstream operations reduced from 61% to 48%, with the remaining ownership held by MEP.

ENBRIDGE ENERGY MANAGEMENT, L.L.C.

Noncontrolling interests in EEM represented the 88.3% (2015 - 88.3%) of the listed shares of EEM not held by the Company. During the year ended December 31, 2016, the decrease in the carrying value of Noncontrolling interests in EEM is due to a comprehensive loss attributable to noncontrolling interests in EEM.

ENBRIDGE GAS DISTRIBUTION INC.

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 its option, redeem all or a portion of the outstanding shares for $25 per share plus all accrued and unpaid dividends to the redemption date. As at December 31, 2016, no preferred shares have been redeemed.

RENEWABLE ENERGY ASSETS

Renewable energy assets include the VIEs (Note 10) of Magic Valley, Wildcat, Keechi and New Creek wind farms. During the year ended December 31, 2016, the net decrease in the carrying value of Noncontrolling interests in Renewable energy assets was primarily due to a comprehensive loss attributable to noncontrolling interests, which were partially offset by contributions, net of distributions, received from noncontrolling interests.

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REDEEMABLE NONCONTROLLING INTERESTS

Year ended December 31,	2016		2015		2014
(millions of Canadian dollars)
Balance at beginning of year	2,141		2,249		1,053
Earnings/(loss)	268		(3	)	(11	)
Other comprehensive income/(loss), net of tax
Change in unrealized gains/(loss) on cash flow hedges	(17	)	(7	)	(15	)
Other comprehensive loss from equity investees	-		(12	)	-
Reclassification to earnings of realized cash flow hedges	3		2		-
Reclassification to earnings of unrealized cash flow hedges	6		2		-
Change in foreign currency translation adjustment	(3	)	18		5
Other comprehensive income/(loss)	(11	)	3		(10	)
Distributions to unitholders	(202	)	(114	)	(79	)
Contributions from unitholders	591		670		323
Reversal of cumulative redemption value adjustment attributable to ECT preferred units	-		(541	)	-
Dilution loss on Enbridge Income Fund issuance of trust units	(4	)	(355	)	-
Dilution loss on Enbridge Income Fund equity investment	(73	)	(132	)	-
Dilution gain/(loss) on Enbridge Income Fund indirect equity investment	(4	)	5		-
Redemption value adjustment	686		359		973
Balance at end of year	3,392		2,141		2,249

Redeemable noncontrolling interests in the Fund as at December 31, 2016 represented 45.6% (2015 - 40.7%, 2014 - 70.6%) of interests in the Fund’s trust units that are held by third parties.

In April 2016, ENF completed a public equity offering of common shares for gross proceeds of $575 million and issued additional shares to Enbridge for gross proceeds of $143 million in order for Enbridge to maintain its 19.9% ownership interest in ENF. ENF used the proceeds from the common share issuances to subscribe for additional trust units of the Fund. Enbridge did not participate in this offering, resulting in an increase in redeemable noncontrolling interests from 40.7% to 45.6%. This resulted in contributions of $591 million, net of share issue costs, from redeemable noncontrolling interest holders and a dilution loss for redeemable noncontrolling interests of $4 million.

In April 2016, the Fund used the aggregate proceeds of $718 million from the issuance of trust units to ENF to purchase additional common units of ECT, and ECT used the aggregate proceeds of $718 million to purchase additional Class A units of EIPLP, resulting in a dilution loss for ECT. This dilution loss resulted in a dilution loss for the Fund’s equity investment in ECT and a dilution loss for redeemable noncontrolling interests of $73 million for the year ended December 31, 2016.

In September 2015, Enbridge’s unitholdings in the Fund increased upon closing of the Canadian Restructuring Plan (Note 1), resulting in a decrease in redeemable noncontrolling interests.

Upon closing of the Canadian Restructuring Plan, ECT, an equity investment of the Fund, reclassified its Preferred Units from mezzanine equity to liabilities. Accordingly, ECT reduced the recorded redemption value of its Preferred Units to their aggregate par value, resulting in an increase to the Fund’s equity investment in ECT. This resulted in an adjustment to redeemable noncontrolling interests of approximately $541 million.

Upon closing of the Canadian Restructuring Plan, EIPLP, an indirect equity investment of the Fund, issued Special Interest Rights to Enbridge which are entitled to Temporary Performance Distribution Rights (TPDR) distributions. TPDR distributions occur when the Fund distribution rate exceeds a payout target and are paid in the form of Class D units. The Class D unitholders receive a distribution each month equal to the per unit amount paid on Class C units of EIPLP, but to be paid in kind in additional Class D units. The issuances of TPDR and additional Class D units resulted in a dilution gain for the Fund’s indirect equity investment in EIPLP. For the year ended December 31, 2016, a dilution loss for redeemable noncontrolling interests of $4 million was recorded (2015 - dilution gain of $5 million).

44

In November 2015, ENF completed a bought deal public offering of common shares for approximately $700 million and issued additional common shares to Enbridge for approximately $174 million in order for Enbridge to maintain its 19.9% in ENF. ENF used the aggregate proceeds of $874 million to subscribe for additional trust units of the Fund. Enbridge did not participate in this offering, resulting in an increase in redeemable noncontrolling interests from 34.3% to 40.7%. This resulted in contributions of $670 million, net of share issue costs, from redeemable noncontrolling interest holders and a dilution loss for redeemable noncontrolling interests of $355 million for the year ended December 31, 2015.

In November 2015, the Fund used the aggregate proceeds of $874 million from the issuance of trust units to ENF to purchase additional common units of ECT, and ECT used the aggregate proceeds of $874 million to purchase additional Class A units of EIPLP, resulting in a dilution loss for ECT. This dilution loss resulted in a dilution loss for Fund’s equity investment in ECT and a dilution loss for redeemable noncontrolling interests of $132 million for the year ended December 31, 2015.

In November 2014, the Fund Group acquired Enbridge’s 50% interest in the United States portion of Alliance Pipeline and subscribed for and purchased Class A units of Enbridge’s subsidiaries that indirectly own the Canadian and United States segments of the Southern Lights Pipeline for a total consideration of approximately $1.8 billion, including $421 million in cash, $878 million in the form of a long-term note payable by the Fund, bearing interest of 5.5% per annum and was fully repaid at December 31, 2015, and $461 million in the form of preferred units of ECT, which at the time of the transfer was a subsidiary of the Fund. To fund the cash component of the consideration, the Fund issued approximately $421 million of trust units to ENF. To purchase the trust units from the Fund, ENF completed a bought deal public offering of common shares for approximately $337 million and issued additional common shares to Enbridge for approximately $84 million in order for Enbridge to maintain its 19.9% interest in ENF. As a result of the transfer, redeemable noncontrolling interests in the Fund increased from 68.6% to 70.6% and contributions of $323 million, net of share issue costs, were received from redeemable noncontrolling interest holders.

Distributions to noncontrolling unitholders were made on a monthly basis for the years ended December 31, 2016, 2015, and 2014 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.

21.   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

	2016		2015		2014
	Number		Number		Number
December 31,	of Shares	Amount	of Shares	Amount	of Shares	Amount
(millions of Canadian dollars; number of common shares in millions)
Balance at beginning of year	868	7,391	852	6,669	831	5,744
Common shares issued1	56	2,241	-	-	9	446
Dividend Reinvestment and Share Purchase Plan (DRIP)	16	795	12	646	9	428
Shares issued on exercise of stock options	3	65	4	76	3	51
Balance at end of year	943	10,492	868	7,391	852	6,669

1Gross proceeds - $2,300 million (2015 - nil; 2014 - $460 million); net issuance costs - $59 million (2015 - nil; 2014 - $14 million).

45

PREFERENCE SHARES

	2016		2015		2014
	Number		Number		Number
December 31,	of Shares	Amount	of Shares	Amount	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	20	500
Preference Shares, Series D	18	450	18	450	18	450
Preference Shares, Series F	20	500	20	500	20	500
Preference Shares, Series H	14	350	14	350	14	350
Preference Shares, Series J	8	199	8	199	8	199
Preference Shares, Series L	16	411	16	411	16	411
Preference Shares, Series N	18	450	18	450	18	450
Preference Shares, Series P	16	400	16	400	16	400
Preference Shares, Series R	16	400	16	400	16	400
Preference Shares, Series 1	16	411	16	411	16	411
Preference Shares, Series 3	24	600	24	600	24	600
Preference Shares, Series 5	8	206	8	206	8	206
Preference Shares, Series 7	10	250	10	250	10	250
Preference Shares, Series 9	11	275	11	275	11	275
Preference Shares, Series 11	20	500	20	500	20	500
Preference Shares, Series 13	14	350	14	350	14	350
Preference Shares, Series 15	11	275	11	275	11	275
Preference Shares, Series 17	30	750	-	-	-	-
Issuance costs		(147)		(137)		(137)
Balance at end of year		7,255		6,515		6,515

46

Characteristics of the preference shares are as follows:

			Per Share Base	Redemption and	Right to
	Initial		Redemption	Conversion	Convert
	Yield	Dividend1	Value2	Option Date2,3	Into3,4
(Canadian dollars unless otherwise stated)
Preference Shares, Series A	5.50%	$1.375	$25	-	-
Preference Shares, Series B	4.00%	$1.000	$25	June 1, 2017	Series C
Preference Shares, Series D	4.00%	$1.000	$25	March 1, 2018	Series E
Preference Shares, Series F	4.00%	$1.000	$25	June 1, 2018	Series G
Preference Shares, Series H	4.00%	$1.000	$25	September 1, 2018	Series I
Preference Shares, Series J	4.00%	US$1.000	US$25	June 1, 2017	Series K
Preference Shares, Series L	4.00%	US$1.000	US$25	September 1, 2017	Series M
Preference Shares, Series N	4.00%	$1.000	$25	December 1, 2018	Series O
Preference Shares, Series P	4.00%	$1.000	$25	March 1, 2019	Series Q
Preference Shares, Series R	4.00%	$1.000	$25	June 1, 2019	Series S
Preference Shares, Series 1	4.00%	US$1.000	US$25	June 1, 2018	Series 2
Preference Shares, Series 3	4.00%	$1.000	$25	September 1, 2019	Series 4
Preference Shares, Series 5	4.40%	US$1.100	US$25	March 1, 2019	Series 6
Preference Shares, Series 7	4.40%	$1.100	$25	March 1, 2019	Series 8
Preference Shares, Series 9	4.40%	$1.100	$25	December 1, 2019	Series 10
Preference Shares, Series 11	4.40%	$1.100	$25	March 1, 2020	Series 12
Preference Shares, Series 13	4.40%	$1.100	$25	June 1, 2020	Series 14
Preference Shares, Series 15	4.40%	$1.100	$25	September 1, 2020	Series 16
Preference Shares, Series 17	5.15%	$1.288	$25	March 1, 2022	Series 18

1	The holder is entitled to receive a fixed, cumulative, quarterly preferential dividend, as declared by the Board. With the exception of Series A Preference Shares, such fixed dividend rate resets every five years beginning on the initial redemption and conversion option date. The Series 17 Preference Shares contain a feature where the fixed dividend rate, when reset every five years, will not be less than 5.15%. No other series of Preference Shares has this feature.
2	Preference 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.
3	The holder will have the right, subject to certain conditions, to convert their shares into Cumulative Redeemable Preference Shares of a specified series on a one-for-one basis on the Conversion Option Date and every fifth anniversary thereafter at an ascribed issue price equal to the Base Redemption Value.
4	With the exception of Series A Preference Shares, after the redemption and conversion option dates, holders may elect 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), 2.5% (Series S), 2.4% (Series 4), 2.6% (Series 8), 2.7% (Series 10), 2.6% (Series 12), 2.7% (Series 14), 2.7% (Series 16), 4.1% (Series 18); or US$25 x (number of days in quarter/365) x (three-month United States Government treasury bill rate + 3.1% (Series K), 3.2% (Series M), 3.1% (Series 2) or 2.8% (Series 6)).

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 common shares outstanding has been reduced by the Company’s pro-rata weighted average interest in its own common shares of 13 million (2015 - 12 million; 2014 - 12 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,	2016	2015	2014
(number of common shares in millions)
Weighted average shares outstanding	911	847	829
Effect of dilutive options	7	-	11
Diluted weighted average shares outstanding	918	847	840

For the year ended December 31, 2016, 10,803,672 anti-dilutive stock options (2015 - 36,005,043; 2014 - 6,058,580) with a weighted average exercise price of $52.92 (2015 - $40.26; 2014 - $48.78) were excluded from the diluted earnings per common share calculation.

47

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.

22.   STOCK OPTION AND STOCK UNIT PLANS

The Company maintains four long-term incentive compensation plans: the ISO Plan, the PSO 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 50 million have been issued to date. A further 71 million common shares have been reserved for issuance for the 2007 ISO and PSO plans, of which 14 million have been exercised and issued from treasury 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 ISO to purchase common shares at the market price on the grant date. ISO vest in equal annual instalments over a four-year period and expire 10 years after the issue date.

December 31, 2016	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	32,788	40.31
Options granted	6,373	44.05
Options exercised1	(5,364)	29.73
Options cancelled or expired	(888)	49.26
Options outstanding at end of year	32,909	42.51	6.3	335
Options vested at end of year2	18,355	37.11	4.9	286

1	The total intrinsic value of ISO exercised during the year ended December 31, 2016 was $123 million (2015 - $126 million; 2014 - $117 million) and cash received on exercise was $37 million (2015 - $43 million; 2014 - $37 million).
2	The total fair value of options vested under the ISO Plan during the year ended December 31, 2016 was $36 million (2015 - $34 million; 2014 - $26 million).

48

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

Year ended December 31,	2016	2015	2014
Fair value per option (Canadian dollars)1	7.37	6.48	5.53
Valuation assumptions
Expected option term (years)2	5	5	5
Expected volatility3	25.1%	19.9%	16.9%
Expected dividend yield4	4.4%	3.2%	2.9%
Risk-free interest rate5	0.8%	0.9%	1.6%

1	Options granted to United States employees are based on New York Stock Exchange prices. The option value and assumptions shown are based on a weighted average of the United States and the Canadian options. The fair values per option were $7.01 (2015 - $6.22; 2014 - $5.45) for Canadian employees and US$6.60 (2015 - US$6.16; 2014 - US$5.35) for United States employees.
2	The expected option term is six years based on historical exercise practice and three years for retirement eligible employees.
3	Expected 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.
4	The expected dividend yield is the current annual dividend at the grant date divided by the current stock price.
5	The risk-free interest rate is based on the Government of Canada’s Canadian Bond Yields and the United States Treasury Bond Yields.

Compensation expense recorded for the year ended December 31, 2016 for ISO was $43 million (2015 - $35 million; 2014 - $29 million). At December 31, 2016, unrecognized compensation cost related to non-vested stock-based compensation arrangements granted under the ISO Plan was $50 million. The cost is expected to be fully recognized over a weighted average period of approximately two years.

PERFORMANCE STOCK OPTIONS

PSO are granted to executive officers and become exercisable when both performance targets and time vesting requirements have been met. PSO were granted on August 15, 2007, February 19, 2008, August 15, 2012 and March 13, 2014 under the 2007 plan. 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. As at December 31, 2016, all performance targets have been met and the options are exercisable until August 15, 2020. Time vesting requirements for the 2014 grant will be fulfilled evenly over a four-year term, ending March 13, 2018. The 2014 grant’s performance targets are based on the Company’s share price and must be met by February 15, 2019 or the options expire. As at December 31, 2016, all performance targets have been met and the options are exercisable until August 15, 2020.

December 31, 2016	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	3,217	39.75
Options exercised1	(335)	41.29
Options outstanding at end of year	2,882	39.57	3.2	38
Options vested at end of year2	2,409	39.34	3.2	32

1	The total intrinsic value of PSO exercised during the year ended December 31, 2016 was $7 million (2015 - $43 million; 2014 - nil) and cash received on exercise was $3 million (2015 - $13 million; 2014 - nil).
2	The total fair value of options vested under the PSO Plan during the year ended December 31, 2016 was $2 million (2015 - $6 million; 2014 - $5 million).

49

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

Year ended December 31,	2014
Fair value per option (Canadian dollars)	5.77
Valuation assumptions
Expected option term (years)1	6.5
Expected volatility2	15.0%
Expected dividend yield3	2.8%
Risk-free interest rate4	1.7%

1	The expected option term is based on historical exercise practice.
2	Expected volatility is determined with reference to historic daily share price volatility.
3	The expected dividend yield is the current annual dividend at the grant date divided by the current stock price.
4	The risk-free interest rate is based on the Government of Canada’s Canadian Bond Yields.

Compensation expense recorded for the year ended December 31, 2016 for PSO was $3 million (2015 - $3 million; 2014 - $3 million). At December 31, 2016, unrecognized compensation cost related to non-vested stock-based compensation arrangements granted under the PSO Plan was $2 million. The cost is expected to be fully recognized over a weighted average period of approximately one year.

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 performance multiplier is derived 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 2016 expense, multipliers of two, were used for each of the 2014, 2015 and 2016 PSU grants.

		Weighted
		Average
		Remaining	Aggregate
		Contractual	Intrinsic
December 31, 2016	Number	Life (Years)	Value
(units in thousands; intrinsic value in millions of Canadian dollars)
Units outstanding at beginning of year	536
Units granted	294
Units cancelled	(14)
Units matured1	(295)
Dividend reinvestment	35
Units outstanding at end of year	556	1.5	54

1 The total amount paid during the year ended December 31, 2016 for PSU was $22 million (2015 - $35 million; 2014 - $36 million).

Compensation expense recorded for the year ended December 31, 2016 for PSU was $33 million (2015 - $12 million; 2014 - $40 million). As at December 31, 2016, unrecognized compensation expense related to non-vested units granted under the PSU Plan was $30 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.

50

		Weighted
		Average
		Remaining	Aggregate
		Contractual	Intrinsic
December 31, 2016	Number	Life (years)	Value
(units in thousands; intrinsic value in millions of Canadian dollars)
Units outstanding at beginning of year	1,906
Units granted	972
Units cancelled	(154)
Units matured1	(992)
Dividend reinvestment	122
Units outstanding at end of year	1,854	1.4	105

1 The total amount paid during the year ended December 31, 2016 for RSU was $56 million (2015 - $45 million; 2014 - $45 million).

Compensation expense recorded for the year ended December 31, 2016 for RSU was $51 million (2015 - $47 million; 2014 - $44 million). As at December 31, 2016, unrecognized compensation expense related to non-vested units granted under the RSU Plan was $62 million and is expected to be fully recognized over a weighted average period of approximately one year.

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

Changes in AOCI attributable to Enbridge common shareholders for the years ended December 31, 2016, 2015 and 2014, are as follows:

					Pension and
		Net	Cumulative		OPEB
	Cash Flow	Investment	Translation	Equity	Amortization
	Hedges	Hedges	Adjustment	Investees	Adjustment	Total
(millions of Canadian dollars)
Balance at January 1, 2016	(688)	(795)	3,365	37	(287)	1,632
Other comprehensive income/(loss) retained in AOCI	(216)	171	(665)	(5)	(45)	(760)
Other comprehensive (income)/loss reclassified to earnings
Interest rate contracts1	147	-	-	-	-	147
Commodity contracts2	(11)	-	-	-	-	(11)
Foreign exchange contracts3	1	-	-	-	-	1
Other contracts4	(18)	-	-	-	-	(18)
Amortization of pension and OPEB actuarial loss prior service costs5	-	-	-	-	21	21
	(97)	171	(665)	(5)	(24)	(620)
Tax impact
Income tax on amounts retained in AOCI	91	(5)	-	5	11	102
Income tax on amounts reclassified to earnings	(52)	-	-	-	(4)	(56)
	39	(5)	-	5	7	46
Balance at December 31, 2016	(746)	(629)	2,700	37	(304)	1,058

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						Pension and
		Net	Cumulative			OPEB
	Cash Flow	Investment	Translation	Equity		Amortization
	Hedges	Hedges	Adjustment	Investees		Adjustment	Total
(millions of Canadian dollars)
Balance at January 1, 2015	(488)	108	309	(5)		(359)	(435)
Other comprehensive income/(loss) retained in AOCI	73	(952)	3,056	47		65	2,289
Other comprehensive (income)/loss reclassified to earnings
Interest rate contracts1	(34)	-	-	-		-	(34)
Commodity contracts2	(11)	-	-	-		-	(11)
Foreign exchange contracts3	7	-	-	-		-	7
Other contracts4	26	-	-	-		-	26
Amortization of pension and OPEB actuarial loss and prior service costs5	-	-	-	-		32	32
Other comprehensive loss reclassified to earnings of derecognized cash flow hedges	(338)	-	-	-		-	(338)
	(277)	(952)	3,056	47		97	1,971
Tax impact
Income tax on amounts retained in AOCI	(29)	49	-	(5	)	(14)	1
Income tax on amounts reclassified to earnings	15	-	-	-		(11)	4
Income tax on amounts reclassified to earnings of derecognized cash flow hedges	91	-	-	-		-	91
	77	49	-	(5)		(25)	96
Balance at December 31, 2015	(688)	(795)	3,365	37		(287)	1,632

					Pension and
		Net	Cumulative		OPEB
	Cash Flow	Investment	Translation	Equity	Amortization
	Hedges	Hedges	Adjustment	Investees	Adjustment	Total
(millions of Canadian dollars)
Balance at January 1, 2014	(1)	378	(778)	(15)	(183)	(599)
Other comprehensive income/(loss) retained in AOCI	(857)	(301)	1,087	10	(265)	(326)
Other comprehensive (income)/loss reclassified to earnings
Interest rate contracts1	201	-	-	-	-	201
Commodity contracts2	(2)	-	-	-	-	(2)
Foreign exchange contracts3	8	-	-	-	-	8
Other contracts4	(23)	-	-	-	-	(23)
Amortization of pension and OPEB actuarial loss and prior service costs5	-	-	-	-	18	18
	(673)	(301)	1,087	10	(247)	(124)
Tax impact
Income tax on amounts retained in AOCI	231	31	-	-	74	336
Income tax on amounts reclassified to earnings	(45)	-	-	-	(3)	(48)
	186	31	-	-	71	288
Balance at December 31, 2014	(488)	108	309	(5)	(359)	(435)

1	Reported within Interest expense in the Consolidated Statements of Earnings.
2	Reported within Commodity costs in the Consolidated Statements of Earnings.
3	Reported within Other income/(expense) in the Consolidated Statements of Earnings.
4	Reported within Operating and administrative expense in the Consolidated Statements of Earnings.
5	These components are included in the computation of net periodic pension costs and are reported within Operating and administrative expense in the Consolidated Statements of Earnings.

24.   RISK MANAGEMENT AND FINANCIAL INSTRUMENTS

MARKET 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 risk). Formal risk management policies, processes and systems have been designed to mitigate these risks.

The following summarizes the types of market 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 generates certain revenues, incurs expenses, and holds a number of investments and subsidiaries that are denominated in currencies other than Canadian dollars. As a result, the Company’s earnings, cash flows and OCI are exposed to fluctuations resulting from foreign exchange rate variability.

The Company has implemented a policy whereby, at a minimum, it hedges a level of foreign currency denominated earnings exposures over a five year forecast horizon. A combination of qualifying and non-qualifying derivative instruments is used to hedge anticipated foreign currency denominated revenues and expenses, and to manage variability in cash flows. The Company hedges certain net investments in United States dollar denominated investments and subsidiaries using foreign currency derivatives and United States dollar denominated debt.

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 via execution of floating to fixed interest rate swaps with an average swap rate of 2.4%.

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 via execution of floating to fixed interest rate swaps with an average swap rate of 3.7%.

The Company also monitors its debt portfolio mix of fixed and variable rate debt instruments to maintain a consolidated portfolio of debt within its Board of Directors approved policy limit of a maximum of 25% floating rate debt as a percentage of total debt outstanding. The Company primarily uses 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 its 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, RSU. The Company uses a combination of qualifying and non-qualifying derivative instruments to manage equity price risk.

TOTAL DERIVATIVE INSTRUMENTS

The following table summarizes the Consolidated Statements of Financial Position location and carrying value of the Company’s derivative instruments. The Company did not have any outstanding fair value hedges as at December 31, 2016 or 2015.

The Company generally has a policy of entering into individual International Swaps and Derivatives Association, Inc. (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 the counterparties in these particular circumstances. The following table also summarizes the maximum potential settlement amount in the event of these specific circumstances. All amounts are presented gross in the Consolidated Statements of Financial Position.

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	Derivative		Derivative
	Instruments		Instruments		Non-		Total Gross
	Used as		Used as Net		Qualifying		Derivative		Amounts		Total Net
	Cash Flow		Investment		Derivative		Instruments		Available		Derivative
December 31, 2016	Hedges		Hedges		Instruments		as Presented		for Offset		Instruments
(millions of Canadian dollars)
Accounts receivable and other (Note 7)
Foreign exchange contracts	101		3		5		109		(103	)	6
Interest rate contracts	3		-		-		3		(3	)	-
Commodity contracts	9		-		232		241		(125	)	116
	113		3		237		353		(231	)	122
Deferred amounts and other assets (Note 13)
Foreign exchange contracts	1		3		69		73		(72	)	1
Interest rate contracts	8		-		-		8		(6	)	2
Commodity contracts	7		-		61		68		(22	)	46
Other contracts	1		-		1		2		-		2
	17		3		131		151		(100	)	51
Accounts payable and other (Note 16)
Foreign exchange contracts	-		(268	)	(727	)	(995	)	103		(892	)
Interest rate contracts	(452	)	-		(131	)	(583	)	3		(580	)
Commodity contracts	-		-		(359	)	(359	)	125		(234	)
Other contracts	(1	)	-		(3	)	(4	)	-		(4	)
	(453	)	(268	)	(1,220	)	(1,941	)	231		(1,710	)
Other long-term liabilities (Note 18)
Foreign exchange contracts	-		(68	)	(1,961	)	(2,029	)	72		(1,957	)
Interest rate contracts	(268	)	-		(205	)	(473	)	6		(467	)
Commodity contracts	-		-		(211	)	(211	)	22		(189	)
	(268	)	(68	)	(2,377	)	(2,713	)	100		(2,613	)
Total net derivative asset/(liability)
Foreign exchange contracts	102		(330	)	(2,614	)	(2,842	)	-		(2,842	)
Interest rate contracts	(709	)	-		(336	)	(1,045	)	-		(1,045	)
Commodity contracts	16		-		(277	)	(261	)	-		(261	)
Other contracts	-		-		(2	)	(2	)	-		(2	)
	(591	)	(330	)	(3,229	)	(4,150	)	-		(4,150	)

54

	Derivative		Derivative
	Instruments		Instruments		Non-		Total Gross
	Used as		Used as Net		Qualifying		Derivative		Amounts		Total Net
	Cash Flow		Investment		Derivative		Instruments		Available		Derivative
December 31, 2015	Hedges		Hedges		Instruments		as Presented		for Offset		Instruments
(millions of Canadian dollars)
Accounts receivable and other (Note 7)
Foreign exchange contracts	6		2		2		10		(3	)	7
Interest rate contracts	2		-		-		2		(2	)	-
Commodity contracts	7		-		772		779		(211	)	568
	15		2		774		791		(216	)	575
Deferred amounts and other assets (Note 13)
Foreign exchange contracts	114		4		10		128		(127	)	1
Interest rate contracts	18		-		-		18		(14	)	4
Commodity contracts	7		-		220		227		(77	)	150
	139		4		230		373		(218	)	155
Accounts payable and other (Note 16)
Foreign exchange contracts	(1	)	(106	)	(765	)	(872	)	3		(869	)
Interest rate contracts	(379	)	-		(185	)	(564	)	2		(562	)
Commodity contracts	-		-		(501	)	(501	)	194		(307	)
Other contracts	(2	)	-		(6	)	(8	)	-		(8	)
	(382	)	(106	)	(1,457	)	(1,945	)	199		(1,746	)
Other long-term liabilities (Note 18)
Foreign exchange contracts	-		(252	)	(2,796	)	(3,048	)	127		(2,921	)
Interest rate contracts	(405	)	-		(224	)	(629	)	14		(615	)
Commodity contracts	-		-		(260	)	(260	)	77		(183	)
Other contracts	(8	)	-		(5	)	(13	)	-		(13	)
	(413	)	(252	)	(3,285	)	(3,950	)	218		(3,732	)
Total net derivative asset/(liability)
Foreign exchange contracts	119		(352	)	(3,549	)	(3,782	)	-		(3,782	)
Interest rate contracts	(764	)	-		(409	)	(1,173	)	-		(1,173	)
Commodity contracts	14		-		231		245		(17	)1	228
Other contracts	(10	)	-		(11	)	(21	)	-		(21	)
	(641	)	(352	)	(3,738	)	(4,731	)	(17	)	(4,748	)

1Amount available for offset includes $17 million of cash collateral.

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

December 31, 2016	2017		2018		2019		2020		2021		Thereafter
Foreign exchange contracts - United States dollar forwards - purchase (millions of United States dollars)	991		2		2		2		-		-
Foreign exchange contracts - United States dollar forwards - sell (millions of United States dollars)	4,369		2,768		2,943		2,722		566		223
Foreign exchange contracts - GBP forwards - purchase (millions of GBP)	91		6		-		-		-		-
Foreign exchange contracts - GBP forwards - sell (millions of GBP)	-		-		89		25		27		144
Foreign exchange contracts - Japanese yen forwards - purchase (millions of yen)	-		-		32,662		-		-		-
Interest rate contracts - short-term borrowings (millions of Canadian dollars)	6,713		5,161		1,581		153		100		300
Interest rate contracts - long-term debt (millions of Canadian dollars)	3,998		2,743		768		-		-		-
Equity contracts (millions of Canadian dollars)	48		40		-		-		-		-
Commodity contracts - natural gas (billions of cubic feet)	(93	)	(42	)	(17	)	(9	)	-		-
Commodity contracts - crude oil (millions of barrels)	(11	)	(9	)	-		-		-		-
Commodity contracts - NGL (millions of barrels)	(8	)	(6	)	-		-		-		-
Commodity contracts - power (megawatt hours (MWH))	40		30		31		35		(3	)	(43	)

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December 31, 2015	2016		2017		2018		2019	2020	Thereafter
Foreign exchange contracts - United States dollar forwards - purchase (millions of United States dollars)	172		413		2		2	2	-
Foreign exchange contracts - United States dollar forwards - sell (millions of United States dollars)	3,059		3,213		3,133		2,630	2,303	787
Foreign exchange contracts - GBP forwards - purchase (millions of GBP)	70		77		6		-	-	-
Foreign exchange contracts - GBP forwards - sell (millions of GBP)	-		-		-		89	25	144
Interest rate contracts - short-term borrowings (millions of Canadian dollars)	8,382		7,604		4,536		1,574	156	406
Interest rate contracts - long-term debt (millions of Canadian dollars)	4,291		3,371		1,960		773	-	-
Equity contracts (millions of Canadian dollars)	51		48		-		-	-	-
Commodity contracts - natural gas (billions of cubic feet)	(126	)	(209	)	(17	)	2	1	-
Commodity contracts - crude oil (millions of barrels)	(6	)	(17	)	(9	)	-	-	-
Commodity contracts - NGL (millions of barrels)	(5	)	1		-		-	-	-
Commodity contracts - power (megawatt hours)	40		40		30		31	35	(35	)

The Effect of Derivative Instruments on the Consolidated 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.

	2016		2015		2014
(millions of Canadian dollars)
Amount of unrealized gains/(loss) recognized in OCI
Cash flow hedges
Foreign exchange contracts	(19	)	77		8
Interest rate contracts	(90	)	(275	)	(1,086	)
Commodity contracts	14		9		50
Other contracts	39		(47	)	13
Net investment hedges
Foreign exchange contracts	22		(248	)	(113	)
	(34	)	(484	)	(1,128	)
Amount of (gains)/loss reclassified from AOCI to earnings (effective portion)
Foreign exchange contracts1	2		9		8
Interest rate contracts2	145		128		101
Commodity contracts3	(12	)	(46	)	4
Other contracts4	(29	)	28		(7	)
	106		119		106
De-designation of qualifying hedges in connection with the Canadian Restructuring Plan
Interest rate contracts 2	-		338		-
	-		338		-
Amount of (gains)/loss reclassified from AOCI to earnings (ineffective portion and amount excluded from effectiveness testing)
Interest rate contracts2	61		21		216
Commodity contracts3	-		5		(6	)
	61		26		210

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

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

3Reported within Transportation and other services revenues, Commodity sales 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.

The Company estimates that a gain of $23 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 36 months as at December 31, 2016.

56

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,	2016		2015		2014
(millions of Canadian dollars)
Foreign exchange contracts1	935		(2,187	)	(936	)
Interest rate contracts2	73		(363	)	4
Commodity contracts3	(508	)	199		1,031
Other contracts4	9		(22	)	7
Total unrealized derivative fair value gain/(loss), net	509		(2,373	)	106

1Reported within Transportation and other services revenues (2016 - $497 million gain; 2015 - $1,383 million loss; 2014 - $496 million loss) and Other income/(expense) (2016 - $438 million gain; 2015 - $804 million loss; 2014 - $440 million loss) in the Consolidated Statements of Earnings.

2Reported as an (increase)/decrease within Interest expense in the Consolidated Statements of Earnings.

3Reported within Transportation and other services revenues (2016 - $52 million loss; 2015 - $328 million gain; 2014 - $741 million gain), Commodity sales (2016 - $474 million loss; 2015 - $226 million loss; 2014 - nil), Commodity costs (2016 - $38 million gain; 2015 - $99 million gain; 2014 - $303 million gain) and Operating and administrative expense (2016 - $20 million loss; 2015 - $2 million loss; 2014 - $13 million loss) 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, as they become due. In order to mitigate this risk, the Company forecasts cash requirements over a 12 month rolling time period to determine whether sufficient funds will be available and maintains substantial capacity under its committed bank lines of credit to address any contingencies. 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 also 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 with a diversified group of banks and institutions which, if necessary, enables the Company to fund all anticipated requirements for approximately 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, 2016. 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. In order to mitigate this risk, 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, netting arrangements, and ongoing monitoring of counterparty credit exposure using external credit rating services and other analytical tools.

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The Company had group credit concentrations and maximum credit exposure, with respect to derivative instruments, in the following counterparty segments:

December 31,	2016	2015
(millions of Canadian dollars)
Canadian financial institutions	39	47
United States financial institutions	179	450
European financial institutions	106	95
Asian financial institutions	1	4
Other1	162	213
	487	809

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

As at December 31, 2016, the Company had provided letters of credit totalling $160 million in lieu of providing cash collateral to its counterparties pursuant to the terms of the relevant ISDA agreements. The Company held no cash collateral on derivative asset exposures at December 31, 2016 and $17 million of cash collateral at December 31, 2015.

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 at 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. Within Gas Distribution, 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 are 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 FINANCIAL INSTRUMENTS

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.

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.

58

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, basis swaps, commodity swaps, power and energy swaps, as well as options. 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 price) 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.

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Fair Value of Derivatives

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

							Total Gross
							Derivative
December 31, 2016	Level 1		Level 2		Level 3		Instruments
(millions of Canadian dollars)
Financial assets
Current derivative assets
Foreign exchange contracts	-		109		-		109
Interest rate contracts	-		3		-		3
Commodity contracts	2		86		153		241
	2		198		153		353
Long-term derivative assets
Foreign exchange contracts	-		73		-		73
Interest rate contracts	-		8		-		8
Commodity contracts	-		43		25		68
Other contracts	-		2		-		2
	-		126		25		151
Financial liabilities
Current derivative liabilities
Foreign exchange contracts	-		(995	)	-		(995	)
Interest rate contracts	-		(583	)	-		(583	)
Commodity contracts	(12	)	(75	)	(272	)	(359	)
Other contracts	-		(4	)	-		(4	)
	(12	)	(1,657	)	(272	)	(1,941	)
Long-term derivative liabilities
Foreign exchange contracts	-		(2,029	)	-		(2,029	)
Interest rate contracts	-		(473	)	-		(473	)
Commodity contracts	-		(10	)	(201	)	(211	)
	-		(2,512	)	(201	)	(2,713	)
Total net financial asset/(liability)
Foreign exchange contracts	-		(2,842	)	-		(2,842	)
Interest rate contracts	-		(1,045	)	-		(1,045	)
Commodity contracts	(10	)	44		(295	)	(261	)
Other contracts	-		(2	)	-		(2	)
	(10	)	(3,845	)	(295	)	(4,150	)

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							Total Gross
							Derivative
December 31, 2015	Level 1		Level 2		Level 3		Instruments
(millions of Canadian dollars)
Financial assets
Current derivative assets
Foreign exchange contracts	-		10		-		10
Interest rate contracts	-		2		-		2
Commodity contracts	14		210		555		779
	14		222		555		791
Long-term derivative assets
Foreign exchange contracts	-		128		-		128
Interest rate contracts	-		18		-		18
Commodity contracts	-		121		106		227
	-		267		106		373
Financial liabilities
Current derivative liabilities
Foreign exchange contracts	-		(872	)	-		(872	)
Interest rate contracts	-		(564	)	-		(564	)
Commodity contracts	(3	)	(130	)	(368	)	(501	)
Other contracts	-		(8	)	-		(8	)
	(3	)	(1,574	)	(368	)	(1,945	)
Long-term derivative liabilities
Foreign exchange contracts	-		(3,048	)	-		(3,048	)
Interest rate contracts	-		(629	)	-		(629	)
Commodity contracts	-		(21	)	(239	)	(260	)
Other contracts	-		(13	)	-		(13	)
	-		(3,711	)	(239	)	(3,950	)
Total net financial asset/(liability)
Foreign exchange contracts	-		(3,782	)	-		(3,782	)
Interest rate contracts	-		(1,173	)	-		(1,173	)
Commodity contracts	11		180		54		245
Other contracts	-		(21	)	-		(21	)
	11		(4,796	)	54		(4,731	)

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

			Unobservable	Minimum	Maximum	Weighted
December 31, 2016	Fair Value		Input	Price/Volatility	Price/Volatility	Average Price/Volatility
(fair value in millions of Canadian dollars)
Commodity contracts - financial1
Natural gas	30		Forward gas price	3.65	5.62	4.77	$/mmbtu3
NGL	1		Forward NGL price	0.37	1.66	1.14	$/gallon
Power	(159	)	Forward power price	26.00	78.70	48.32	$/MWH
Commodity contracts - physical1
Natural gas	(72	)	Forward gas price	2.10	11.05	4.24	$/mmbtu3
Crude	(91	)	Forward crude price	40.97	78.94	68.58	$/barrel
NGL	4		Forward NGL price	0.37	1.75	1.06	$/gallon
Commodity options2
Crude	4		Option volatility	22%	33%	25%
NGL	(13	)	Option volatility	32%	103%	57%
Power	1		Option volatility	22%	51%	23%
	(295	)

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 could 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.

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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,	2016		2015
(millions of Canadian dollars)
Level 3 net derivative asset at beginning of period	54		149
Total loss
Included in earnings1	(113	)	136
Included in OCI	3		(1	)
Settlements	(239	)	(230	)
Level 3 net derivative liability at end of period	(295	)	54

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, 2016 or 2015.

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 totalled $110 million as at December 31, 2016 (2015 - $126 million).

The Company has a held to maturity preferred share investment carried at its amortized cost of $355 million as at December 31, 2016 (2015 - $359 million). These preferred shares are entitled to a cumulative preferred dividend based on the yield of 10-year Government of Canada bonds plus a margin of 4.38%. As at December 31, 2016, the fair value of this preferred share investment approximates its face value of $580 million (2015 - $580 million).

As at December 31, 2016, the Company’s long-term debt had a carrying value of $40,761 million (2015 - $41,530 million) before debt issuance cost and a fair value of $43,910 million (2015 - $41,045 million).

NET INVESTMENT HEDGES

The Company has designated a portion of its United States dollar denominated debt, as well as a portfolio of foreign exchange forward contracts, as a hedge of its net investment in United States dollar denominated investments and subsidiaries.

During the year ended December 31, 2016, the Company recognized an unrealized foreign exchange gain on the translation of United States dollar denominated debt of $121 million (2015 - unrealized loss of $631 million) and an unrealized gain on the change in fair value of its outstanding foreign exchange forward contracts of $21 million (2015 - unrealized loss of $250 million) in OCI. The Company recognized a realized gain of $3 million (2015 - realized gain of $4 million) in OCI associated with the settlement of foreign exchange forward contracts and also recognized a realized gain of $26 million (2015 - realized loss of $75 million) in OCI associated with the settlement of United States dollar denominated debt that had matured during the period. There was no ineffectiveness during the year ended December 31, 2016 (2015 - nil).

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25.   INCOME TAXES

INCOME TAX RATE RECONCILIATION

Year ended December 31,	2016		2015		2014
(millions of Canadian dollars)
Earnings before income taxes and discontinued operations	2,451		11		2,173
Canadian federal statutory income tax rate	15%		15%		15%
Expected federal taxes at statutory rate	368		2		326
Increase/(decrease) resulting from:
Provincial and state income taxes1	34		(204	)	(36	)
Foreign and other statutory rate differentials	(56	)	310		394
Effects of rate-regulated accounting2	(116	)	(52	)	(97	)
Foreign allowable interest deductions	(107	)	(84	)	(65	)
Part VI.1 tax, net of federal Part I deduction	56		55		47
Intercompany sale of investment3	6		23		68
Non-taxable portion of gain on sale of investment to unrelated party4	(61	)	-		-
Valuation allowance5	22		154		2
Noncontrolling interests	(15	)	(28	)	(28	)
Other6	11		(6	)	-
Income taxes on earnings before discontinued operations	142		170		611
Effective income tax rate	5.8%		1,545.5%		28.1%

1	The change in provincial and state income taxes from 2015 to 2016 reflects the increase in earnings from the Canadian operations and the decrease in earnings from the United States operations.
2	The increase in 2016 is due to the federal component of the tax effect of the 2015 impairment of regulatory receivables.
3	In November 2016, September 2015 and November 2014, certain assets were sold to entities under common control. The intercompany gains realized on these transfers were eliminated. However, because these transactions involved the sale of partnership units, tax consequences have been recognized in earnings.
4	The amount in 2016 represents the federal component of the non-taxable portion of the gain on the sale of the South Prairie Region assets to unrelated party.
5	The decrease from 2015 to 2016 is due to the federal component of the tax effect of a valuation allowance on the deferred tax assets related to an outside basis temporary difference that, in 2015, was no longer more likely than not to be realized.
6	2015 included $17 million recovery related to the federal component of the tax effect of adjustments related to prior periods.

COMPONENTS OF PRETAX EARNINGS AND INCOME TAXES

Year ended December 31,	2016		2015		2014
(millions of Canadian dollars)
Earnings/(loss) before income taxes and discontinued operations
Canada	2,034		(1,365	)	114
United States	(333	)	808		1,614
Other	750		568		445
	2,451		11		2,173
Current income taxes
Canada	74		157		35
United States	21		3		(15	)
Other	4		3		4
	99		163		24
Deferred income taxes
Canada	188		(558	)	(193	)
United States	(151	)	565		780
Other	6		-		-
	43		7		587
Income taxes on earnings before discontinued operations	142		170		611

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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 as follows:

December 31,	2016		2015
(millions of Canadian dollars)
Deferred income tax liabilities
Property, plant and equipment	(3,867	)	(3,423	)
Investments	(2,938	)	(3,024	)
Regulatory assets	(439	)	(354	)
Other	(47	)	(85	)
Total deferred income tax liabilities	(7,291	)	(6,886	)
Deferred income tax assets
Financial instruments	1,215		1,374
Pension and OPEB plans	219		202
Loss carryforwards	1,189		848
Other	374		274
Total deferred income tax assets	2,997		2,698
Less valuation allowance	(572	)	(538	)
Total deferred income tax assets, net	2,425		2,160
Net deferred income tax liabilities	(4,866	)	(4,726	)
Presented as follows:1
Accounts receivable and other (Note 7)	-		367
Deferred income taxes	1,170		839
Total deferred income tax assets	1,170		1,206
Accounts payable and other	-		(17	)
Deferred income taxes	(6,036	)	(5,915	)
Total deferred income tax liabilities	(6,036	)	(5,932	)
Net deferred income tax liabilities	(4,866	)	(4,726	)

1 Effective January 1, 2016, the Company elected to early adopt ASU 2015-17 (Note 3).

A valuation allowance has been established for certain loss and credit carryforwards, and outside basis temporary differences on investments that reduce deferred income tax assets to an amount that will more likely than not be realized.

As at December 31, 2016, the Company recognized the benefit of unused tax loss carryforwards of $2,486 million (2015 - $1,754 million) in Canada which start to expire in 2025 and beyond.

As at December 31, 2016, the Company recognized the benefit of unused tax loss carryforwards of $1,287 million (2015 - $899 million) in the United States which start to expire in 2030 and beyond.

The Company has not provided for deferred income taxes on the difference between the carrying value of substantially all of its foreign subsidiaries and their corresponding tax basis as the earnings of those subsidiaries are intended to be permanently reinvested in their operations. As such these investments are not anticipated to give rise to income taxes in the foreseeable future. The difference between the carrying values of the investments and their tax bases is largely a result of unremitted earnings and currency translation adjustments. The unremitted earnings and currency translation adjustment for which no deferred taxes have been recognized in respect of foreign subsidiaries is $4.1 billion (2015 - $4.0 billion). If such earnings are remitted, in the form of dividends or otherwise, the Company may be subject to income taxes and foreign withholding taxes. The determination of the amount of unrecognized deferred income tax liabilities on such amounts is not practicable.

The Company and one or more of its subsidiaries are subject to taxation in Canada, the United States and other foreign jurisdictions. The material jurisdictions in which the Company is subject to potential examinations include the United States (Federal) and Canada (Federal, Alberta and Ontario). The Company’s 2008 to 2016 taxation years are still open for audit in the Canadian jurisdictions and the 2013 to 2016 taxation years remain open for audit in the United States jurisdictions. The Company is currently under examination for income tax matters in Canada for the 2013 and 2014 taxation years. The Company is not currently under examination for income tax matters in any other material jurisdiction where it is subject to income tax.

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UNRECOGNIZED TAX BENEFITS

Year ended December 31,	2016		2015
(millions of Canadian dollars)
Unrecognized tax benefits at beginning of year	65		51
Gross increases for tax positions of current year	27		5
Change in translation of foreign currency	(2	)	9
Lapses of statute of limitations	(6	)	-
Unrecognized tax benefits at end of year	84		65

The unrecognized tax benefits as at December 31, 2016, if recognized, would affect the Company’s effective income tax rate. The Company does not anticipate further adjustments to the unrecognized tax benefits during the next 12 months that would have a material impact on its consolidated financial statements.

The Company recognizes accrued interest and penalties related to unrecognized tax benefits as a component of Income taxes. Income taxes for the year ended December 31, 2016 included $1 million recovery (2015 - $2 million expense; 2014 - nil) of interest and penalties. As at December 31, 2016, interest and penalties of $6 million (2015 - $7 million) have been accrued.

26.   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 Canadian Plans provide Company funded defined benefit pension and/or defined contribution benefits to Canadian employees of Enbridge. The United States Plan provides Company funded defined benefit pension benefits for United States based employees. The Company has four supplemental pension plans that provide pension benefits in excess of the basic plans for certain employees.

A measurement date of December 31, 2016 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	Effective Date of Next Required
	Filed Actuarial Valuation	Actuarial Valuation
Canadian Plans
Liquids Pipelines	December 31, 2015	December 31, 2016
Gas Distribution	December 31, 2013	December 31, 2016
United States Plan	January 1, 2016	January 1, 2017

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.

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OTHER POSTRETIREMENT BENEFITS

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

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,	2016		2015		2016		2015
(millions of Canadian dollars)
Change in accrued benefit obligation
Benefit obligation at beginning of year	2,551		2,470		308		276
Service cost	155		167		8		8
Interest cost	89		98		11		11
Employees’ contributions	-		-		1		1
Actuarial (gains)/loss	112		(172	)	12		9
Benefits paid	(108	)	(90	)	(12	)	(12	)
Effect of foreign exchange rate changes	(14	)	79		(4	)	21
Other	(7	)	(1	)	(12	)	(6	)
Benefit obligation at end of year	2,778		2,551		312		308
Change in plan assets
Fair value of plan assets at beginning of year	2,229		2,062		115		99
Actual return on plan assets	168		88		5		(2	)
Employer’s contributions	102		116		9		10
Employees’ contributions	-		-		1		1
Benefits paid	(108	)	(90	)	(12	)	(12	)
Effect of foreign exchange rate changes	(10	)	54		(3	)	19
Other	(1	)	(1	)	-		-
Fair value of plan assets at end of year1	2,380		2,229		115		115
Underfunded status at end of year	(398	)	(322	)	(197	)	(193	)
Presented as follows:
Deferred amounts and other assets	5		6		4		2
Accounts payable and other	-		-		(7	)	(6	)
Other long-term liabilities (Note 18)	(403	)	(328	)	(194	)	(189	)
	(398	)	(322	)	(197	)	(193	)

1 Assets of $44 million (2015 - $40 million) are held by the Company in trust accounts that back non-registered supplemental pension plans benefitting United States plan participants. Due to United States tax regulations, these assets are not restricted from creditors, and therefore the Company is unable to include these balances in plan assets for accounting purposes. However, these assets are committed for the future settlement of non-registered supplemental pension plan obligations included in the underfunded status as at the end of the year.

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,	2016	2015	2014	2016	2015	2014
Discount rate	4.0%	4.2%	4.0%	4.0%	4.2%	3.9%
Average rate of salary increases	3.6%	3.6%	4.0%

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NET BENEFIT COSTS RECOGNIZED

	Pension						OPEB
Year ended December 31,	2016		2015		2014		2016		2015		2014
(millions of Canadian dollars)
Benefits earned during the year	155		167		108		8		8		8
Interest cost on projected benefit obligations	89		98		93		11		11		12
Expected return on plan assets	(148	)	(142	)	(123	)	(6	)	(6	)	(5	)
Amortization of prior service credits	-		-		-		(1	)	-		-
Amortization of actuarial loss	35		49		28		1		1		-
Net defined benefit costs on an accrual basis	131		172		106		13		14		15
Defined contribution benefit costs	3		4		4		-		-		-
Net benefit cost recognized in Earnings	134		176		110		13		14		15
Amount recognized in OCI:
Net actuarial (gains)/loss1	24		(107	)	232		12		16		15
Net prior service credit2	-		-		-		(12	)	(6	)	-
Total amount recognized in OCI	24		(107	)	232		-		10		15
Total amount recognized in Comprehensive income	158		69		342		13		24		30

1	Unamortized actuarial losses included in AOCI, before tax, were $425 million (2015 - $404 million) relating to the pension plans and $54 million (2015 - $44 million) relating to OPEB at December 31, 2016.
2	Unamortized prior service credits included in AOCI, before tax, were $13 million (2015 - $1 million) relating to OPEB at December 31, 2016.

The Company estimates that approximately $36 million related to pension plans and $1 million related to OPEB at December 31, 2016 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). For the year ended December 31, 2016, an offsetting regulatory liability increased by $10 million (2015 - nil) and has been recorded to the extent pension and OPEB costs are expected to be refunded to customers in future rates.

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,	2016		2015		2014	2016		2015		2014
Discount rate - service cost	4.1	%	4.0	%	5.0%	4.2	%	3.9	%	4.9	%
Discount rate - interest cost	4.1	%	4.0	%	5.0%	4.2	%	3.9	%	4.9	%
Average rate of return on plan assets	6.6	%	6.7	%	6.7%	6.0	%	6.0	%	6.0	%
Average rate of salary increases	3.6	%	4.0	%	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	6.6%	4.5%	2034
Other medical	4.5%	-	-
United States Plan	6.9%	4.5%	2037

A 1% increase in the assumed medical care trend rate would result in an increase of $23 million in the benefit obligation and an increase of $1 million in service and interest costs. A 1% decrease in the assumed medical care trend rate would result in a decrease of $45 million in the benefit obligation and a decrease of $2 million in service and interest costs.

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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,	2016		2015	2016		2015
Canadian Plans	6.6	%	6.7%
United States Plan	7.2	%	7.2%	6.0	%	6.0	%

Target Mix for Plan Assets

	Canadian Plans
	Liquids Pipelines	Gas Distribution	United States
	Plan	Plan	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, 2016, the pension assets were invested 48.3% (2015 - 56.4%) in equity securities, 31.4% (2015 - 31.4%) in fixed income securities and 20.3% (2015 - 12.2%) in other. The OPEB assets were invested 60.0% (2015 - 59.1%) in equity securities, 39.1% (2015 - 40.0%) in fixed income securities and 0.9% (2015 - 0.9%) in other.

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The following table summarizes the Company’s pension financial instruments at fair value. Non-financial instruments with a carrying value of $7 million asset (2015 - $21 million asset) and refundable tax assets of $105 million (2015 - $106 million) have been excluded from the table below.

	2016							2015
December 31,	Level 1	1	Level 2	2	Level 3	3	Total	Level 1	1	Level 2	2	Level 3	3	Total
(millions of Canadian dollars)
Pension
Cash and cash equivalents	47		-		-		47	37		-		-		37
Fixed income securities
Canadian government bonds	137		-		-		137	131		-		-		131
Corporate bonds and debentures	5		3		-		8	5		3		-		8
Canadian corporate bond index fund	277		-		-		277	259		-		-		259
Canadian government bond index fund	214		-		-		214	201		-		-		201
United States debt index fund	111		-		-		111	102		-		-		102
Equity
Canadian equity securities	138		-		-		138	133		-		-		133
United States equity securities	2		-		-		2	2		-		-		2
Global equity securities	114		30		-		144	106		25		-		131
Canadian equity funds	287		-		-		287	253		-		-		253
United States equity funds	271		-		-		271	243		5		-		248
Global equity funds	167		140		-		307	161		148		-		309
Infrastructure4	-		-		184		184	-		-		182		182
Real estate4	-		-		137		137	-		-		115		115
Forward currency contracts	-		4		-		4	-		(10	)	-		(10	)
OPEB
Cash and cash equivalents	1		-		-		1	2		-		-		2
Fixed income securities
United States government and government agency bonds	45		-		-		45	46		-		-		46
Equity
United States equity funds	35		-		-		35	34		-		-		34
Global equity funds	34		-		-		34	34		-		-		34

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 values of the infrastructure and real estate investments are 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:

December 31,	2016	2015
(millions of Canadian dollars)
Balance at beginning of year	297	132
Unrealized and realized gains	22	44
Purchases and settlements, net	2	121
Balance at end of year	321	297

PLAN CONTRIBUTIONS BY THE COMPANY

	Pension		OPEB
Year ended December 31,	2016	2015	2016	2015
(millions of Canadian dollars)
Total contributions	102	116	9	10
Contributions expected to be paid in 2017	148		2

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BENEFITS EXPECTED TO BE PAID BY THE COMPANY

Year ended December 31,	2017	2018	2019	2020	2021	2022-2026
(millions of Canadian dollars)
Expected future benefit payments	115	121	127	134	142	829

27.   OTHER INCOME/(EXPENSE)

Year ended December 31,	2016	2015		2014
(millions of Canadian dollars)
Net foreign currency gain/(loss)	91	(884	)	(400	)
Allowance for equity funds used during construction	1	2		3
Interest income on affiliate loans	23	20		20
Interest income	3	4		3
Noverco preferred shares dividend income	37	40		42
Gains on dispositions	848	94		38
Other	29	22		28
	1,032	(702	)	(266	)

28.   SEVERANCE COSTS

Included in Operating and administrative and Other income/(expense) is $54 million and nil, respectively (2015 - $42 million and $4 million, respectively), for severance costs related to termination benefits to employees. This resulted from an enterprise-wide reduction of workforce that occurred in October 2016 and November 2015 that affected approximately 5% of the Company’s workforce in each respective year. The amounts are included within Eliminations and Other.

Of the total severance costs incurred in 2016, $29 million was paid in 2016 with the remaining $25 million to be paid in 2017 and is included in Accounts payable and other as at December 31, 2016.

Of the total severance costs incurred in 2015, $22 million was paid in 2015 with the remaining $24 million paid in 2016. This amount was included in Accounts payable and other as at December 31, 2015.

29.   CHANGES IN OPERATING ASSETS AND LIABILITIES

Year ended December 31,	2016		2015		2014
(millions of Canadian dollars)
Accounts receivable and other	(437	)	698		(83	)
Accounts receivable from affiliates	(7	)	82		(176	)
Inventory	(371	)	(315	)	(186	)
Deferred amounts and other assets	(183	)	364		(429	)
Accounts payable and other	396		(1,472	)	(822	)
Accounts payable to affiliates	71		(26	)	34
Interest payable	20		31		24
Other long-term liabilities	153		(7	)	(61	)
	(358	)	(645	)	(1,699	)

30.   RELATED PARTY TRANSACTIONS

Related party transactions are conducted 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.

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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 $7 million for the year ended December 31, 2016 (2015 - $7 million; 2014 - $7 million).

Certain wholly-owned subsidiaries within the Liquids Pipelines, Gas Distribution, Gas Pipelines and Processing and Energy Services segments have committed and uncommitted transportation arrangements with several joint venture affiliates that are accounted for using the equity method. Total amounts charged to the Company for transportation services for the year ended December 31, 2016 were $357 million (2015 - $332 million; 2014 - $256 million).

A wholly-owned subsidiary within Liquids Pipelines had a lease arrangement with a joint venture affiliate. During the year ended December 31, 2016, expenses related to the lease arrangement totalled $287 million (2015 - $151 million; 2014 - $21 million) and were recorded to Operating and administrative expense.

Certain wholly-owned subsidiaries within Gas Distribution and Energy Services segments made natural gas and NGL purchases of $98 million (2015 - $228 million; 2014 - $315 million) from several joint venture affiliates during the year ended December 31, 2016.

Natural gas sales of $49 million (2015 - $5 million; 2014 - $58 million) were made by certain wholly-owned subsidiaries within the Energy Services segment to several joint venture affiliates during the year ended December 31, 2016.

LONG-TERM NOTES RECEIVABLE FROM AFFILIATES

Amounts receivable from affiliates include a series of loans to Vector and other affiliates totalling $130 million and $140 million, respectively (2015 - $149 million and $3 million, respectively), which require quarterly interest payments at annual interest rates ranging from 4% to 12%. These amounts are included in Deferred amounts and other assets.

31.   COMMITMENTS AND CONTINGENCIES

COMMITMENTS

At December 31, 2016, Enbridge had commitments as detailed below:

		Less
		than
	Total	1 year	2 years	3 years	4 years	5 years	Thereafter
(millions of Canadian dollars)
Purchase of services, pipe and other materials, including transportation1,2	10,661	3,660	1,461	1,249	1,100	996	2,195
Capital and operating leases	631	105	62	56	52	51	305
Maintenance agreements	394	54	40	35	18	16	231
Land lease commitments	356	13	14	13	14	13	289
Total	12,042	3,832	1,577	1,353	1,184	1,076	3,020

1Includes capital and operating commitments.

2Includes commitments for transportation service agreements totalling $618 million which assume a light to heavy crude oil ratio of 80:20 on certain pipelines and a power charge of $0.06 per barrel.

ENBRIDGE ENERGY PARTNERS, L.P.

As at December 31, 2016, Enbridge holds an approximate 35.3% (2015 - 35.7%; 2014 - 33.7%) combined direct and indirect economic interest in EEP, which is consolidated with noncontrolling interests.

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 Kalamazoo River via 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.

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EEP continues to evaluate the need for additional remediation activities and is performing the necessary restoration and monitoring of the areas affected by the Line 6B crude oil release. All 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.

In May 2015, EEP reached a settlement with the MDEQ and the Michigan Attorney General’s offices regarding the Line 6B crude oil release. As stipulated in the settlement, EEP agrees to: (1) provide at least 300 acres of wetland through restoration, creation, or banked wetland credits, to remain as wetland in perpetuity; (2) pay US$5 million as mitigation for impacts to the banks, bottomlands, and flow of Talmadge Creek and the Kalamazoo River for the purpose of enhancing the Kalamazoo River watershed and restoring stream flows in the River; (3) continue to reimburse the State of Michigan for costs arising from oversight of EEP activities since the release; and (4) continue monitoring, restoration and invasive species control within state-regulated wetlands affected by the release and associated response activities. The timing of these activities is based upon the work plans approved by the State of Michigan.

As at December 31, 2016, EEP’s total cost estimate for the Line 6B crude oil release remains at US$1.2 billion ($195 million after-tax attributable to Enbridge) since December 31, 2015 and 2014. This includes a reduction of estimated remediation efforts offset by an increase in civil penalties under the Clean Water Act of the United States, as described below under Legal and Regulatory Proceedings.

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, 2016. Despite the efforts EEP has made to ensure the reasonableness of its estimate, 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.

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.

EEP has completed the cleanup, remediation and restoration of the areas affected by the release. In October 2013, the National Transportation Safety Board publicly posted their final report related to the Line 6A crude oil release which states the probable cause of the crude oil release was erosion caused by a leaking water pipe resulting from an improperly installed third-party water service line below EEP’s oil pipeline.

The total estimated cost for the Line 6A crude oil release was approximately US$53 million ($7 million after-tax attributable to Enbridge) before insurance recoveries and excluding fines and penalties. These costs included emergency response, environmental remediation and cleanup activities with the crude oil release. As at December 31, 2016, EEP has no remaining estimated liability.

Insurance

EEP is included in the comprehensive insurance program that is maintained by Enbridge for its subsidiaries and affiliates. On May 1 of each year, the commercial liability insurance program is renewed and includes coverage that is consistent with coverage considered customary for its industry and includes coverage for environmental incidents excluding costs for fines and penalties.

Enbridge has renewed its comprehensive property and liability insurance programs with a liability program aggregate limit of US$900 million, which includes sudden and accidental pollution liability. The insurance programs are effective May 1, 2016 through April 30, 2017. In the unlikely event that multiple insurable incidents which in aggregate exceed coverage limits occur within the same insurance period, the total insurance coverage will be allocated among Enbridge entities on an equitable basis based on an insurance allocation agreement among Enbridge and its subsidiaries.

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A majority of the costs incurred in connection with the crude oil release for Line 6B, other than fines and penalties, 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 for Enbridge and its affiliates. Including EEP’s remediation spending through December 31, 2016, costs related to Line 6B exceeded the limits of the coverage available under this insurance policy. Additionally, fines and penalties would not be covered under prior or existing insurance policy. As at December 31, 2016, EEP has recorded total insurance recoveries of US$547 million ($80 million after-tax attributable to Enbridge) for the Line 6B crude oil release out of the US$650 million aggregate limit. EEP will record receivables for additional amounts it claims for recovery pursuant to its insurance policies during the period it deems recovery to be probable.

In March 2013, EEP and Enbridge filed a lawsuit against the insurers of US$145 million of coverage, as one particular insurer is disputing the recovery eligibility for costs related to EEP’s claim on the Line 6B crude oil release and the other remaining insurers asserted that their payment is predicated on the outcome of the recovery from that insurer. EEP received a partial recovery payment of US$42 million from the other remaining insurers and amended its lawsuit such that it includes only one insurer.

Legal and Regulatory Proceedings

A number of United States governmental agencies and regulators have initiated investigations into the Line 6B crude oil release. Two actions or claims are pending against Enbridge, EEP or their affiliates in United States state courts in connection with the Line 6B crude oil release. Based on the current status of these cases, the Company does not expect the outcome of these actions to be material to its results of operations or financial condition.

Line 6A and 6B Fines and Penalties

As at December 31, 2016, included in EEP’s total estimated costs related to the Line 6B crude oil release were US$69 million in fines and penalties. Of this amount, US$61 million relates to civil penalties under the Clean Water Act of the United States, which EEP fully accrued but have not paid, pending approval of the Consent Decree, as described below.

In June 2015, Enbridge reached a separate agreement with the United States (Federal Natural Resources Damages Trustees), State of Michigan (State Natural Resources Damages Trustees), Match-E-Be-Nash-She-Wish Band of the Potawatomi Indians, and the Nottawaseppi Huron Band of the Potawatomi Indians, and paid approximately US$4 million that was accrued to cover a variety of projects, including the restoration of 175 acres of oak savanna in the Fort Custer State Recreation Area and wild rice beds along the Kalamazoo River.

One claim related to the Line 6A crude oil release had been filed against Enbridge, EEP or their affiliates by the State of Illinois in the Illinois state court in connection with this crude oil release. On February 20, 2015, EEP agreed to a consent order releasing it from any claims, liability, or penalties.

Consent Decree

On July 20, 2016, a Consent Decree was filed with the United States District Court for the Western District of Michigan Southern Division (the Court). The Consent Decree is EEP’s signed settlement agreement with the EPA and the United States Department of Justice regarding Lines 6A and 6B crude oil releases. Pursuant to the Consent Decree, EEP will pay US$62 million in civil penalties: US$61 million in respect of Line 6B and US$1 million in respect of Line 6A. The Consent Decree will take effect upon approval by the Court.

In addition to the monetary fines and penalties discussed above, the Consent Decree calls for replacement of Line 3, which EEP initiated in 2014 and is currently under regulatory review in the State of Minnesota. The Consent Decree contains a variety of injunctive measures, including, but not limited to, enhancements to EEP’s comprehensive in-line inspection-based spill prevention program; enhanced measures to protect the Straits of Mackinac; improved leak detection requirements; installation of new valves to control product loss in the event of an incident; continued enhancement of control room operations; and improved spill response capabilities. Collectively, these measures build on continuous improvements implemented since 2010 to EEP’s leak detection program, control centre operations and emergency response program. EEP estimates the total cost of these measures to be approximately US$110 million, most of which is already incorporated into existing long-term capital investment and operational expense planning and guidance. Compliance with the terms of the Consent Decree is not expected to materially impact the overall financial performance of EEP or the Company.

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AUX SABLE

Notice of Violation

In September 2014, Aux Sable US received a Notice and Finding of Violation (NFOV) from the United States EPA for alleged violations of the Clean Air Act related to the Leak Detection and Repair program, and related provisions of the Clean Air Act permit for Aux Sable’s Channahon, Illinois facility. As part of the ongoing process of responding to the September 2014 NFOV, Aux Sable discovered what it believed to be an exceedance of currently permitted limits for Volatile Organic Material. In April 2015, a second NFOV from the EPA was received in connection with this potential exceedance. Aux Sable engaged in discussions with the EPA to evaluate the impacts and ultimate resolution of these issues, including with respect to a draft Consent Decree, and those discussions are continuing. The Consent Decree, when finalized, is not expected to have a material impact.

On October 14, 2016, an amended claim was filed against Aux Sable by a counterparty to an NGL supply agreement. On January 5, 2017, Aux Sable filed a Statement of Defence with respect to this claim. While the final outcome of this action cannot be predicted with certainty, at this time management believes that the ultimate resolution of this action will not have a material impact on the Company’s consolidated financial position or results of operations.

TAX MATTERS

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

OTHER LITIGATION

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

32.   GUARANTEES

The Company has agreed to indemnify EEP from and against substantially all liabilities, including liabilities relating to environmental matters, arising from operations prior to the transfer of its pipeline operations to EEP in 1991. This indemnification does not apply to amounts that EEP would be able to recover in its tariff rates if not recovered through insurance or to any liabilities relating to a change in laws after December 27, 1991.

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

The Company has also agreed to indemnify the Fund Group for certain liabilities relating to environmental matters arising from operations prior to the transfer of certain assets and interests to the Fund Group in 2012 and prior to the transfer of certain assets and interests to the Fund Group as part of the Canadian Restructuring Plan. The Company has also agreed to pay defined payments to the Fund Group on their investment in Southern Lights in the event shippers do not elect to extend their current contracts post June 2025.

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Following the completion of the Canadian Restructuring Plan, EIPLP indirectly owns all of the Class B Units of Southern Lights Canada, together with the Class A Units it already owned. As a result EIPLP holds all the ownership, economic interests and voting rights, direct and indirect, in Southern Lights Canada. The Enbridge guarantee provided in respect of distributions on the Class A Units of Southern Lights Canada was released upon closing of the Canadian Restructuring Plan.

In the normal course of conducting business, the Company enters into agreements which indemnify third parties and affiliates. 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 cannot reasonably estimate the maximum potential amounts that could become payable to third parties and affiliates under these agreements; however, historically, the Company has not made any significant payments under 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 indemnifications and guarantees have not had, and are not reasonably likely to have, a material effect on the Company’s financial condition, changes in financial condition, earnings, liquidity, capital expenditures or capital resources.

33.   SUBSEQUENT EVENTS

On February 17, 2017, the Company announced it had acquired an effective 50% interest in the partnership that will construct the 497-MW Hohe See Offshore Wind Project. Enbridge will partner with state-owned German utility EnBW in the construction and operation of this late-design project, with the target in-service date of 2019. The Hohe See Offshore Wind Project is located in the North Sea, 98 kilometres (61 miles) off the coast of Germany and will be constructed under fixed-price engineering, procurement, construction and installation contracts, which have been secured with key suppliers. The Hohe See Offshore Wind Project is backed by a government legislated 20-year revenue support mechanism. Enbridge’s total investment in this project through the project’s completion and in-service date in 2019 is expected to be approximately $1.7 billion (€1.07 billion), including planned spend of approximately $0.6 billion (€0.44 billion) throughout 2017.

On February 15, 2017, EEP completed its previously disclosed transaction to acquire an effective 27.6% interest in the Bakken Pipeline System for a purchase price of US$1.5 billion. The Bakken Pipeline System connects the prolific Bakken formation in North Dakota to markets in eastern PADD II and the United States Gulf Coast, providing customers with access to premium markets at a competitive cost. The Bakken Pipeline System consists of the Dakota Access Pipeline and the Energy Transfer Crude Oil Pipeline projects. The Dakota Access Pipeline consists of 1,886 kilometres (1,172 miles) of 30-inch pipeline from the Bakken/Three Forks production area in North Dakota to Patoka, Illinois. It is expected to initially deliver in excess of 470,000 bpd of crude oil and has the potential to be expanded to 570,000 bpd. The Energy Transfer Crude Oil Pipeline consists of 100 kilometres (62 miles) of new 30-inch diameter pipe, 1,104 kilometres (686 miles) of converted 30-inch diameter pipe, and 64 kilometres (40 miles) of converted 24-inch diameter pipe from Patoka, Illinois to Nederland, Texas.

On January 27, 2017, Enbridge announced that it had entered into a merger agreement through a wholly-owned subsidiary, whereby it will take private MEP by acquiring all of the outstanding publicly-held common units of MEP. Total consideration to be paid by Enbridge for these units will be approximately US$170 million and the transaction is expected to close in the second quarter of 2017. In addition, pursuant to an on-going strategic review of EEP, further joint funding actions with EEP were announced. Specifically, Enbridge and EEP entered into an agreement for the joint funding of the United States portion of the Line 3 Replacement Program (U.S. L3R Program), whereby Enbridge and EEP will fund 99% and 1%, respectively, of the project development and construction costs. Enbridge has reimbursed EEP approximately US$450 million for capital expenditures on the project to date and will fund 99% of the expenditures through construction. EEP will retain an option to acquire up to 40% of the U.S. L3R Program at book value, once the project is completed and in service. EEP also used a portion of the proceeds reimbursed by Enbridge under the U.S. L3R joint funding arrangement to acquire an additional 15% interest in the cash-generating Eastern Access projects pursuant to an existing joint funding agreement for approximately US$360 million. The strategic review of EEP is ongoing and it is currently expected that any resulting actions will be announced early in the second quarter of 2017. Any such contemplated actions are not expected to be material to Enbridge’s previously published financial projections.

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