Enbridge (ENB) 8-K 2018 FY Updated Consolidated Financial Statements of Enbridge Inc. and Accompanying Notes

EXHIBIT 99.1

Updated Consolidated Financial Statements of Enbridge Inc. and Accompanying Notes

ENBRIDGE INC.

CONSOLIDATED STATEMENTS OF EARNINGS

Year ended December 31,	2018		2017		2016
(millions of Canadian dollars, except per share amounts)
Operating revenues
Commodity sales	27,660		26,286		22,816
Gas distribution sales	4,360		4,215		2,486
Transportation and other services	14,358		13,877		9,258
Total operating revenues (Note 4)	46,378		44,378		34,560
Operating expenses
Commodity costs	26,818		26,065		22,409
Gas distribution costs	2,583		2,572		1,596
Operating and administrative	6,792		6,442		4,358
Depreciation and amortization	3,246		3,163		2,240
Impairment of long-lived assets(Note 8 and Note 11)	1,104		4,463		1,376
Impairment of goodwill(Note 8 and Note 16)	1,019		102		—
Total operating expenses	41,562		42,807		31,979
Operating income	4,816		1,571		2,581
Income from equity investments(Note 13)	1,509		1,102		428
Other income/(expense)
Net foreign currency gain/(loss)	(522	)	237		91
Gain/(loss) on dispositions	(46	)	16		848
Other	516		199		93
Interest expense(Note 18)	(2,703	)	(2,556	)	(1,590	)
Earnings before income taxes	3,570		569		2,451
Income tax recovery/(expense)(Note 25)	(237	)	2,697		(142	)
Earnings	3,333		3,266		2,309
Earnings attributable to noncontrolling interests and redeemable noncontrolling interests	(451	)	(407	)	(240	)
Earnings attributable to controlling interests	2,882		2,859		2,069
Preference share dividends	(367	)	(330	)	(293	)
Earnings attributable to common shareholders	2,515		2,529		1,776
Earnings per common share attributable to common shareholders (Note 6)	1.46		1.66		1.95
Diluted earnings per common share attributable to common shareholders (Note 6)	1.46		1.65		1.93

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

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ENBRIDGE INC.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

Year ended December 31,	2018		2017		2016
(millions of Canadian dollars)
Earnings	3,333		3,266		2,309
Other comprehensive income/(loss), net of tax
Change in unrealized loss on cash flow hedges	(153	)	(21	)	(138	)
Change in unrealized gain/(loss) on net investment hedges	(458	)	490		166
Other comprehensive income/(loss) from equity investees	38		(27	)	—
Reclassification to earnings of loss on cash flow hedges	152		313		116
Reclassification to earnings of pension and other postretirement benefits amounts	12		19		17
Actuarial gain/(loss) on pension plans and other postretirement benefits	(52	)	8		(34	)
Foreign currency translation adjustments	4,599		(3,060	)	(712	)
Other comprehensive income/(loss), net of tax	4,138		(2,278	)	(585	)
Comprehensive income	7,471		988		1,724
Comprehensive income attributable to noncontrolling interests and redeemable noncontrolling interests	(801	)	(160	)	(229	)
Comprehensive income attributable to controlling interests	6,670		828		1,495
Preference share dividends	(367	)	(330	)	(293	)
Comprehensive income attributable to common shareholders	6,303		498		1,202

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

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ENBRIDGE INC.

CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY

Year ended December 31,	2018		2017		2016
(millions of Canadian dollars, except per share amounts)
Preference shares (Note 21)
Balance at beginning of year	7,747		7,255		6,515
Preference shares issued	—		492		740
Balance at end of year	7,747		7,747		7,255
Common shares (Note 21)
Balance at beginning of year	50,737		10,492		7,391
Common shares issued	—		1,500		2,241
Common shares issued in Merger Transaction (Note 8)	—		37,429		—
Shares issued on Sponsored Vehicles buy-in (Note 21)	12,727		—		—
Dividend Reinvestment and Share Purchase Plan	1,181		1,226		795
Shares issued on exercise of stock options	32		90		65
Balance at end of year	64,677		50,737		10,492
Additional paid-in capital
Balance at beginning of year	3,194		3,399		3,301
Stock-based compensation	49		82		41
Sponsored Vehicles buy-in (Note 20)	(4,323	)	—		—
Options exercised	(24	)	(95	)	(24	)
Dilution gain on Spectra Energy Partners, LP restructuring (Note 20)	1,136		—		—
Dilution gain/(loss) and other	(111	)	(192	)	81
Sale of noncontrolling interest in subsidiaries (Note 20)	79		—		—
Balance at end of year	—		3,194		3,399
Retained earnings/(deficit)
Balance at beginning of year	(2,468	)	(716	)	142
Earnings attributable to controlling interests	2,882		2,859		2,069
Preference share dividends	(367	)	(330	)	(293	)
Common share dividends declared	(5,019	)	(4,702	)	(1,945	)
Dividends paid to reciprocal shareholder	33		30		26
Modified retrospective adoption of ASC 606 Revenue from Contracts with Customers (Note 3)	(86	)	—		—
Redemption value adjustment attributable to redeemable noncontrolling interests (Note 20)	(456	)	292		(686	)
Adjustment relating to equity method investment	—		—		(29	)
Other	(57	)	99		—
Balance at end of year	(5,538	)	(2,468	)	(716	)
Accumulated other comprehensive income/(loss) (Note 23)
Balance at beginning of year	(973	)	1,058		1,632
Impact of Sponsored Vehicles buy-in	(142	)	—		—
Other comprehensive income/(loss) attributable to common shareholders, net of tax	3,787		(2,031	)	(574	)
Balance at end of year	2,672		(973	)	1,058
Reciprocal shareholding (Note 13)
Balance at beginning of year	(102	)	(102	)	(83	)
Change in reciprocal interest	14		—		(19	)
Balance at end of year	(88	)	(102	)	(102	)
Total Enbridge Inc. shareholders’ equity	69,470		58,135		21,386
Noncontrolling interests (Note 20)
Balance at beginning of year	7,597		577		1,300
Earnings/(loss) attributable to noncontrolling interests	334		232		(28	)
Other comprehensive income/(loss) attributable to noncontrolling interests, net of tax
Change in unrealized gain on cash flow hedges	31		15		4
Foreign currency translation adjustments	294		(431	)	(44	)
Reclassification to earnings of (gain)/loss on cash flow hedges	4		139		40
	329		(277	)	—
Comprehensive income/(loss) attributable to noncontrolling interests	663		(45	)	(28	)
Noncontrolling interests resulting from Merger Transaction (Note 8)	—		8,955		—
Enbridge Energy Company, Inc. common control transaction	—		(343	)	—
Distributions	(857	)	(839	)	(720	)
Contributions	24		832		28
Deconsolidation of Sabal Trail Transmission, LLC	—		(2,318	)	—
Spectra Energy Partners, LP restructuring (Note 20)	(1,486	)	—		—
Sale of noncontrolling interest in subsidiaries	1,183		—		—
Purchase of noncontrolling interests on Sponsored Vehicles buy-in (Note 20)	(2,657	)	—		—
Noncontrolling interests reclassified on Sponsored Vehicles buy-in	(210	)	—		—
Preferred share redemption (Note 20)	(210	)	—		—
Dilution gain	—		832		—
Other	(82	)	(54	)	(3	)
Balance at end of year	3,965		7,597		577
Total equity	73,435		65,732		21,963
Dividends paid per common share	2.68		2.41		2.12

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

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ENBRIDGE INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

Year ended December 31,	2018		2017		2016
(millions of Canadian dollars)
Operating activities
Earnings	3,333		3,266		2,309
Adjustments to reconcile earnings to net cash provided by operating activities:
Depreciation and amortization	3,246		3,163		2,240
Deferred income tax (recovery)/expense	(148	)	(2,877	)	43
Changes in unrealized (gain)/loss on derivative instruments, net(Note 24)	903		(1,242	)	(509	)
Earnings from equity investments	(1,509	)	(1,102	)	(656	)
Distributions from equity investments	1,539		1,264		827
Impairment of long-lived assets	1,104		4,463		1,620
Impairment of goodwill	1,019		102		—
(Gain)/loss on dispositions	8		(120	)	(848	)
Other	92		79		547
Changes in operating assets and liabilities (Note 27)	915		(338	)	(368	)
Net cash provided by operating activities	10,502		6,658		5,205
Investing activities
Capital expenditures	(6,806	)	(8,287	)	(5,128	)
Long-term investments	(1,312	)	(3,586	)	(514	)
Distributions from equity investments in excess of cumulative earnings	1,277		125		—
Additions to intangible assets	(540	)	(789	)	(127	)
Acquisitions	—		—		(644	)
Cash acquired in Merger Transaction (Note 8)	—		682		—
Proceeds from dispositions	4,452		628		1,379
Reimbursement of capital expenditures	—		212		—
Other	(88	)	(22	)	(118	)
Net cash used in investing activities	(3,017	)	(11,037	)	(5,152	)
Financing activities
Net change in short-term borrowings (Note 18)	(420	)	721		(248	)
Net change in commercial paper and credit facility draws	(2,256	)	(1,249	)	(2,297	)
Debenture and term note issues, net of issue costs	3,537		9,483		4,080
Debenture and term note repayments	(4,445	)	(5,054	)	(1,946	)
Sale of noncontrolling interest in subsidiary	1,289		—		—
Purchase of interest in consolidated subsidiary	—		(227	)	—
Contributions from noncontrolling interests	24		832		28
Distributions to noncontrolling interests	(857	)	(919	)	(720	)
Contributions from redeemable noncontrolling interests	70		1,178		591
Distributions to redeemable noncontrolling interests	(325	)	(247	)	(202	)
Sponsored Vehicle buy-in cash payment	(64	)	—		—
Preference shares issued	—		489		737
Redemption of preferred shares	(210	)	—		—
Common shares issued	21		1,549		2,260
Preference share dividends	(364	)	(330	)	(293	)
Common share dividends	(3,480	)	(2,750	)	(1,150	)
Other	(23	)	—		—
Net cash (used in)/provided by financing activities	(7,503	)	3,476		840
Effect of translation of foreign denominated cash and cash equivalents and restricted cash	68		(72	)	(19	)
Net increase/(decrease) in cash and cash equivalents and restricted cash	50		(975	)	874
Cash and cash equivalents and restricted cash at beginning of year	587		1,562		688
Cash and cash equivalents and restricted cash at end of year	637		587		1,562
Supplementary cash flow information
Cash paid for income taxes	277		172		194
Cash paid for interest, net of amount capitalized	2,508		2,668		1,820
Property, plant and equipment non-cash accruals	847		889		773

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

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ENBRIDGE INC.

CONSOLIDATED STATEMENTS OF FINANCIAL POSITION

December 31,	2018		2017
(millions of Canadian dollars; number of shares in millions)
Assets
Current assets
Cash and cash equivalents (Note 2)	518		480
Restricted cash	119		107
Accounts receivable and other (Note 9)	6,517		7,053
Accounts receivable from affiliates	79		47
Inventory (Note 10)	1,339		1,528
	8,572		9,215
Property, plant and equipment, net(Note 11)	94,540		90,711
Long-term investments(Note 13)	16,707		16,644
Restricted long-term investments(Note 14)	323		267
Deferred amounts and other assets	8,558		6,442
Intangible assets, net(Note 15)	2,372		3,267
Goodwill(Note 16)	34,459		34,457
Deferred income taxes(Note 25)	1,374		1,090
Total assets	166,905		162,093
Liabilities and equity
Current liabilities
Short-term borrowings (Note 18)	1,024		1,444
Accounts payable and other (Note 17)	9,836		9,478
Accounts payable to affiliates	40		157
Interest payable	669		634
Environmental liabilities	27		40
Current portion of long-term debt (Note 18)	3,259		2,871
	14,855		14,624
Long-term debt(Note 18)	60,327		60,865
Other long-term liabilities	8,834		7,510
Deferred income taxes(Note 25)	9,454		9,295
	93,470		92,294
Commitments and contingencies(Note 29)
Redeemable noncontrolling interests(Note 20)	—		4,067
Equity
Share capital(Note 21)
Preference shares	7,747		7,747
Common shares(2,022 and 1,695 outstanding at December 31, 2018 and
December 31, 2017, respectively)	64,677		50,737
Additional paid-in capital	—		3,194
Deficit	(5,538	)	(2,468	)
Accumulated other comprehensive income/(loss) (Note 23)	2,672		(973	)
Reciprocal shareholding	(88	)	(102	)
Total Enbridge Inc. shareholders’ equity	69,470		58,135
Noncontrolling interests (Note 20)	3,965		7,597
	73,435		65,732
Total liabilities and equity	166,905		162,093

Variable Interest Entities (Note 12).

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

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NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

INDEX

		Page
1.	Business Overview	7
2.	Significant Accounting Policies	8
3.	Changes in Accounting Policies	18
4.	Revenue	23
5.	Segmented Information	25
6.	Earnings per Common Share	27
7.	Regulatory Matters	28
8.	Acquisitions and Dispositions	32
9.	Accounts Receivable and Other	40
10.	Inventory	40
11.	Property, Plant and Equipment	40
12.	Variable Interest Entities	41
13.	Long-Term Investments	46
14.	Restricted Long-Term Investments	48
15.	Intangible Assets	49
16.	Goodwill	50
17.	Accounts Payable and Other	51
18.	Debt	52
19.	Asset Retirement Obligations	58
20.	Noncontrolling Interests	59
21.	Share Capital	62
22.	Stock Option and Stock Unit Plans	65
23.	Components of Accumulated Other Comprehensive Income/(Loss)	67
24.	Risk Management and Financial Instruments	69
25.	Income Taxes	81
26.	Pension and Other Postretirement Benefits	84
27.	Changes in Operating Assets and Liabilities	93
28.	Related Party Transactions	93
29.	Commitments and Contingencies	94
30.	Guarantees	95
31.	Condensed Consolidating Financial Information	96
32.	Subsequent Events	106
33.	Quarterly Financial Data	107

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1. BUSINESS OVERVIEW

The terms “we,” “our,” “us” and “Enbridge” as used in this report refer collectively to Enbridge Inc. and its subsidiaries unless the context suggests otherwise. These terms are used for convenience only and are not intended as a precise description of any separate legal entity within Enbridge.

Enbridge is a publicly traded energy transportation and distribution company. We conduct our business through five business segments: Liquids Pipelines; Gas Transmission and Midstream; Gas Distribution; Green Power and Transmission; and Energy Services. These reporting segments are strategic business units established by senior management to facilitate the achievement of our long-term objectives, to aid in resource allocation decisions and to assess operational performance.

LIQUIDS PIPELINES

Liquids Pipelines consists of common carrier and contract pipelines that transport crude oil, natural gas liquids (NGL) and refined products and terminals in Canada and the United States, including Canadian Mainline, Lakehead Pipeline System (Lakehead System), Regional Oil Sands System, Gulf Coast and Mid-Continent, Southern Lights Pipeline, Express-Platte System, Bakken System, and Feeder Pipelines and Other.

GAS TRANSMISSION AND MIDSTREAM

Gas Transmission and Midstream consists of investments in natural gas pipelines and gathering and processing facilities in Canada and the United States. Investments in natural gas pipelines include our interests in US Gas Transmission, Canadian Gas Transmission and Midstream, Alliance Pipeline, US Midstream and Other. Investments in natural gas processing include our interest in Aux Sable, a natural gas extraction and fractionation business located near the terminus of the Alliance Pipeline; Canadian Gas Transmission and Midstream assets located in northeast British Columbia and northwest Alberta; and DCP Midstream, LLC assets located primarily in Texas and Oklahoma.

GAS DISTRIBUTION

Gas Distribution consists of our natural gas utility operations, the core of which are Enbridge Gas Distribution Inc. (EGD) and Union Gas Limited (Union Gas), which serves residential, commercial and industrial customers, primarily located in Ontario. This business segment also includes natural gas distribution activities in Quebec and New Brunswick and an investment in Noverco Inc. (Noverco).

GREEN POWER AND TRANSMISSION

Green Power and Transmission consists of our 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. We also have assets in operation and 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 our 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 the impact of foreign exchange hedge settlements, which are not allocated to business segments. Also included in Eliminations and Other are new business development activities, general corporate investments and a portion of the synergies achieved thus far related to the integration of corporate functions due to the Merger Transaction, as defined in Acquisition of Spectra Energy Corp.

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SPONSORED VEHICLES BUY-IN

In the fourth quarter of 2018, Enbridge completed the buy-ins of our sponsored vehicles: Spectra Energy Partners, LP (SEP), Enbridge Energy Partners, L.P. (EEP), Enbridge Energy Management, L.L.C. (EEM) and Enbridge Income Fund Holdings Inc. (ENF), (referred to herein collectively as the Sponsored Vehicles) in a series of combination transactions, through which we acquired all of the outstanding equity securities of the Sponsored Vehicles not beneficially owned by us (collectively, the Sponsored Vehicles buy-in). Please refer to Note 20 - Noncontrolling Interests for further discussion of the transactions.

ACQUISITION OF SPECTRA ENERGY CORP

On February 27, 2017, Enbridge and Spectra Energy Corp (Spectra Energy) combined in a stock-for-stock merger transaction (the Merger Transaction) for a purchase price of $37.5 billion. Under the terms of the Merger Transaction, Spectra Energy shareholders received 0.984 shares of Enbridge common stock for each share of Spectra Energy common stock that they owned, resulting in us acquiring 100% ownership of Spectra Energy. Please refer to Note 8 - Acquisitions and Dispositions for further discussion of the transaction.

DISPOSITIONS

During the years ended December 31, 2018 and 2017, we have disposed of a number of our non-core assets. Please refer to Note 8 - Acquisitions and Dispositions for further discussion of these transactions.

2. 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 (SEC) registrant, we are permitted to use U.S. GAAP for purposes of meeting both our 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 7); purchase price allocations (Note 8); unbilled revenues; depreciation rates and carrying value of property, plant and equipment(Note 11); amortization rates of intangible assets(Note 15); measurement of goodwill(Note 16); 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 29);and estimates of losses related to environmental remediation obligations(Note 29). Actual results could differ from these estimates.

Certain comparative figures in our Consolidated Statements of Cash Flows have been reclassified to conform to the current year's presentation. Effective September 30, 2017, we combined Cash and cash equivalents and amounts previously presented as Bank indebtedness where the corresponding bank accounts are subject to cash pooling arrangements. Net cash provided by financing activities in the Consolidated Statements of Cash Flows for the year ended December 31, 2016 have decreased by $0.3 billion to reflect this change.

PRINCIPLES OF CONSOLIDATION

The consolidated financial statements include our accounts and accounts of our subsidiaries and variable interest entities (VIEs) for which we are 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

8

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, we perform 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 we conclude that we are the primary beneficiary of a VIE, we consolidate the accounts of that VIE. We assess all variable interests in the entity and use our judgment when determining if we are 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. We assess the primary beneficiary determination for a VIE on an ongoing basis, if 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 we represent the general partner and, based on all facts and circumstances, control such limited partnerships, unless the limited partner has substantive participating rights or substantive kick-out rights. For certain investments where we retain an undivided interest in assets and liabilities, we record our proportionate share of assets, liabilities, revenues and expenses. If an entity is determined to not be a VIE, the voting interest entity model is applied, where an investor holding the majority voting rights consolidates the entity.

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 we exercise significant influence are accounted for using the equity method.

As a result of the Canadian Restructuring Plan, ECT, our subsidiary, 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 for comparative periods. Redeemable noncontrolling interests on the Consolidated Statements of Financial Position as at December 31, 2017 are recognized at the maximum redemption value of the trust units held by third parties, which references the market price of ENF common shares.

REGULATION

Certain parts of our 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 (NBEUB), the Ontario Energy Board (OEB) and La Régie de l’Energie du Québec.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 underU.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

9

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 we identify 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 our expectations, the timing and amount of recovery or settlement of regulatory balances could differ significantly from those recorded. In the absence of rate regulation, we 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, we 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 7).

With the approval of the applicable regulator, EGD, Union Gas 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 our 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. We recognize 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 Enbridge to provide transportation services for the life of the underlying producing fields. Under these arrangements, shippers pay Enbridge 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.

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Fixed monthly toll revenues are recognized ratably over the committed volume made available to shippers throughout the contract period, regardless of when cash is received. For the years ended December 31, 2018, 2017 and 2016, cash received net of revenue recognized for contracts under make-up rights and similar deferred revenue arrangements was $208 million, $196 million, and $249 million, respectively.

For rate-regulated businesses, revenues are recognized in a manner that is consistent with the underlying agreements as approved by the regulators. 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 our distribution franchise area. Since July 1, 2011, 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, we prospectively discontinued the application of rate-regulated accounting for those assets with the exception of flow-through income taxes covered by specific rate orders.

Our Energy Services segment enters into commodity purchase and sale arrangements that are recorded gross because the related contracts are not held for trading purposes and we are acting as the principal in the transactions. For our energy marketing contracts, 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.

Derivatives in Qualifying Hedging Relationships

We use derivative financial instruments to manage our exposure to changes in commodity prices, foreign exchange rates, interest rates and certain compensation tied to our share price. Hedge accounting is optional and requires Enbridge 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. We present the earnings effects of hedging items with the hedged transaction. Derivatives in qualifying hedging relationships are categorized as cash flow hedges, fair value hedges or net investment hedges.

Cash Flow Hedges

We use cash flow hedges to manage our exposure to changes in commodity prices, foreign exchange rates, interest rates and certain compensation tied to our 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.

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Fair Value Hedges

We use fair value hedges to hedge the fair value of debt instruments. 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 Enbridge’s Canadian dollar presentation currency are included in cumulative translation adjustments (CTA). We designate 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

We recognize the fair market value of derivative instruments on the Consolidated Statements of Financial Position as current and non-current 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 we have 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. We incur transaction costs primarily from the issuance of debt and account for these costs as a deduction from Long-term debt on the Statements of Financial Position. 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 we exercise significant influence, but do not have controlling financial interests, are accounted for using the equity method. Equity investments are initially measured at cost and are adjusted for our 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, we capitalize 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, we classify equity investments in entities over which we do not exercise significant influence and that do not have readily determinable fair values as other investments measured at fair value

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measurement alternative and recorded at cost minus impairment, if any, plus or minus changes resulting from observable price changes in orderly transactions for an identical or similar investment of the same issuer. Investments in equity securities measured using the fair value measurement alternative are reviewed for impairment each reporting period. Equity investments with readily determinable fair values are measured at fair value through net income. Dividends received from investments in equity securities are recognized in earnings when the right to receive payment is established.

Investments in debt securities are classified either as available for sale securities measured at fair value through OCI or as held to maturity securities measured at amortized cost.

NONCONTROLLING INTERESTS

Noncontrolling interests represent ownership interests attributable to third parties in certain consolidated subsidiaries. The portion of equity not owned by us 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 as at December 31, 2017, within the mezzanine section of the Consolidated Statements of Financial Position between long-term liabilities and equity.

Enbridge Income Fund (The Fund)'s noncontrolling interest holders had the option to redeem the Fund trust units for cash, subject to certain limitations. Redeemable noncontrolling interests as at December 31, 2017 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 and up until redeemable noncontrolling interest repurchase date, 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 our Consolidated Statements of Earnings for comparative periods.

INCOME TAXES

Income taxes are accounted for using the liability method. 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 our regulated operations, a deferred income tax liability or asset is recognized with a corresponding regulatory asset or liability, respectively, 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 Enbridge 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.

Gains and losses arising from translation of foreign operations’ functional currencies to our 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.

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CASH AND CASH EQUIVALENTS

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

RESTRICTED CASH

Cash and cash equivalents that are restricted 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 we have 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.

NATURAL GAS IMBALANCES

The Consolidated Statements of Financial Position include in-kind balances as a result of differences in gas volumes received and delivered for customers. Since settlement of certain imbalances is in-kind, changes in the balances do not have an effect on our Consolidated Statements of Earnings or Consolidated Statements of Cash Flows. Most natural gas volumes owed to or by us are valued at natural gas market index prices as at the balance sheet dates.

INVENTORY

Inventory is comprised of natural gas in storage held in EGD and Union Gas, and crude oil and natural gas held primarily by energy services businesses in the Energy Services segment. Natural gas in storage in EGD and Union Gas 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. We capitalize 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 generally not reflected in earnings but are booked as an adjustment to accumulated depreciation.

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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.

INTANGIBLE ASSETS

Intangible assets consist primarily of certain software costs, customer relationships and emission allowances. We capitalize costs incurred during the application development stage of internal use software projects. Customer relationships represent the underlying relationship from long-term agreements with customers that are capitalized upon acquisition. From January 1, 2017 through July 3, 2018, emission allowances, which are recorded at their original cost, were purchased in order to meet greenhouse gas (GHG) compliance obligations. Intangible assets are generally amortized on a straight-line basis over their expected lives, commencing when the asset is available for use, with the exception of emission allowances, which are not amortized as they will be used to satisfy compliance obligations as they come due.

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. We perform our annual review of the goodwill balance on April 1.

We perform our annual review for impairment at the reporting unit level, which is identified by assessing whether the components of our operating segments constitute businesses for which discrete information is available, whether segment management regularly reviews the operating results of those components and whether the economic and regulatory characteristics are similar. We determined that our reporting units are equivalent to our reportable segments, with the exception of the gas transmission and gas midstream reportable segment which is divided at the component level into two reporting units. We have the option to first assess qualitative factors to determine whether it is necessary to perform the quantitative goodwill impairment test. The quantitative goodwill impairment test involves determining the fair value of our reporting units 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 at the amount by which the reporting unit’s carrying value exceeds its fair value. This amount should not exceed the carrying amount of goodwill.

The allocation of goodwill to held for sale and disposed businesses is based on the relative fair value of businesses included in the particular reporting unit. Fair value of our reporting unit is estimated using a combination of discounted cash flow model and earnings multiples techniques. The determination of fair value using the discounted cash flow model technique requires the use of estimates and assumptions related to discount rates, projected operating income, terminal value growth rates, capital expenditures and working capital levels. The cash flow projections included significant judgments and assumptions relating to revenue growth rates and expected future capital expenditure. The determination of fair value using the earnings multiples technique requires assumptions to be made in relation to maintainable earnings and earnings multipliers for reporting units.

IMPAIRMENT

We review the carrying values of our 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, we calculate fair value based on the discounted cash flows and write the assets down to the extent that the carrying value exceeds the fair value.

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With respect to investments in debt securities, we assess 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 objective evidence of impairment, we value the expected discounted cash flows using observable market inputs and determine 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, we assess the assets for impairment when there is no longer reasonable assurance of timely collection. If evidence of impairment is noted, we reduce 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. Our estimates of retirement costs could change as a result of changes in cost estimates and regulatory requirements.

RETIREMENT AND POSTRETIREMENT BENEFITS

We maintain 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.

We use mortality tables issued by the Society of Actuaries in the United States (revised in 2018) and the Canadian Institute of Actuaries tables (revised in 2014) to measure our benefit obligations of our United States pension plan (the United States Plan) and our Canadian pension plans (the Canadian Plans), respectively. We determine discount rates by reference to rates of high-quality long-term corporate bonds with maturities that approximate the timing of future payments we anticipate 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.

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

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

The overfunded or underfunded status of defined benefit pension and OPEB plans is recognized as Deferred amounts and other assets, 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 Enbridge 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.

Restricted Stock Units (RSU) are cash settled awards for which the related liability is remeasured each reporting period. RSUs 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 Enbridge’s shares with an offset to Accounts payable and other or to Other long-term liabilities.

COMMITMENTS, CONTINGENCIES AND ENVIRONMENTAL LIABILITIES

We expense or capitalize, as appropriate, expenditures for ongoing compliance with environmental regulations that relate to past or current operations. We expense costs incurred for remediation of existing environmental contamination caused by past operations that do not benefit future periods by preventing or eliminating future contamination. We record 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. Our 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. We evaluate recoveries from insurance coverage separately from the liability and, when recovery is probable, we record and report an asset separately from the associated liability in the Consolidated Statements of Financial Position.

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Liabilities for other commitments and contingencies are recognized when, after fully analyzing available information, we determine 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, we recognize the most likely amount, or if no amount is more likely than another, the minimum of the range of probable loss is accrued. We expense legal costs associated with loss contingencies as such costs are incurred.

3.  CHANGES IN ACCOUNTING POLICIES

CHANGES IN ACCOUNTING POLICIES

There were no changes in accounting policies during the year ended December 31, 2018.

ADOPTION OF NEW ACCOUNTING STANDARDS

Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income

Effective January 1, 2018, we adopted Accounting Standards Update (ASU) 2018-02 to address a specific consequence of the Tax Cuts and Jobs Act (TCJA or United States Tax Reform) enacted by the United States federal government on December 22, 2017. The amendments in this accounting update allowed a reclassification from accumulated other comprehensive income (AOCI) to retained earnings for stranded tax effects resulting from the TCJA. The amendments eliminated the stranded tax effects recognized as a result of the reduction of the historical United States federal corporate income tax rate to the newly enacted United States federal corporate income tax rate. The adoption of this accounting update did not have a material impact on our consolidated financial statements.

Clarifying Guidance on the Application of Modification Accounting on Stock Compensation

Effective January 1, 2018, we adopted ASU 2017-09 and applied the standard on a prospective basis. The new standard was issued to clarify the scope of modification accounting. Under the new guidance, modification accounting is required for all changes to share-based payment awards, unless all of the following conditions are met: 1) there is no change to the fair value of the award, 2) the vesting conditions have not changed, and 3) the classification of the award as an equity instrument or a debt instrument has not changed. The adoption of this accounting update did not, and is not expected to have a material impact on our consolidated financial statements.

Improving the Presentation of Net Periodic Benefit Cost related to Defined Benefit Plans

Effective January 1, 2018, we adopted ASU 2017-07 which was issued primarily to improve the income statement presentation of the components of net periodic pension cost and net periodic postretirement benefit cost for an entity’s sponsored defined benefit pension and other postretirement plans. Upon adoption of this accounting update, our Consolidated Statements of Earnings presents the current service cost within Operating and administrative expenses and the other components of net benefit cost within Other income/(expense). Previously, all components of net benefit cost were presented within Operating and administrative expenses. In addition, only the service cost component of net benefit cost will be capitalized on a prospective basis. The adoption of this accounting update did not, and is not expected to have a material impact on our consolidated financial statements.

Clarifying Guidance on Derecognition and Partial Sales of Nonfinancial Assets

Effective January 1, 2018, we adopted ASU 2017-05 on a modified retrospective basis. The new standard clarifies the scope provisions of nonfinancial assets and how to allocate consideration to each distinct asset, and amends the guidance for derecognition of a distinct nonfinancial asset in partial sale transactions. The adoption of this accounting update did not have a material impact on our consolidated financial statements.

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

Effective January 1, 2018, we adopted ASU 2016-18 on a retrospective basis. The new standard clarifies guidance on the classification and presentation of changes in restricted cash and restricted cash

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equivalents within the statement of cash flows. The amendments require that changes in restricted cash and restricted cash equivalents be included within cash and cash equivalents when reconciling the opening and closing period amounts shown on the statement of cash flows. For current and comparative periods, we amended the presentation in the Consolidated Statements of Cash Flows to include restricted cash and restricted cash equivalents with cash and cash equivalents.

Simplifying Cash Flow Classification

Effective January 1, 2018, we adopted ASU 2016-15 on a retrospective basis. The new standard reduces 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. We assessed each of the eight specific presentation issues and the adoption of this ASU did not have a material impact on our consolidated financial statements.

Recognition and Measurement of Financial Assets and Liabilities

Effective January 1, 2018, we adopted ASU 2016-01 on a prospective basis. The new standard addresses certain aspects of recognition, measurement, presentation and disclosure of financial assets and liabilities. Investments in equity securities, excluding equity method and consolidated investments, are no longer classified as trading or available-for-sale securities. All investments in equity securities with readily determinable fair values are classified as investments at fair value through net income. Investments in equity securities without readily determinable fair values are measured using the fair value measurement alternative and are recorded at cost minus impairment, if any, plus or minus changes resulting from observable price changes in orderly transactions for an identical or similar investment of the same issuer. Investments in equity securities measured using the fair value measurement alternative are reviewed for indicators of impairment each reporting period. Fair value of financial assets and liabilities is measured using the exit price notion. The adoption of this accounting update did not have a material impact on our consolidated financial statements.

Revenue from Contracts with Customers

Effective January 1, 2018, we adopted ASU 2014-09 on a modified retrospective basis to contracts that were not complete at the date of initial application. The new standard was issued 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. It also requires the use of more estimates and judgments than the previous standards.

In adopting Accounting Standards Codification (ASC) 606, we applied the practical expedient for contract modifications whereby contracts that were modified before January 1, 2018 were not retrospectively restated. Instead, the aggregate effect of all contract modifications occurring before that time has been reflected when identifying satisfied and unsatisfied performance obligations, determining the transaction price and allocating the transaction price to satisfied and unsatisfied performance obligations.

Revenue was previously recognized for a certain contract within the Liquids Pipelines business unit using a formula-based method. Under the new revenue standard, revenue is recognized on a straight-line basis over the term of the agreement in order to reflect the fulfillment of our performance obligation to provide up to a specified volume of pipeline capacity throughout the term of the contract.

Certain payments received from customers to offset the cost of constructing assets required to provide services to those customers, referred to as Contributions in Aid of Construction (CIACs) were previously recorded as reductions of property, plant and equipment regardless of whether the amounts were imposed by regulation or arose from negotiations with customers. Under the new revenue standard, CIACs which are negotiated as part of an agreement to provide transportation and other services to a customer are deemed to be advance payments for future services and are recognized as revenue when those future services are provided. Accordingly, negotiated CIACs are accounted for as deferred revenue and recognized as revenue over the term of the associated revenue contract. Amounts which are required

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to be collected from the customer based on requirements of the regulator continue to be accounted for as reductions of property, plant and equipment.

The below table presents the cumulative, immaterial effect of the adoption of ASC 606 on our Consolidated Statement of Financial Position as at January 1, 2018 on each affected financial statement line item. For the year ended December 31, 2018, the effect of the adoption of ASC 606 on our Consolidated Statement of Earnings was not material.

	Balance at December 31, 2017		Adjustments Due to ASC 606		Balance at January 1, 2018
(millions of Canadian dollars)
Assets
Deferred amounts and other assets	6,442		(170	)	6,272
Property, plant and equipment, net	90,711		112		90,823
Liabilities and equity
Accounts payable and other	9,478		62		9,540
Other long-term liabilities	7,510		66		7,576
Deferred income taxes	9,295		(62	)	9,233
Redeemable noncontrolling interests	4,067		(38	)	4,029
Deficit	(2,468	)	(86	)	(2,554	)

The following ASU’s have been issued, but not yet adopted.

Clarifying Interaction between Collaborative Arrangements and Revenue from Contracts with Customers

In November 2018, ASU 2018-18 was issued to provide clarity on when transactions between entities in a collaborative arrangement should be accounted for under the new revenue standard, ASC 606. In determining whether transactions in collaborative arrangements should be accounted under the revenue standard, the update specifies that entities shall apply unit of account guidance to identify distinct goods or services and whether such goods and services are separately identifiable from other promises in the contract. ASU 2018-18 also precludes entities from presenting transactions with a collaborative partner which are not in scope of the new revenue standard together with revenue from contracts with customers. The accounting update is effective January 1, 2020 and early adoption is permitted. We are currently assessing the impact of the new standard on our consolidated financial statements.

Improvements to Related Party Guidance for Variable Interest Entities

ASU 2018-17 was issued in October 2018 to improve the related party guidance on determining whether fees paid to decision makers and service providers (“decision-maker fees”) are variable interests. Under the new guidance, reporting entities must consider indirect interests held through related parties in common control arrangements on a proportionate basis, rather than as the equivalent of a direct interest in its entirety, when determining if a decision maker’s fees constitute a variable interest. The accounting update is effective January 1, 2020 and must be applied on a retrospective basis. We are currently assessing the impact of the new standard on our consolidated financial statements.

Amended Guidance on Cloud Computing Arrangements

In August 2018, ASU 2018-15 was issued to provide guidance on the accounting for implementation costs incurred in a cloud computing arrangement (CCA) that is a service contract. The amendment aligns the accounting for costs incurred to implement a CCA that is a service arrangement with the guidance on capitalizing costs associated with developing or obtaining internal-use software. Additionally, ASU 2018-15 specifies that an entity would apply ASC 350-40, Internal-use software, to determine which implementation costs related to a hosting arrangement that is a service contract should be capitalized and which should be expensed. Furthermore, the amendments in the update require capitalized costs be amortized on a straight-line basis generally over the term of the arrangement and presented in the same

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income statement line as fees paid for the hosting service. The new standard also requires that the balance sheet presentation of capitalized implementation costs to be the same as that of the prepayment of fees related to the hosting arrangement, as well as similar consistency in classifications from a cash flow statement perspective. ASU 2018-15 is effective January 1, 2020 and we have elected to early adopt the standard as of January 1, 2019, as permitted. We do not expect the adoption of this accounting update to have a material impact on our consolidated financial statements.

Disclosure Effectiveness

In August 2018, the Financial Accounting Standards Board issued two amendments as a part of its disclosure framework project aimed to improve the effectiveness of disclosures in the notes to financial statements.

ASU 2018-14 was issued in August 2018 to improve disclosure requirements for employers that sponsor defined benefit pension or other postretirement plans. The amendment modifies the current guidance by adding and removing several disclosure requirements while also clarifying the guidance on current disclosure requirements. ASU 2018-14 is effective January 1, 2021 and entities are permitted to adopt the standard early. We are currently assessing the impact of the new standard on our consolidated financial statements.

ASU 2018-13 was issued to improve the disclosure requirements for fair value measurements by eliminating and modifying some disclosures, while also adding new disclosures. This update is effective January 1, 2020, however entities are permitted to early adopt the eliminated or modified disclosures. We are currently assessing the impact of the new standard on our consolidated financial statements.

Improvements to Accounting for Hedging Activities

ASU 2017-12 was issued in August 2017 with the objective of better aligning a company’s risk management activities and the resulting hedge accounting reflected in the financial statements. The amendments allow cash flow hedging of contractually specified components in financial and non-financial items. Under the new guidance, hedge ineffectiveness is no longer required to be measured and hedging instruments’ fair value changes will be recorded in the same income statement line as the hedged item. The ASU also allows the initial quantitative hedge effectiveness assessment to be performed at any time before the end of the quarter in which the hedge is designated. After initial quantitative testing is performed, an ongoing qualitative effectiveness assessment is permitted. The accounting update is effective January 1, 2019, with early adoption permitted, and is to be applied on a modified retrospective basis. Based upon our current assessment, we do not expect the standard to have a material impact on our consolidated financial statements.

In October 2018, ASU 2018-16 was issued to permit the use of the Overnight Index Swap rate based on the Secured Overnight Financing Rate as a U.S. benchmark interest rate for hedge accounting purposes. ASU 2018-16 is effective concurrently with ASU 2017-12.

Amending the Amortization Period for Certain Callable Debt Securities Purchased at a Premium

ASU 2017-08 was issued in March 2017 with the intent of shortening the amortization period to the earliest call date for certain callable debt securities held at a premium. The accounting update is effective January 1, 2019 and will be applied on a modified retrospective basis. We do not expect the adoption of this accounting update to have a material impact on our consolidated financial statements.

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 accounting update adds a new impairment model, known as the current expected credit loss model, which is based on expected losses rather than incurred losses. Under the new guidance, an

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entity will recognize 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.

Further, ASU 2018-19 was issued in November 2018 to clarify that operating lease receivables should be accounted for under the new leases standard, ASC 842, and are not within the scope of ASC 326, Financial Instrument - Credit Losses. Both accounting updates are effective January 1, 2020. We are currently assessing the impact of the new standard on our consolidated financial statements.

Recognition of Leases 

ASU 2016-02 was issued in February 2016 with the intent to increase transparency and comparability among organizations. It requires lessees of operating lease arrangements to recognize lease assets and lease liabilities on the statements of financial position and disclose additional key information about lease agreements. The accounting update also replaces the current definition of a lease and requires that an arrangement be recognized as a lease when a customer has the right to obtain substantially all of the economic benefits from the use of an asset, as well as the right to direct the use of the asset. The new standard became effective January 1, 2019 and in adopting ASC 842, we have applied the package of practical expedients offered in connection with this update. Application of the package of practical expedients permits entities not to reassess a) whether any expired or existing contracts contain leases in accordance with the new guidance, b) lease classifications, and c) whether initial direct costs capitalized under current guidance continue to meet the definition of initial direct costs under the new guidance. Under the new lease guidance, we have also decided to elect, by class of underlying asset, to not separate non-lease components from the associated lease components of our lessee contract and account for both components as a single lease component.

ASU 2018-01 was issued in January 2018 to address stakeholder concerns about the costs and complexity of complying with the transition provisions of the new lease requirements as they relate to land easements. The amendments provide an optional transition practical expedient to not evaluate existing or expired land easements that were not previously accounted for as leases under existing guidance. We have elected this practical expedient in connection with the adoption of the new lease requirements. 

In July 2018, ASU 2018-11 was issued to address additional stakeholder concerns regarding the unanticipated costs and complexities associated with the modified retrospective transition method as well as the requirement for lessors to separate components of a contract. Under the new guidance, entities are provided with an additional transition method which allows entities to apply the new standard at the date of adoption and to elect not to recast comparative periods presented. This amendment also permits lessors to combine associated lease and non-lease components within a contract for operating leases when certain conditions are met.  We have elected both of these practical expedients in the adoption of the new lease standard.

We have identified all lease contracts existing as at November 30, 2018 and have performed detailed evaluations of those lease contracts under the requirements of the transitional guidance. We estimate that we will recognize right-of-use lease assets and related lease liabilities for existing operating leases where we are the lessee in the range of $750 million to $900 million, with no impact to our Consolidated Statements of Earnings or Consolidated Statements of Cash Flows. This estimate represents the net present value of future lease payments payable under operating lease contracts we had entered into as at November 30, 2018, and that have commenced or are scheduled to commence by January 1, 2019. We do not expect any adjustments will be made to our accounting for existing lessor contracts as a result of implementing this new standard.

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4. REVENUE

REVENUE FROM CONTRACTS WITH CUSTOMERS

Major Products and Services

	Liquids Pipelines		Gas Transmission and Midstream	Gas Distribution	Green Power and Transmission	Energy Services	Eliminations and Other		Consolidated
Year ended December 31, 2018
(millions of Canadian dollars)
Transportation revenue	8,488		3,928	875	—	—	—		13,291
Storage and other revenue	101		222	196	—	—	—		519
Gas gathering and processing revenue	—		815	—	—	—	—		815
Gas distribution revenue	—		—	4,376	—	—	—		4,376
Electricity and transmission revenue	—		—	—	559	—	—		559
Commodity sales	—		1,590	—	—	—	—		1,590
Total revenue from contracts with customers	8,589		6,555	5,447	559	—	—		21,150
Commodity sales	—		—	—	—	26,070	—		26,070
Other revenue1	(894	)	6	9	8	4	25		(842	)
Intersegment revenue	384		10	14	—	154	(562	)	—
Total revenue	8,079		6,571	5,470	567	26,228	(537	)	46,378

1  Includes mark-to-market gains/(losses) from our hedging program.

We disaggregate revenue into categories which represent our principal performance obligations within each business segment because these revenue categories represent the most significant revenue streams in each segment and consequently are considered to be the most relevant revenue information for management to consider in evaluating performance.

Contract Balances

	Receivables	Contract Assets	Contract Liabilities
(millions of Canadian dollars)
Balance as at January 1, 2018	2,475	290	992
Balance as at December 31, 2018	1,929	191	1,245

Contract receivables represent the amount of receivables derived from contracts with customers. The decrease in contract receivables for the year ended December 31, 2018, is primarily attributed to the sale of Midcoast Operating, L.P. and its subsidiaries to AL Midcoast Holdings, LLC (an affiliate of ArcLight Capital Partners, LLC), refer to Note 8 - Acquisitions and Dispositions for further discussion.

Contract assets represent the amount of revenue which has been recognized in advance of payments received for performance obligations we have fulfilled (or partially fulfilled) and prior to the point in time at which our right to the payment is unconditional. Amounts included in contract assets are transferred to accounts receivable when our right to the consideration becomes unconditional.

Contract liabilities represent payments received for performance obligations which have not been fulfilled. Contract liabilities primarily relate to make-up rights and deferred revenue. Revenue recognized during the year ended December 31, 2018 included in contract liabilities at the beginning of the period is $183 million. Increases in contract liabilities from cash received, net of amounts recognized as revenue during the year ended December 31, 2018 were $449 million.

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Performance Obligations

Segment	Nature of Performance Obligation
Liquids Pipelines	• Transportation and storage of crude oil and NGLs
Gas Transmission and Midstream	• Sale of crude oil, natural gas and NGLs
	• Transportation, storage, gathering, compression and treating of natural gas
	• Transportation of NGLs
Gas Distribution	• Supply and delivery of natural gas
	• Transportation of natural gas
	• Storage of natural gas
Green Power and Transmission	• Generation and transmission of electricity
	• Delivery of electricity from renewable energy generation facilities

There was no material revenue recognized in the year ended December 31, 2018 from performance obligations satisfied in previous periods.

Payment Terms

Payments are received monthly from customers under long-term transportation, commodity sales, and gas gathering and processing contracts. Payments from Gas Distribution customers are received on a continuous basis based on established billing cycles.

Certain contracts in the United States offshore business provide for us to receive a series of fixed monthly payments (FMPs) for a specified period which is less than the period during which the performance obligations are satisfied. As a result, a portion of the FMPs is recorded as a contract liability. The FMPs are not considered to be a financing arrangement because the payments are scheduled to match the production profiles of offshore oil and gas fields, which generate greater revenue in the initial years of their productive lives.

Revenue to be Recognized from Unfulfilled Performance Obligations

Total revenue from performance obligations expected to be fulfilled in future periods is $67.4 billion, of which $7.1 billion is expected to be recognized during the year ending December 31, 2019.

The revenues excluded from the amounts above based on optional exemptions available under ASC 606, as explained below, represent a significant portion of our overall revenues and revenues from contracts with customers. Certain revenues such as flow-through operating costs charged to shippers are recognized at the amount for which we have the right to invoice our customers and are excluded from the amounts for revenue to be recognized in the future from unfulfilled performance obligations above. Variable consideration is excluded from the amounts above due to the uncertainty of the associated consideration, which is generally resolved when actual volumes and prices are determined. For example, we consider interruptible transportation service revenues to be variable revenues since volumes cannot be estimated. Additionally, the effect of escalation on certain tolls which are contractually escalated for inflation has not been reflected in the amounts above as it is not possible to reliably estimate future inflation rates. Revenues for periods extending beyond the current rate settlement term for regulated contracts where the tolls are periodically reset by the regulator are excluded from the amounts above since future tolls remain unknown. Finally, revenues from contracts with customers which have an original expected duration of one year or less are excluded from the amounts above.

SIGNIFICANT JUDGMENTS MADE IN RECOGNIZING REVENUE

Long-Term Transportation Agreements

For long-term transportation agreements, significant judgments pertain to the period over which revenue is recognized and whether the agreement provides for make-up rights for the shippers. Transportation revenue earned from firm contracted capacity arrangements is recognized ratably over the contract

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period. Transportation revenue from interruptible or volumetric-based arrangements is recognized when services are performed.

Estimates of Variable Consideration

Revenue from arrangements subject to variable consideration is recognized only to the extent that it is probable that a significant reversal in the amount of cumulative revenue recognized will not occur when the uncertainty associated with the variable consideration is subsequently resolved. Uncertainties associated with variable consideration relate principally to differences between estimated and actual volumes and prices. These uncertainties are resolved each month when actual volumes are sold or transported and actual tolls and prices are determined.

Recognition and Measurement of Revenue

	Liquids Pipelines	Gas Transmission and Midstream	Gas Distribution	Green Power and Transmission	Energy Services	Consolidated
Year ended December 31, 2018
(millions of Canadian dollars)
Revenue from products transferred at a point in time1	—	1,590	68	—	—	1,658
Revenue from products and services transferred over time2	8,589	4,965	5,379	559	—	19,492
Total revenue from contracts with customers	8,589	6,555	5,447	559	—	21,150

1 Revenue from sales of crude oil, natural gas and NGLs.

2 Revenue from crude oil and natural gas pipeline transportation, storage, natural gas gathering, compression and treating, natural gas distribution, natural gas storage services and electricity sales.

Performance Obligations Satisfied at a Point in Time

Revenue from commodity sales where the commodity sold is not immediately consumed prior to use is recognized at the point in time when the contractually specified volume of the commodity has been delivered, as control over the commodity transfers to the customer upon delivery.

Performance Obligations Satisfied Over Time

For arrangements involving the transportation and sale of petroleum products and natural gas where the transportation services or commodities are simultaneously received and consumed by the shipper or customer, we recognize revenue over time using an output method based on volumes of commodities delivered or transported. The measurement of the volumes transported or delivered corresponds directly to the benefits received by the shippers or customers during that period.

Determination of Transaction Prices

Prices for gas processing and transportation services are determined based on the capital cost of the facilities, pipelines and associated infrastructure required to provide such services plus a rate of return on capital invested that is determined either through negotiations with customers or through regulatory processes for those operations that are subject to rate regulation.

Prices for commodities sold are determined by reference to market price indices plus or minus a negotiated differential and in certain cases a marketing fee.

Prices for natural gas sold and distribution services provided by regulated natural gas distribution operations are prescribed by regulation.

5.  SEGMENTED INFORMATION

Segmented information for the years ended December 31, 2018, 2017 and 2016 are as follows:

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Year ended December 31, 2018	Liquids Pipelines		Gas Transmission and Midstream		Gas Distribution		Green Power and Transmission		Energy Services		Eliminations and Other		Consolidated
(millions of Canadian dollars)
Revenues	8,079		6,571		5,470		567		26,228		(537	)	46,378
Commodity and gas distribution costs	(16	)	(1,481	)	(2,748	)	(7	)	(25,689	)	540		(29,401	)
Operating and administrative	(3,124	)	(2,102	)	(1,111	)	(157	)	(73	)	(225	)	(6,792	)
Impairment of long-lived assets	(180	)	(914	)	—		(4	)	—		(6	)	(1,104	)
Impairment of goodwill	—		(1,019	)	—		—		—		—		(1,019	)
Income/(loss) from equity investments	577		930		11		(28	)	18		1		1,509
Other income/(expense)	(5	)	349		89		(2	)	(2	)	(481	)	(52	)
Earnings/(loss) before interest, income tax expense, and depreciation and amortization	5,331		2,334		1,711		369		482		(708	)	9,519
Depreciation and amortization													(3,246	)
Interest expense													(2,703	)
Income tax expense													(237	)
Earnings													3,333
Capital expenditures1	3,102		2,644		1,066		33		—		27		6,872
Total assets	68,798		60,559		25,748		5,716		1,042		5,042		166,905

Year ended December 31, 2017	Liquids Pipelines		Gas Transmission and Midstream		Gas Distribution		Green Power and Transmission		Energy Services		Eliminations and Other		Consolidated
(millions of Canadian dollars)
Revenues	8,913		7,067		4,992		534		23,282		(410	)	44,378
Commodity and gas distribution costs	(18	)	(2,834	)	(2,689	)	—		(23,508	)	412		(28,637	)
Operating and administrative	(2,949	)	(1,756	)	(960	)	(163	)	(47	)	(567	)	(6,442	)
Impairment of long-lived assets	—		(4,463	)	—		—		—		—		(4,463	)
Impairment of goodwill	—		(102	)	—		—		—		—		(102	)
Income/(loss) from equity investments	416		653		23		6		8		(4	)	1,102
Other income/(expense)	33		166		24		(5	)	2		232		452
Earnings/(loss) before interest, income tax expense, and depreciation and amortization	6,395		(1,269	)	1,390		372		(263	)	(337	)	6,288
Depreciation and amortization													(3,163	)
Interest expense													(2,556	)
Income tax recovery													2,697
Earnings													3,266
Capital expenditures1	2,799		4,016		1,177		321		1		108		8,422
Total assets	63,881		60,745		25,956		6,289		2,514		2,708		162,093

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Year ended December 31, 2016	Liquids Pipelines		Gas Transmission and Midstream		Gas Distribution		Green Power and Transmission		Energy Services		Eliminations and Other		Consolidated
(millions of Canadian dollars)
Revenues	8,176		2,877		2,976		502		20,364		(335	)	34,560
Commodity and gas distribution costs	(12	)	(2,206	)	(1,653	)	5		(20,473	)	334		(24,005	)
Operating and administrative	(2,908	)	(446	)	(553	)	(173	)	(63	)	(215	)	(4,358	)
Impairment of long-lived assets	(1,365	)	(11	)	—		—		—		—		(1,376	)
Income/(loss) from equity investments	194		223		12		2		(3	)	—		428
Other income/(expense)	841		27		49		8		(8	)	115		1,032
Earnings/(loss) before interest, income tax expense, and depreciation and amortization	4,926		464		831		344		(183	)	(101	)	6,281
Depreciation and amortization													(2,240	)
Interest expense													(1,590	)
Income tax expense													(142	)
Earnings													2,309
Capital expenditures1	3,957		176		713		251		—		32		5,129

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).

No non-affiliated customer exceeds 10% of our third-party revenues for the year ended December 31, 2018. Our largest non-affiliated customer accounted for approximately 11.8%, and 18.0% of our third-party revenues for the years ended December 31, 2017 and 2016, respectively. A second customer accounted for approximately 10.4% of our third-party revenues for the year ended December 31, 2016. Revenues from these two customers are primarily reported in the Energy Services segment.

GEOGRAPHIC INFORMATION

Revenues¹ 

Year ended December 31,	2018	2017	2016
(millions of Canadian dollars)
Canada	19,023	18,076	12,470
United States	27,355	26,302	22,090
	46,378	44,378	34,560

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

Property, Plant and Equipment¹ 

December 31,	2018	2017
(millions of Canadian dollars)
Canada	44,716	46,025
United States	49,824	44,686
	94,540	90,711

1Amounts are based on the location where the assets are held.

6.  EARNINGS PER COMMON SHARE

BASIC

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 our pro-rata weighted average interest in our own common shares of 12 million as at December 31, 2018, and 13 million as at December 31, 2017 and 2016, resulting from our reciprocal investment in Noverco.

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DILUTED

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.

Weighted average shares outstanding used to calculate basic and diluted earnings per share are as follows:

December 31,	2018	2017	2016
(number of shares in millions)
Weighted average shares outstanding	1,724	1,525	911
Effect of dilutive options	3	7	7
Diluted weighted average shares outstanding	1,727	1,532	918

For the years ended December 31, 2018, 2017 and 2016, 26,837,822, 14,271,615 and 10,803,672, respectively, of anti-dilutive stock options with a weighted average exercise price of $50.38, $56.71 and $52.92, respectively, were excluded from the diluted earnings per common share calculation.

7.  REGULATORY MATTERS

GENERAL INFORMATION ON RATE REGULATION AND ITS ECONOMIC EFFECTS

We record assets and liabilities that result from the regulated ratemaking process that would not be recorded under GAAP for non-regulated entities. See Note 2 - Significant Accounting Policies for further discussion.

A number of our businesses are subject to regulation by the NEB. We also collect and set 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 14). Amounts expected to be paid to cover future abandonment costs are recognized as long-term regulatory liabilities. Our 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.

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Southern Lights Pipeline

The United States portion of the Southern Lights Pipeline is regulated by the FERC and the Canadian portion of the Southern Lights Pipeline 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 Transmission and Midstream

British Columbia (BC) Pipeline and BC Field Services

Under the current NEB-authorized rate structure for BC Pipeline, income tax costs are recovered in tolls based on the current income tax payable and do not include accruals for deferred income tax. However, as income taxes become payable as a result of the reversal of the temporary differences that created the deferred income taxes, it is expected that tolls will be adjusted to recover these taxes. Since most of these temporary differences are related to property, plant and equipment costs, this recovery is expected to occur over the life of those assets.

On July 4, 2018, we entered into agreements to sell our Canadian natural gas gathering and processing businesses (Note 8). On October 1, 2018, we closed the sale of the provincially regulated facilities. The sale of the federally regulated facilities is expected to close in mid-2019.

Spectra Energy Partners, LP

SEP's gas transmission and storage services are regulated by the FERC. Current rates are governed by the applicable FERC-approved natural gas tariff while fee-based gathering services are governed by the applicable state oil and gas commissions.

For information related to regulatory assets acquired in the Merger Transaction for Union Gas, BC Pipelines, BC Field Services and SEP, refer to Note 8 - Acquisitions and Dispositions.

Gas Distribution

On August 30, 2018, we received a decision from the OEB approving the application to amalgamate EGD and Union Gas (Amalgamation). On October 15, 2018, we announced that we would proceed with the Amalgamation, with an expected effective date of January 1, 2019. On January 1, 2019, the Amalgamation was completed and the amalgamated company continued as Enbridge Gas Inc. (EGI).

The OEB decision also approved the rate setting mechanism for the amalgamated entity to be employed during a five-year deferred rebasing period from 2019 through 2023, after which time rates will be rebased. The decision also approved the continuation and establishment of certain deferral and variance accounts, as well as an earnings sharing mechanism that requires the amalgamated entity to share equally with customers, any earnings in excess of 150 basis points over the OEB approved ROE.

Enbridge Gas Distribution Inc.

EGD’s gas distribution operations are regulated by the OEB. Rates for the years ended December 31, 2018 and 2017 were set in accordance with parameters established by the customized incentive rate plan (IR Plan). The customized IR Plan, inclusive of the requested capital investment amounts and an incentive mechanism providing the opportunity to earn above the allowed ROE, was approved, with modifications, by the OEB in 2014. The approved customized IR Plan is for establishing rates for 2014 through 2018.

As part of the customized IR Plan, the OEB 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 also includes an earnings sharing mechanism, whereby any return over the allowed

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rate of return for a given year under the customized IR Plan will be shared equally with customers. 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.

EGD’s after-tax rate of return on common equity embedded in rates was 9.0% and 8.8% for the years ended December 31, 2018 and 2017, respectively, based on a 36% deemed common equity component of capital for regulatory purposes, in both years.

Union Gas Limited

Union Gas is regulated by the OEB. Union Gas's distribution rates beginning January 1, 2014 are set under a five-year incentive regulation framework. The incentive regulation framework establishes new rates at the beginning of each year through the use of a pricing formula rather than through the examination of revenue and cost forecasts.

The incentive regulation framework includes an earnings sharing mechanism that permits Union Gas to fully retain the return on common equity from utility operations up to 9.93%, share 50% of any earnings between 9.93% and 10.93% with customers, and share 90% of any earnings above 10.93% with customers. Union Gas's approved after-tax return on common equity is fixed at 8.93% for the five-year incentive regulation term.

Enbridge Gas New Brunswick Inc.

Enbridge Gas New Brunswick Inc. is regulated by the EUB. The current rates are set, as prescribed by legislation for 2018 and 2019. In 2020 all rates will be set by cost-of-service methodology. On December 4, 2018, we announced that we entered into a definitive agreement for the sale of Enbridge Gas New Brunswick Inc. (Note 8). Closing of the transaction remains subject to the receipt of regulatory approvals and other customary closing conditions expected to occur in 2019. As such, we classified Enbridge Gas New Brunswick Inc. assets as held for sale and measured them at the lower of their carrying value or fair value less costs to sell. As the carrying value does not exceed the fair value, no impairment has been recorded for the year ended December 31, 2018.

FINANCIAL STATEMENT EFFECTS

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

December 31,	Recovery/Refund Period Ends	2018		2017
(millions of Canadian dollars)
Regulatory assets/(liabilities)
Liquids Pipelines
Deferred income taxes	Various	1,673		1,492
Tolling deferrals	Various	(28	)	(34	)
Recoverable income taxes	Through 2030	27		46
Pipeline future abandonment costs1	Various	(201	)	(141	)
Gas Transmission and Midstream
Deferred income taxes	Various	826		717
Regulatory liability related to income taxes2	Various	(912	)	(1,078	)
Other	Various	94		(16	)
Gas Distribution
Deferred income taxes	Various	1,132		1,000
Purchased gas variance3	Various	197		51
Pension plans and OPEB4	Through 2033	118		102
Constant dollar net salvage adjustment	2018	6		38
Future removal and site restoration reserves5	Various	(1,107	)	(1,066	)
Site restoration clearance adjustment	Various	—		(31	)
Other	Various	(4	)	31

1 Funds collected are included in Restricted long-term investments (Note 14).

2 Relates to the establishment of a regulatory liability as a result of the United States tax reform legislation enacted December 22, 2017.

3 Purchase gas variance is the difference between the actual cost and the approved cost of natural gas reflected in rates. EGD and Union Gas have 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.

4 The balances are excluded from the rate base and do not earn an ROE.

5 Future removal and site restoration reserves result from amounts collected from customers by the Company, with the approval of the OEB, 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 that is recorded in rates. The balance represents the amount that the Company has collected from customers, net of actual costs expended on removal and site restoration. The settlement of this balance will occur over the long-term as future removal and site restoration costs are incurred. In the absence of rate regulation accounting, costs incurred for removal and site restoration would be charged to earnings as incurred with recognition of revenue for amounts previously collected.

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 services 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. As at December 31, 2018 and 2017, the net book value of these costs included in gas mains in Property, plant

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and equipment, net was $110 million and $118 million, respectively. In the absence of rate regulation accounting, some of these costs would be charged to earnings in the year incurred.

8.  ACQUISITIONS AND DISPOSITIONS

ACQUISITIONS

Spectra Energy Corp

On February 27, 2017, Enbridge and Spectra Energy combined in the Merger Transaction for a purchase price of $37.5 billion. Under the terms of the Merger Transaction, Spectra Energy shareholders received 0.984 shares of Enbridge common stock for each share of Spectra Energy common stock that they owned, giving us 100% ownership of Spectra Energy.

Consideration offered to complete the Merger Transaction included 691 million common shares of Enbridge at US$41.34 per share, based on the February 24, 2017 closing price on the New York Stock Exchange (NYSE), for a total value of $37,429 million in common shares issued to Spectra Energy shareholders, plus approximately $3 million in cash in lieu of any fractional shares, and 3.5 million share options with a fair value of $77 million, that were exchanged for Spectra Energy’s outstanding stock compensation awards.

Spectra Energy, through its subsidiaries and equity affiliates, owns and operates a large and diversified portfolio of complementary natural gas-related energy assets and is one of North America’s leading natural gas infrastructure companies. Spectra Energy also owns and operates a crude oil pipeline system that connects Canadian and United States producers to refineries in the United States Rocky Mountain and Midwest regions. The combination brings together two highly complementary platforms to create North America’s largest energy infrastructure company and meaningfully enhances customer optionality, positioning us for long-term growth opportunities, and strengthening our balance sheet.

The Merger Transaction has been accounted for as a business combination under the acquisition method of accounting as prescribed by Accounting Standards Codification (ASC) 805 Business Combinations. The acquired tangible and intangible assets and assumed liabilities are recorded at their estimated fair values at the date of acquisition.

The purchase price allocation has been completed as at December 31, 2017, along with the allocation of goodwill to reporting units (Note 16). Our reporting units are equivalent to our identified segments with the exception of the Gas Transmission and Midstream segment, which is composed of two reporting units: gas transmission and gas midstream.

The following table summarizes the estimated fair values that were assigned to the net assets of Spectra Energy:

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February 27,	2017
(millions of Canadian dollars)
Fair value of net assets acquired:
Current assets (a)	2,432
Property, plant and equipment, net (b)	33,555
Restricted long-term investments	144
Long-term investments (c)	5,000
Deferred amounts and other assets (d)	2,390
Intangible assets, net (e)	1,288
Current liabilities (a)	(3,982	)
Long-term debt (d)	(21,444	)
Other long-term liabilities	(1,983	)
Deferred income taxes (b)	(7,670	)
Noncontrolling interests (f)	(8,877	)
	853
Goodwill (g)	36,656
	37,509
Purchase price:
Common shares	37,429
Cash	3
Fair value of outstanding earned stock compensation awards recorded in Additional paid-in capital	77
	37,509

a) Accounts receivable is comprised primarily of customer trade receivables and natural gas imbalances. As such, the fair value of accounts receivable approximates the net carrying value of $1,174 million. The gross amount due of $1,190 million, of which $16 million is not expected to be collected, is included in current assets.

During the fourth quarter of 2017, we identified certain transactions that were not reflected in the purchase price equation. This resulted in a $67 million and $548 million increase in current assets and current liabilities, respectively, and a $481 million decrease in long-term debt.

b) We have applied the valuation methodologies described in ASC 820 Fair Value Measurements and Disclosures, to value the property, plant and equipment purchased. The fair value of Spectra Energy’s rate-regulated property, plant and equipment was determined using a market participant perspective, which is their carrying amount. The fair value of the remaining non-regulated property, plant and equipment was determined primarily using variations of the income approach, which is based on the present value of the future after-tax cash flows attributable to each non-regulated asset. Some of the more significant assumptions inherent in the development of the values, from the perspective of a market participant, include, but are not limited to, the amount and timing of projected future cash flows (including revenue and profitability); the discount rate selected to measure the risks inherent in the future cash flows; the assessment of the asset’s life cycle; the competitive trends impacting the asset; and customer turnover.

During the third quarter of 2017, Spectra Energy's right-of-way agreements were reclassified from intangible assets to property, plant and equipment to conform the presentation of these agreements with our accounting policy pertaining to rights-of-way. The purchase price allocation above reflects this reclassification, which amounted to $830 million as at February 27, 2017. There is no change in the amortization period for the right-of-way agreements as a result of this reclassification.

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During the fourth quarter of 2017, we finalized our fair value measurement of the BC Pipeline & Field Services businesses, which resulted in decreases to property, plant and equipment of $1,955 million and deferred income tax liabilities of $661 million as at February 27, 2017.

c) Long-term investments represent Spectra Energy’s 50% equity investment in DCP Midstream LLC (DCP Midstream), Gulfstream Natural Gas System, L.L.C., Nexus Gas Transmission, LLC (Nexus), Steckman Ridge LP, Islander East Pipeline Company, L.L.C., Southeast Supply Header L.L.C., and 20% equity interest in PennEast Pipeline Company LLC (PennEast). The fair value of these investments was determined using an income approach.

d)     Fair value of long-term debt was determined based on the current underlying Government of Canada and United States Treasury interest rates on the corresponding bonds, as well as an implied credit spread based on current market conditions and resulted in an increase in the book value of debt of $1.5 billion. The fair value adjustment to long-term debt related to rate-regulated entities of $629 million also results in a regulatory offset in Deferred amounts and other assets in the Consolidated Statements of Financial Position.

During the fourth quarter of 2017, deferred amounts and other assets decreased by $530 million as at February 27, 2017 due to the finalization of BC Pipelines & Field Services' fair value measurement, as discussed under (b) above.

During the fourth quarter of 2017, we identified certain transactions that were not reflected in the purchase price equation. This resulted in a $481 million decrease in long-term debt, as discussed under (a) above.

e) Intangible assets primarily consist of customer relationships in the non-regulated business, which represent the underlying relationship from long-term agreements with customers that are capitalized upon acquisition, determined using the income approach. Intangible assets are amortized on a straight-line basis over their expected lives.

During the third quarter of 2017, intangible assets decreased by $830 million as at February 27, 2017 due to a reclassification to property, plant and equipment, as discussed under (b) above.

The fair value of intangible assets acquired through the Merger Transaction, by major classes is as follows:

	Weighted Average		Fair
As at February 27, 2017	Amortization Rate		Value
(millions of Canadian dollars)
Customer relationships1	3.7	%	739
Project agreement2	4.0	%	105
Software	11.1	%	329
Other	4.2	%	115
			1,288

1 Represents customer relationships in the non-regulated business, which were capitalized upon acquisition.

2 Represents a project agreement between SEP, NextEra Energy, Inc., Duke Energy Corporation (Duke Energy) and Williams Partners L.P. In accordance with the agreement, payments will be made, based on our proportional ownership interest in Sabal Trail Transmission, LLC (Sabal Trail), as certain milestones of the project are met. Amortization of the intangible asset began on July 3, 2017, when Sabal Trail was placed into service (Note 13).

f) The fair value of Spectra Energy’s noncontrolling interests includes approximately 78.4 million SEP common units outstanding to the public, valued at the February 24, 2017 closing price of US$44.88 per common unit on the NYSE, and units held by third parties in Maritimes & Northeast Pipeline, L.L.C., Sabal Trail and Algonquin Gas Transmission, L.L.C., valued based on the

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underlying net assets of each reporting unit and preferred stock held by third parties in Union Gas and Westcoast Energy Inc.

During the third quarter of 2017, we finalized our fair value measurement of Sabal Trail, which resulted in an increase to noncontrolling interests of $85 million as at February 27, 2017.

g) We recorded $36.7 billion in goodwill, which is primarily related to expected synergies from the Merger Transaction. The goodwill balance recognized is not deductible for tax purposes. Factors that contributed to the goodwill include the opportunity to expand our natural gas pipelines segment, the potential for cost and supply chain optimization synergies, existing assembled assets and work force that cannot be duplicated at the same cost by a new entrant, franchise rights and other intangibles not separately identifiable because they are inextricably linked to the provision of regulated utility service and the enhanced scale and geographic diversity which provide greater optionality and platforms for future growth.

During the third quarter of 2017, goodwill increased by $85 million as at February 27, 2017 due to the finalization of the fair value measurement of Sabal Trail as discussed under (f) above.

During the fourth quarter of 2017, goodwill increased by $1,824 million as at February 27, 2017 due to the finalization of the fair value measurement of BC Pipelines & Field Services as discussed under (b) above.

Acquisition-related expenses incurred were approximately $231 million. Costs incurred for the years ended December 31, 2017 and 2016 of $180 million and $51 million, respectively, are included in Operating and administrative expense in the Consolidated Statements of Earnings.

Upon completion of the Merger Transaction, we began consolidating Spectra Energy. Since the closing date of February 27, 2017 through December 31, 2017, Spectra Energy has generated approximately $5,740 million in revenues and $2,574 million in earnings.

Our supplemental pro forma consolidated financial information for the years ended December 31, 2017 and 2016, including the results of operations for Spectra Energy as if the Merger Transaction had been completed on January 1, 2016 are as follows:

Year ended December 31,	2017	2016
(unaudited; millions of Canadian dollars)
Revenues	45,669	40,934
Earnings attributable to common shareholders1	2,902	2,820

1 Merger Transaction costs of $180 million (after-tax $131 million) were excluded from earnings for the year ended December 31, 2017.

Tupper Main and Tupper West

On April 1, 2016, we acquired the Tupper Main and Tupper West gas plants and associated pipelines (the Tupper Plants) located in northeastern BC 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, we did not recognize any goodwill as part of the acquisition. Transaction costs incurred by us totaled approximately $1 million and are included in Operating and administrative expense in the Consolidated Statements of Earnings. The Tupper Plants are a part of our Gas Transmission and Midstream segment.

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

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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

In 2018, the assets of the Tupper Plants were subsequently reclassified to assets held for sale and sold as part of the provincially regulated assets of the Canadian Natural Gas Gathering and Processing transaction. See Assets Held for Sale section below for further details of the transaction.

OTHER ACQUISITIONS

Chapman Ranch Wind Project

On September 9, 2016, we 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, we 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 our earnings if the transaction had occurred on January 1, 2016 as the project was under construction and had not generated revenues to date. Chapman Ranch is a part of our Green Power and Transmission segment.

New Creek Wind Project

In November 2015, we 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 balance allocated to Intangible assets. New Creek was placed into service in December 2016 and is a part of our Green Power and Transmission segment.

Midstream Business

On February 27, 2015, EEP acquired, through its partially-owned subsidiary, Midcoast Energy Partners, L.P. (MEP), the midstream business of New Gulf Resources, LLC located in Texas for $106 million (US$85 million) in cash and a contingent future payment of up to $21 million (US$17 million). The acquisition consisted of a natural gas gathering system that is in operation and is a part of our Gas Transmission and Midstream segment. Of the purchase price, we allocated $69 million (US$55 million) to Property, plant and equipment and the balance to Intangible assets. In 2016, we determined that the likelihood of making any future contingent payments was remote.

ASSETS HELD FOR SALE

Enbridge Gas New Brunswick

In December 2018, we entered into an agreement for the sale of Enbridge Gas New Brunswick Limited Partnership and Enbridge Gas New Brunswick Inc. (collectively, EGNB) to Liberty Utilities (Canada) LP, a wholly-owned subsidiary of Algonquin Power and Utilities Corp., for a cash purchase price of $331 million. EGNB operates and maintains natural gas distribution pipelines in southern New Brunswick, and its related assets are included in our Gas Distribution segment. Subject to certain regulatory approvals and customary closing conditions, the transaction is expected to close in 2019.

As these assets represented a portion of a reporting unit, we allocated a portion of the goodwill of the reporting unit to these assets using a relative fair value approach. As such, we have classified EGNB assets and an allocated goodwill of $133 million as held for sale and measured them at the lower of their

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carrying value or fair value less costs to sell. As the carrying value does not exceed the fair value, no impairment has been recorded for the year ended December 31, 2018.

Canadian Natural Gas Gathering and Processing Businesses

On July 4, 2018, we entered into agreements to sell our Canadian natural gas gathering and processing businesses to Brookfield Infrastructure Partners L.P. and its institutional partners for a cash purchase price of approximately $4.3 billion, subject to customary closing adjustments. Separate agreements were entered into for those facilities currently governed by provincial regulations and those governed by federal regulations (collectively, Canadian Natural Gas Gathering and Processing Businesses assets). On October 1, 2018, we closed the sale of the provincially regulated facilities for proceeds of approximately $2.5 billion. These assets were included within our Gas Transmission and Midstream segment. Please see Dispositions discussion below for further details regarding the transaction.

As at December 31, 2018, the net assets of the federally regulated facilities of our Canadian Natural Gas Gathering and Processing Business remain classified as held for sale, including $55 million of allocated goodwill. The sale of the federally regulated facilities is expected to close in mid-2019 for proceeds of approximately $1.8 billion.

In addition, upon classifying the Canadian Natural Gas Gathering and Processing Businesses assets as held for sale in the third quarter of 2018, as these assets represented a portion of a reporting unit, we allocated a portion of the goodwill of the reporting unit to these assets using a relative fair value approach. As a result of the goodwill allocation, the carrying value of Canadian Natural Gas Gathering and Processing Businesses assets is greater than the sale price consideration less the cost to sell. Therefore, we recorded a goodwill impairment of $1,019 million on the Consolidated Statements of Earnings for the year ended December 31, 2018. The held for sale classification represented a triggering event and required us to perform a goodwill impairment test for the related reporting unit. The results of the test did not indicate any additional goodwill impairment.

Line 10 Crude Oil Pipeline

In the first quarter of 2018, we satisfied the condition as set out in our agreements for the sale of our Line 10 crude oil pipeline (Line 10), which originates near Hamilton, Ontario and terminates at West Seneca, New York. Our subsidiaries, Enbridge Pipelines Inc. and EEP, own the Canadian and United States portions of Line 10, respectively, and the related assets are included in our Liquids Pipeline segment.

We expect to close the sale of Line 10 within one year, subject to regulatory approval and certain closing conditions. As such, during the first quarter of 2018, we classified Line 10 assets as held for sale and measured them at the lower of their carrying value or fair value less costs to sell, which resulted in a loss of $154 million ($95 million after-tax attributable to us) included within Asset impairment on the Consolidated Statements of Earnings for the year ended December 31, 2018.

St. Lawrence Gas Company, Inc.

In August 2017, we entered into an agreement to sell the issued and outstanding shares of St. Lawrence Gas Company, Inc. (St. Lawrence Gas) for cash proceeds of approximately $96 million (US$70 million). Subject to regulatory approval and certain pre-closing conditions, the transaction is expected to close in 2019. As at December 31, 2018 and 2017, St. Lawrence Gas, which is a part of our Gas Distribution segment, was classified as held for sale in the Consolidated Statements of Financial Position.

The table below summarizes the presentation of net assets held for sale in our Consolidated Statements of Financial Position.

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	December 31, 2018		December 31, 2017
(millions of Canadian dollars)
Accounts receivable and other (current assets held for sale)	117		424
Deferred amounts and other assets (long-term assets held for sale)1	2,383		1,190
Accounts payable and other (current liabilities held for sale)	(63	)	(315	)
Other long-term liabilities (long-term liabilities held for sale)	(96	)	(34	)
Net assets held for sale	2,341		1,265

1 Included within Deferred amounts and other assets at December 31, 2018 and 2017 respectively is property, plant and equipment of $2.1 billion and $1.1 billion.

DISPOSITIONS

Canadian Natural Gas Gathering and Processing Businesses

On October 1, 2018, we closed the sale of the provincially regulated facilities of the Canadian Natural Gas Gathering and Processing Businesses assets for proceeds of approximately $2.5 billion. After closing adjustments, a gain on disposal of $34 million before tax was included in Other income/(expense) in the Consolidated Statements of Earnings. Please see Assets Held for Sale discussion above for further details regarding the transaction.

Renewable Assets

On August 1, 2018, we closed the sale of a 49% interest in all of our Canadian renewable assets, a 49% interest in two United States renewable assets and 49% of our interest in the Hohe See Offshore wind power project and its subsequent expansion, both concurrently under construction in Germany, (collectively, the Renewable Assets) to the Canada Pension Plan Investment Board (CPPIB). Total cash proceeds from the transaction were $1.75 billion. In addition, CPPIB will fund their pro-rata share of the remaining capital expenditures on the Hohe See Offshore wind power project. We maintain a 51% interest in the Renewable Assets and will continue to manage, operate and provide administrative services for these assets.

A loss on disposal of $20 million (€14 million) was included in Other income/(expense) in the Consolidated Statements of Earnings for the sale of 49% of our interest in the Hohe See Offshore wind power project and its subsequent expansion. Subsequent to the sale, the remaining interests in these assets continue to be accounted for as an equity method investment, and are a part of our Green Power and Transmission segment.

Gains of $62 million and $17 million (US$13 million) were included in Additional paid-in capital in the Consolidated Statements of Financial Position for the sale of 49% interest in the Canadian and United States renewable assets, respectively. Subsequent to the sale, because we maintained a controlling interest, these assets continue to be consolidated and are a part of our Green Power and Transmission segment. In addition, we recognized noncontrolling interests in our Consolidated Statements of Financial Position as at December 31, 2018 to reflect the interests that we do not hold (Note 20).

Also, a deferred income tax recovery of $267 million ($196 million attributable to us) was recorded in the year ended December 31, 2018 as a result of the agreement entered into during the second quarter of 2018 for the Renewable Assets (Note 25).

In connection with our sale of the Renewable Assets, we have new consolidated and unconsolidated VIEs (Note 12).

Midcoast Operating, L.P.

On August 1, 2018, we closed the sale of Midcoast Operating, L.P. and its subsidiaries (collectively, MOLP) to AL Midcoast Holdings, LLC (an affiliate of ArcLight Capital Partners, LLC) for total cash proceeds of $1.4 billion (US$1.1 billion). After closing adjustments recorded in the fourth quarter of 2018, a loss on disposal of $41 million (US$32 million) was included in Other income/(expense) in the

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Consolidated Statements of Earnings. MOLP conducted our United States natural gas and natural gas liquids gathering, processing, transportation and marketing businesses, and was a part of our Gas Transmission and Midstream segment.

Upon closing of the sale, we also recorded a liability of $387 million (US$298 million) for future volume commitments retained by us. The associated loss is included in the loss on disposal of $41 million discussed above. As at December 31, 2018, $79 million (US$58 million) and $296 million (US$216 million) were included in Accounts payable and other and Other long-term liabilities, respectively, on the Consolidated Statements of Financial Position.

In the second quarter of 2018, our equity method investment in the Texas Express NGL pipeline system, together with the MOLP assets that have been held for sale since December 31, 2017, also met the conditions for assets held for sale. The $447 million carrying value of Texas Express NGL pipeline system equity investment and an allocated goodwill of $262 million, were included within the disposal group as at June 30, 2018 and subsequently disposed on August 1, 2018.

In the first quarter of 2018, as a result of entering into a definitive sales agreement, the fair value of the assets held for sale as at March 31, 2018 were revised based on the sale price. Accordingly, we recorded a loss of $913 million ($701 million after-tax). This loss has been included within Asset impairment on the Consolidated Statements of Earnings for the year ended December 31, 2018.

Previously as at December 31, 2017, we classified these assets as held for sale and measured them at the lower of their carrying value or fair value less costs to sell, which resulted in an asset impairment loss of $4.4 billion ($2.8 billion after-tax) and a related goodwill impairment of $102 million, which were included in the Consolidated Statement of Earnings for the year ended December 31, 2017.

Sandpiper Project

During the years ended December 31, 2018 and 2017, we sold unused pipe related to the Sandpiper Project (Sandpiper) for cash proceeds of approximately $38 million (US$30 million) and $148 million (US$111 million), respectively. Gains on disposal of $29 million (US$22 million) and $83 million (US$63 million) before tax were included in Operating and administrative expense in the Consolidated Statements of Earnings for the years ended December 31, 2018 and 2017, respectively. These assets were a part of our Liquids Pipelines segment.

Olympic Pipeline

On July 31, 2017, we completed the sale of our interest in Olympic Pipeline for cash proceeds of approximately $203 million (US$160 million). A gain on disposal of $27 million (US$21 million) before tax was included in Other income/(expense) in the Consolidated Statements of Earnings. This interest was a part of our Liquids Pipelines segment.

Ozark Pipeline

In 2016, we classified the Ozark Pipeline assets as held for sale. On March 1, 2017, we completed the sale of the Ozark Pipeline assets to a subsidiary of MPLX LP for cash proceeds of approximately $294 million (US$220 million), including reimbursement of costs. A gain on disposal of $14 million (US$10 million) before tax was included in Operating and administrative expense in the Consolidated Statements of Earnings. These assets were a part of our Liquids Pipelines segment.

South Prairie Region

On December 1, 2016, we completed the sale of the South Prairie Region assets for cash proceeds of approximately $1.1 billion. A gain on disposal of $850 million before tax was included in Other income/(expense) in the Consolidated Statements of Earnings. These assets were a part of our Liquids Pipelines segment.

OTHER DISPOSITIONS

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

9.  ACCOUNTS RECEIVABLE AND OTHER

December 31,	2018	2017
(millions of Canadian dollars)
Trade receivables and unbilled revenues1	4,711	5,325
Short-term portion of derivative assets	498	296
Other	1,308	1,432
	6,517	7,053

1 Net of allowance for doubtful accounts of $64 million and $50 million as at December 31, 2018 and 2017, respectively.

During 2017, in conjunction with its restructuring actions (Note 20), EEP terminated a receivable purchase agreement with a special purpose entity wholly-owned by us.

10.  INVENTORY

December 31,	2018	2017
(millions of Canadian dollars)
Natural gas	776	695
Crude oil	482	744
Other commodities	81	89
	1,339	1,528

Adjustments of $93 million, nil and nil were included in Commodity costs on the Consolidated Statements of Earnings for the years ended December 31, 2018, 2017 and 2016, respectively, to reduce inventory to market value.

11.  PROPERTY, PLANT AND EQUIPMENT

	Weighted Average
December 31,	Depreciation Rate		2018		2017
(millions of Canadian dollars)
Pipelines	2.6	%	50,078		47,720
Pumping equipment, buildings, tanks and other	3.0	%	16,935		16,610
Land and right-of-way1	2.7	%	2,603		2,538
Gas mains, services and other	3.2	%	17,474		17,026
Compressors, meters and other operating equipment	1.7	%	5,893		5,774
Processing and treating plants	1.5	%	1,634		1,440
Storage	1.9	%	1,713		1,545
Wind turbines, solar panels and other	4.2	%	5,063		4,804
Power transmission	2.6	%	383		365
Vehicles, office furniture, equipment and other buildings and improvements	5.9	%	630		390
Under construction	—		9,778		7,601
Total property, plant and equipment2			112,184		105,813
Total accumulated depreciation			(17,644	)	(15,102	)
Property, plant and equipment, net			94,540		90,711

1 The measurement of weighted average depreciation rate excludes non-depreciable assets.

2 Certain assets were reclassified as held for sale as at December 31, 2018 and December 31, 2017 (Note 8).

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Depreciation expense for the years ended December 31, 2018, 2017 and 2016 was $2.9 billion, $2.9 billion and $2.0 billion, respectively.

IMPAIRMENT

Northern Gateway Project

On November 29, 2016, the Canadian Federal Government directed the NEB to dismiss our Northern Gateway Project application and the Certificates of Public Convenience and Necessity have been rescinded. In consultation with potential shippers and Aboriginal equity partners, we assessed this decision and concluded that the project cannot proceed as envisioned. After taking into consideration the amount recoverable from potential shippers on the Northern Gateway Project, we 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 are a part of our Liquids Pipelines segment.

Sandpiper Project

On September 1, 2016, we announced that EEP applied for the withdrawal of regulatory applications pending with the Minnesota Public Utilities Commission for Sandpiper. In connection with this announcement and other factors, we evaluated Sandpiper for impairment. As a result, we recognized an impairment loss of $992 million ($81 million after-tax attributable to us) 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 a part of our Liquids Pipelines segment. The estimated remaining fair value of Sandpiper was 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 at the time. 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, was reclassified into Deferred amounts and other assets in the Consolidated Statements of Financial Position as at December 31, 2016. During 2017, we disposed of substantially all of the remaining Sandpiper assets (Note 8).

Other

For the year ended December 31, 2016, we recorded impairment charges of $11 million related to EEP’s non-core trucking assets and related facilities, which are a part of our Gas Transmission and Midstream segment.

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 such charges are included in Impairment of property, plant and equipment on the Consolidated Statements of Earnings.

12.  VARIABLE INTEREST ENTITIES

CONSOLIDATED VARIABLE INTEREST ENTITIES

Enbridge Canadian Renewable LP (ECRLP)

To facilitate the sale on August 1, 2018 of the Renewable Assets (Note 8), we and our subsidiaries transferred our Canadian renewable assets to a newly formed partnership, ECRLP. Subsequently, a 49% interest in ECRLP was sold to CPPIB. ECRLP is a VIE as its limited partners do not have substantive kick-out rights or participating rights. Because we have the power to direct the activities of ECRLP, we are exposed to potential losses, and we have the right to receive benefits from ECRLP, we are considered the primary beneficiary.

Enbridge Energy Partners, L.P.

EEP is a Delaware limited partnership and is considered a VIE as its limited partners do not have substantive kick-out rights or participating rights. Through our wholly-owned subsidiary, Enbridge Energy Company, Inc. (EECI), we have the power to direct EEP’s activities and have a significant impact on

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EEP’s economic performance. Along with an economic interest held through an indirect common interest and general partner interest through EECI, and through our 100% ownership of EECI, we are the primary beneficiary of EEP. As at December 31, 2017, our economic interest in EEP was 34.6% and the public owned the remaining interests in EEP. As at December 31, 2018, subsequent to the Sponsored Vehicles buy-in (Note 20), our interest in EEP was 100%.

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. We are the primary beneficiary of the Fund through our 100% direct common interest in the Fund. We also serve in the capacity of Manager of the Fund and Affiliates. As at December 31, 2017, our combined economic interest and direct common interest in the Fund were 82.5% and 29.4%, respectively. As at December 31, 2018, subsequent to the Sponsored Vehicles buy-in (Note 20), our interest in the Fund was 100%.

Enbridge Commercial Trust (ECT)

We have the ability to appoint the majority of the trustees to ECT’s Board of Trustees, resulting in a 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 we do not have a common equity interest in ECT, we are considered to be the primary beneficiary of ECT. We also serve in the capacity of Manager of ECT, as part of the Fund and Affiliates.

Enbridge Income Partners LP (EIPLP)

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 a direct wholly-owned subsidiary of Enbridge 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 a direct common interest in EIPLP, we have the power to direct the activities that most significantly impact EIPLP’s economic performance and have the obligation to absorb losses and the right to receive residual returns that are potentially significant to EIPLP, making us the primary beneficiary of EIPLP. As at December 31, 2017, our economic interest and direct common interest in EIPLP were 73.5% and 53.1%, respectively. As at December 31, 2018, subsequent to the Sponsored Vehicles buy-in (Note 20), our interest in EIPLP was 100%.

Green Power and Transmission

Through various subsidiaries, we have a majority ownership interest in Magic Valley, Wildcat, Keechi Wind Project (Keechi), New Creek and Chapman Ranch wind facilities. These wind facilities are considered VIEs due to the members’ lack of substantive kick-out rights and participating rights. We are the primary beneficiary of these VIEs by virtue of our voting rights, our power to direct the activities that most significantly impact the economic performance of the wind facilities, and our obligation to absorb losses.

Enbridge Holdings (DakTex) L.L.C.

Enbridge Holdings (DakTex) L.L.C. (DakTex) is owned 75% by a wholly-owned subsidiary of Enbridge and 25% by EEP, through which we have an effective 27.6% interest in the equity investment, Bakken Pipeline System (Note 13). EEP is the primary beneficiary because it has the power to direct DakTex’s activities that most significantly impact its economic performance. We consolidate EEP and by extension also consolidate DakTex.

Spectra Energy Partners, LP

SEP is a natural gas and crude oil infrastructure master limited partnership and is considered a VIE as its limited partners do not have substantive kick-out rights or participating rights. We are the primary

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beneficiary of SEP because we have the power to direct SEP’s activities that most significantly impact its economic performance. We acquired a 75% ownership in SEP through the Merger Transaction in 2017. As at December 31, 2018, subsequent to the Sponsored Vehicles buy-in (Note 20), our interest in SEP was 100%.

Valley Crossing Pipeline, LLC

Valley Crossing Pipeline, LLC (Valley Crossing), a wholly-owned subsidiary of Enbridge, has constructed a natural gas pipeline to transport natural gas within Texas. The pipeline was placed into service in October 2018. Following the completion of the pipeline construction and beginning of the long term transportation services agreement, Valley Crossing was concluded to have sufficient equity at risk to finance its activities without additional subordinated financial support and thus is no longer a VIE after October 2018.

Other Limited Partnerships

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

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

December 31,	2018	2017
(millions of Canadian dollars)
Assets
Cash and cash equivalents	506	368
Restricted cash	27	—
Accounts receivable and other	2,073	2,132
Accounts receivable from affiliates	5	3
Inventory	244	220
	2,855	2,723
Property, plant and equipment, net	72,737	68,685
Long-term investments	6,481	6,258
Restricted long-term investments	244	206
Deferred amounts and other assets	3,156	2,921
Intangible assets, net	317	296
Goodwill	29	29
Deferred income taxes	131	145
	85,950	81,263
Liabilities
Short-term borrowings	275	485
Accounts payable and other	2,925	2,859
Accounts payable to affiliates	4	131
Interest payable	303	312
Environmental liabilities	22	35
Current portion of long-term debt	1,034	2,129
	4,563	5,951
Long-term debt	29,577	31,469
Other long-term liabilities	5,074	4,301
Deferred income taxes	6,911	3,010
	46,125	44,731
Net assets before noncontrolling interests	39,825	36,532

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We do not have an obligation to provide financial support to any of the consolidated VIEs.

UNCONSOLIDATED VARIABLE INTEREST ENTITIES

We currently hold 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. We have determined that we do 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.

The carrying amount of our interest in VIEs that are unconsolidated and our estimated maximum exposure to loss as at December 31, 2018 and 2017 is presented below.

	Carrying Amount of Investment	Enbridge’s Maximum Exposure to
December 31, 2018	in VIE	Loss
(millions of Canadian dollars)
Aux Sable Liquid Products L.P.1	311	375
Eolien Maritime France SAS2	68	784
Enbridge Renewable Infrastructure Investments S.a.r.l.3, 9	127	3,250
Illinois Extension Pipeline Company, L.L.C.4	724	724
Nexus Gas Transmission, LLC5	1,757	2,668
PennEast Pipeline Company, LLC6	97	385
Rampion Offshore Wind Limited7	638	648
Vector Pipeline L.P.8	198	301
Other4	27	27
	3,947	9,162

	Carrying Amount of Investment	Enbridge’s Maximum Exposure to
December 31, 2017	in VIE	Loss
(millions of Canadian dollars)
Aux Sable Liquid Products L.P.	300	361
Eolien Maritime France SAS	69	754
Hohe See Offshore Wind Project9	763	2,484
Illinois Extension Pipeline Company, L.L.C.	686	686
Nexus Gas Transmission, LLC	834	1,678
PennEast Pipeline Company, LLC	69	345
Rampion Offshore Wind Limited	555	679
Sabal Trail Transmissions, LLC	2,355	2,529
Vector Pipeline L.P.	169	278
Other	21	21
	5,821	9,815

1 At December 31, 2018, the maximum exposure to loss includes a guarantee by us for our respective share of the VIE’s borrowing on a bank credit facility.

2 At December 31, 2018, the maximum exposure to loss includes the portion of our parental guarantee that has been committed in project construction contracts in which we would be liable for in the event of default by the VIE and an outstanding affiliate loan receivable for $202 million held by us.

3 At December 31, 2018, the maximum exposure to loss includes the portion of our parental guarantee that has been committed in project construction contracts in which we would be liable for in the event of default by the VIE.

4 At December 31, 2018, the maximum exposure to loss is limited to our equity investment as these companies are in operation and self-sustaining.

5 At December 31, 2018, the maximum exposure to loss includes the remaining expected contributions to the joint venture and parental guarantees for our portion of capacity lease agreements.

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6 At December 31, 2018 the maximum exposure to loss includes the remaining expected contributions to the joint venture.

7 At December 31, 2018, the maximum exposure to loss includes the portion of our parental guarantee that has been committed in project contracts in which we would be liable for in the event of default by the VIE.

8 At December 31, 2018 the maximum exposure to loss includes the carrying value of an outstanding affiliate loan receivable for $102 million held by us.

9 As at December 31, 2018, the carrying amount of investment and maximum exposure to loss related to Hohe See Offshore Wind Project are included in the amounts shown for ERII.

We do not have an obligation to and did not provide any additional financial support to the VIEs during the years ended December 31, 2018 and 2017.

Enbridge Renewable Infrastructure Investments S.a.r.l. (ERII)

To facilitate the sale on August 1, 2018 of the Renewable Assets (Note 8), we transferred our interest in the Hohe See Offshore wind facilities and its subsequent expansion to a newly formed entity, ERII. Subsequently, a 49% interest in ERII was sold to CPPIB. ERII is a VIE due to insufficient equity at risk to finance its activities. We are not the primary beneficiary of ERII since the power to direct the activities of ERII that most significantly impacts its economic performance is shared. We account for ERII by using the equity method as we retain significant influence through a 51% voting interest in substantive decisions.

Sabal Trail Transmission, LLC

SEP owns a 50% interest in Sabal Trail, a joint venture that operates a pipeline originating in Alabama that transports natural gas to Florida and has been classified as a variable interest entity.

On April 30, 2018, Sabal Trail issued US$500 million in aggregate principal amount of 4.25% senior notes due in 2028, US$600 million in aggregate principal amount of 4.68% senior notes due in 2038 and US$400 million in aggregate principal amount of 4.83% senior notes due in 2048. Sabal Trail distributed net proceeds from the offering to the members as a partial reimbursement of construction and development costs incurred by the members. The net distribution made to SEP was US$744 million and was used to pay down indebtedness and is included within Distributions from equity investments in excess of cumulative earnings on the Consolidated Statements of Cash Flows for the year ended December 31, 2018. These events triggered reconsideration and as a result, it was concluded that Sabal Trail was no longer a VIE as of June 30, 2018 due to sufficient equity at risk to finance its activities.

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13.  LONG-TERM INVESTMENTS

	Ownership
December 31,	Interest		2018	2017
(millions of Canadian dollars)
EQUITY INVESTMENTS
Liquids Pipelines
Bakken Pipeline System1	27.6	%	2,039	1,938
Seaway Crude Pipeline System	50.0	%	3,113	2,882
Illinois Extension Pipeline Company, L.L.C.2	65.0	%	724	686
Other	30.0% - 43.8%		97	87
Gas Transmission and Midstream
Alliance Pipeline3	50.0	%	368	375
Aux Sable	42.7% - 50.0%		311	300
DCP Midstream, LLC4	50.0	%	2,368	2,143
Gulfstream Natural Gas System, L.L.C.4	50.0	%	1,289	1,205
Nexus Gas Transmission, LLC4	50.0	%	1,757	834
Offshore - various joint ventures	22.0% - 74.3%		400	389
PennEast Pipeline Company LLC4	20.0	%	97	69
Sabal Trail Transmission, LLC5	50.0	%	1,586	2,355
Southeast Supply Header L.L.C.4	50.0	%	519	486
Steckman Ridge LP4	49.5	%	237	221
Texas Express Pipeline6	35.0	%	—	430
Vector Pipeline L.P.	60.0	%	198	169
Other4	33.3% - 50.0%		6	34
Gas Distribution
Noverco Common Shares	38.9	%	—	—
Other4	50.0	%	15	15
Green Power and Transmission
Eolien Maritime France SAS	50.0	%	68	69
Enbridge Renewable Infrastructure Investments S.a.r.l.7	25.5	%	127	763
Rampion Offshore Wind Project	24.9	%	638	555
Other	19.0% - 50.0%		72	95
Eliminations and Other
Other	19.0% - 42.7%		10	26
OTHER LONG-TERM INVESTMENTS
Gas Distribution
Noverco Preferred Shares			478	371
Green Power and Transmission
Emerging Technologies and Other			80	80
Eliminations and Other
Other			110	67
			16,707	16,644

1 On February 15, 2017, EEP acquired an effective 27.6% interest in the Dakota Access and Energy Transfer Crude Oil Pipelines (collectively, the Bakken Pipeline System) for a purchase price of $2 billion (US$1.5 billion). The Bakken Pipeline System was placed into service on June 1, 2017. For details regarding our funding arrangement, refer to Note 20 - Noncontrolling Interests.

2 Owns the Southern Access Extension Project.

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

4 On February 27, 2017, we acquired Spectra Energy's interests in DCP Midstream, Gulfstream Natural Gas System, L.L.C, Nexus, PennEast, Southeast Supply Header L.L.C., Steckman Ridge LP and other equity investments as part of the Merger Transaction (Note 8).

5 On February 27, 2017, we acquired Spectra Energy's consolidated interest in Sabal Trail as part of the Merger Transaction (Note 8). On July 3, 2017, Sabal Trail was placed into service and the assets, liabilities, and noncontrolling interests were deconsolidated as at the in-service date.

6 On August 1, 2018 the sale of Midcoast Operating, L.P. and its subsidiaries closed. Upon closing of the sale, our interest in the Texas Express NGL pipeline system was sold along with the MOLP assets. The carrying value of $447 million of our equity method investment in the Texas Express NGL pipeline system was included within the disposal group of the transaction. For further details on the sale transaction please refer to Note 8 - Acquisitions and Dispositions.

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7 On February 8, 2017, we acquired an effective 50% interest in EnBW Hohe See GmbH & Co. KG. On August 1, 2018 we transferred our interest in the Hohe See Offshore wind facilities and its subsequent expansion to a newly formed entity, ERII. Subsequently, we sold a 49% interest in ERII to CPPIB, reducing our interest in the project to 25.5%.

Equity investments include the unamortized excess of the purchase price over the underlying net book value of the investees’ assets at the purchase date. As at December 31, 2018, this comprised of $2.2 billion in Goodwill and $706 millionin amortizable assets. As at December 31, 2017, this comprised of $2.0 billion in Goodwill and $643 million in amortizable assets.

For the years ended December 31, 2018, 2017 and 2016, dividends received from equity investments were$2.8 billion, $1.4 billionand$825 million, respectively.

Summarized combined financial information of our interest in unconsolidated equity investments (presented at 100%) is as follows:

	Year Ended December 31,
	2018			2017			2016
	Seaway	Other	Total	Seaway	Other	Total	Seaway	Other		Total
(millions of Canadian dollars)
Operating revenues	966	18,251	19,217	959	15,254	16,213	938	3,164		4,102
Operating expenses	212	15,422	15,634	286	12,911	13,197	293	3,051		3,344
Earnings/(loss)	646	2,308	2,954	672	2,056	2,728	643	(2	)	641
Earnings attributable to controlling interests	323	1,059	1,382	336	926	1,262	322	147		469

	December 31, 2018			December 31, 2017
	Seaway	Other	Total	Seaway	Other	Total
(millions of Canadian dollars)
Current assets	113	3,176	3,289	106	3,432	3,538
Non-current assets	3,585	45,531	49,116	3,329	41,697	45,026
Current liabilities	123	5,413	5,536	143	3,311	3,454
Non-current liabilities	16	15,859	15,875	13	13,582	13,595
Noncontrolling interests	—	3,479	3,479	—	3,191	3,191

Sabal Trail Transmission, LLC

On July 3, 2017, Sabal Trail was placed into service. In accordance with the Sabal Trail LLC Agreement, upon the in-service date, the power to direct Sabal Trail’s activities became shared with its members. We are no longer the primary beneficiary and deconsolidated the assets, liabilities and noncontrolling interests related to Sabal Trail as at the in-service date.

At deconsolidation, our 50% interest in Sabal Trail was recorded at its fair value of $2.3 billion (US$1.9 billion), which approximated its carrying value as a long-term equity investment. As a result, there was no gain or loss recognized for the year ended December 31, 2017 related to the remeasurement of the retained equity interest to its fair value. The fair value was determined using the income approach which is based on the present value of the future cash flows.

Noverco Inc.

As at December 31, 2018 and 2017, we owned an equity interest in Noverco through ownership of 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, 2018 and 2017, Noverco owned an approximate 1.4% and 1.9% reciprocal shareholding in our common shares, respectively. Noverco sold 4.4 million common shares in December

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2018 and purchased 1.2 million common shares in February 2016. Shares purchased and sold were treated as treasury stock on the Consolidated Statements of Changes in Equity.

As a result of Noverco’s reciprocal shareholding in our common shares, as at December 31, 2018 and 2017, we had an indirect pro-rata interest of 0.5% and 0.7%, respectively, in our own shares. Both the equity investment in Noverco and shareholders’ equity have been reduced by the reciprocal shareholding of $88 million and $102 million as at December 31, 2018 and 2017. Noverco records dividends paid from us as dividend income and we eliminate these dividends from our equity earnings of Noverco. We record our pro-rata share of dividends paid by us to Noverco as a reduction of dividends paid and an increase in our investment in Noverco.

14.  RESTRICTED LONG-TERM INVESTMENTS

Effective January 1, 2015, we 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, we reflect 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.

We routinely invest excess cash and various restricted balances in securities such as commercial paper, bankers acceptances, corporate debt securities, Canadian equity securities, treasury bills and money market securities in the United States and Canada.

As at December 31, 2018and 2017, we had restricted long-term investments held in trust and classified as available for sale or held to maturity of $323 million and $267 million, respectively. We had estimated future abandonment costs related to LMCI of $212 million and $151 million as at December 31, 2018 and 2017, respectively.

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15.  INTANGIBLE ASSETS

The following table provides the weighted average amortization rate, gross carrying value, accumulated amortization and net carrying value for each of our major classes of intangible assets:

	Weighted Average			Accumulated
December 31, 20181	Amortization Rate		Cost	Amortization	Net
(millions of Canadian dollars)
Customer relationships	5.0	%	762	70	692
Power purchase agreements	4.4	%	96	21	75
Project agreement2	4.0	%	164	10	154
Software	11.4	%	1,827	814	1,013
Other intangible assets3	4.1	%	508	70	438
			3,357	985	2,372

	Weighted Average			Accumulated
December 31, 20171	Amortization Rate		Cost	Amortization	Net
(millions of Canadian dollars)
Customer relationships	3.5	%	967	41	926
Power purchase agreements	3.5	%	99	17	82
Project agreement2	4.0	%	150	3	147
Software	11.3	%	1,760	714	1,046
Other intangible assets3	4.4	%	1,162	96	1,066
			4,138	871	3,267

1 Certain assets were reclassified as held for sale as at December 31, 2018 and December 31, 2017 (Note 8).

2 Represents a project agreement acquired from the Merger Transaction (Note 8).

3 The measurement of weighted average amortization rate excludes non-depreciable intangible assets.

For the years ended December 31, 2018, 2017 and 2016, our amortization expense related to intangible assets totaled $281 million, $280 million and $177 million, respectively. The following table presents our forecast of amortization expense associated with existing intangible assets for the years indicated as follows:

	2019	2020	2021	2022	2023
Forecast of amortization expense (millions of Canadian dollars)	278	251	227	205	186

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16.  GOODWILL

	Liquids Pipelines		Gas Transmission & Midstream		Gas Distribution		Green Power and Transmission	Energy Services	Eliminations and Other		Consolidated
(millions of Canadian dollars)
Gross Cost
Balance at January 1, 2017	59		457		7		—	2	13		538
Acquired in Merger Transaction (Note 8)	8,070		22,914		5,672		—	—	—		36,656
Sabal Trail deconsolidation (Note 13)	—		(966	)	—		—	—	—		(966	)
Disposition	(29	)	—		—		—	—	—		(29	)
Foreign exchange and other	(314	)	(866	)	—		—	—	—		(1,180	)
Balance at December 31, 2017	7,786		21,539		5,679		—	2	13		35,019
Disposition	—		(628	)	—		—	—	—		(628	)
Allocation to assets held for sale	—		(55	)	(133	)	—	—	—		(188	)
Foreign exchange and other	538		1,482		(183	)	—	—	—		1,837
Balance at December 31, 2018	8,324		22,338		5,363		—	2	13		36,040
Accumulated Impairment
Balance at January 1, 2017	—		(440	)	(7	)	—	—	(13	)	(460	)
Impairment	—		(102	)	—		—	—	—		(102	)
Balance at December 31, 2017	—		(542	)	(7	)	—	—	(13	)	(562	)
Impairment	—		(1,019	)	—		—	—	—		(1,019	)
Balance at December 31, 2018	—		(1,561	)	(7	)	—	—	(13	)	(1,581	)
Carrying Value
Balance at December 31, 2017	7,786		20,997		5,672		—	2	—		34,457
Balance at December 31, 2018	8,324		20,777		5,356		—	2	—		34,459

IMPAIRMENT

Gas Transmission and Midstream

Canadian Natural Gas Gathering and Processing Businesses

During the year ended December 31, 2018, we recorded a goodwill impairment charge of $1,019 million related to our Canadian Natural Gas Gathering and Processing Businesses assets which were classified as held for sale in the third quarter. The provincially regulated assets were subsequently sold in the fourth quarter (Note 8). As these assets represented a portion of a reporting unit, we allocated a portion of the goodwill of the reporting unit to these assets using a relative fair value approach. In connection with the write-down of the carrying values of the assets held for sale to its sale price consideration less costs to sell, the related goodwill was impaired. We also performed a goodwill impairment test for the related reporting unit resulting in no additional impairment charge. 

US Midstream

During the year ended December 31, 2017, we recorded a goodwill impairment charge of $102 million related to certain assets in our Gas Transmission and Midstream segment classified as held for sale (Note 8). Goodwill was allocated to certain disposal groups qualifying as a business based on a relative fair value approach. In connection with the write-down of the carrying values of the assets held for sale to its fair value less costs to sell, the related goodwill was impaired. The fair value of these assets were estimated using the discounted cash flow method, which was negatively impacted by prolonged decline in commodity prices and deteriorating business performance. We also performed goodwill impairment testing on the associated gas midstream reporting unit resulting in no additional impairment charge. 

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The estimate of the gas midstream reporting unit’s fair value required the use of significant unobservable inputs representative of a Level 3 fair value measurement, including assumptions related to the future performance of the reporting unit.

DISPOSITIONS

In 2018, we derecognized $262 million of goodwill on the disposition of Midcoast Operating, L.P. and its subsidiaries and $366 million on the disposition of the provincially regulated facilities of our Canadian Natural Gas Gathering and Processing Business (Note 8).

In 2017, we derecognized $29 million of goodwill on the disposition of Olympic Pipeline (Note 8).

ASSETS HELD FOR SALE

As at December 31, 2018, the net assets of the federally regulated facilities of our Canadian Natural Gas Gathering and Processing Business remain classified as held for sale, including $55 million of allocated goodwill. In addition, as at December 31, 2018, the net assets of EGNB were also classified as held for sale, including $133 million of allocated goodwill.

ACQUISITIONS

In 2017, we recognized $36.7 billion of goodwill on the Merger Transaction (Note 8).

17.  ACCOUNTS PAYABLE AND OTHER

December 31,	2018	2017
(millions of Canadian dollars)
Trade payables and operating accrued liabilities	4,604	5,135
Construction payables and contractor holdbacks	804	706
Current derivative liabilities	1,234	1,130
Dividends payable	1,539	1,169
Taxes payable	801	522
Other	854	816
	9,836	9,478

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18.  DEBT

	Weighted Average
December 31,	Interest Rate		Maturity	2018		2017
(millions of Canadian dollars)
Enbridge Inc.
United States dollar term notes1	4.1	%	2022-2046	6,419		5,889
Medium-term notes2	4.3	%	2019-2064	7,323		5,698
Fixed-to-floating subordinated term notes3,4	5.9	%	2077-2078	6,771		3,843
Floating rate notes5			2019-2020	2,389		2,254
Commercial paper and credit facility draws6	2.2	%	2019-2023	1,999		2,729
Other7				—		3
Enbridge (U.S.) Inc.
Commercial paper and credit facility draws8	3.5	%	2020	1,065		490
Enbridge Energy Partners, L.P.
Senior notes9	6.2	%	2019-2045	6,214		6,328
Junior subordinated notes10			2067	546		501
Commercial paper and credit facility draws11	3.3	%	2022	1,044		1,820
Enbridge Gas Distribution Inc.
Medium-term notes	4.5	%	2020-2050	3,695		3,695
Debentures	9.9	%	2024	85		85
Commercial paper and credit facility draws	2.3	%	2020	750		960
Enbridge Income Fund
Medium-term notes2				—		1,750
Commercial paper and credit facility draws				—		755
Enbridge Pipelines (Southern Lights) L.L.C.
Senior notes12	4.0	%	2040	1,257		1,207
Enbridge Pipelines Inc.
Medium-term notes13	4.3	%	2019-2046	4,225		4,525
Debentures	8.2	%	2024	200		200
Commercial paper and credit facility draws14	2.4	%	2020	2,200		1,438
Other7				4		4
Enbridge Southern Lights LP
Senior notes	4.0	%	2040	289		315
Midcoast Energy Partners, L.P.
Senior notes15				—		501
Spectra Energy Capital16
Senior notes17	7.1	%	2032-2038	236		1,665
Spectra Energy Partners, LP16
Senior secured notes18	6.1	%	2020	150		138
Senior notes19	4.3	%	2020-2048	8,249		7,192
Floating rate notes20			2020	546		501
Commercial paper and credit facility draws21	3.2	%	2022	2,065		2,824
Union Gas Limited16
Medium-term notes	4.1	%	2021-2047	3,290		3,490
Senior debentures				—		75
Debentures	8.7	%	2025	125		250
Commercial paper and credit facility draws	2.3	%	2021	275		485
Westcoast Energy Inc.16
Senior secured notes	6.2	%	2019	33		66
Medium-term notes	4.7	%	2019-2041	2,175		2,177
Debentures	8.6	%	2020-2026	375		525
Fair value adjustment - Spectra Energy acquisition				964		1,114
Other22				(348	)	(312	)
Total debt				64,610		65,180
Current maturities				(3,259	)	(2,871	)
Short-term borrowings23				(1,024	)	(1,444	)
Long-term debt				60,327		60,865

1 2018 - US$4,700 million; 2017 - US$4,700 million.

2 On December 21, 2018, Enbridge and Enbridge Income Fund (the Fund) completed a transaction to exchange certain series of the Fund's outstanding medium-term notes (Legacy Fund Notes) for an equal principal amount of newly issued medium term notes of Enbridge, having financial terms that are the same as the financial terms of the Fund Notes. See Debt Exchange discussion below.

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3 2018 - $2,400 million and US$3,200 million; 2017 - $1,650 million and US$1,750 million. For the initial 10 years, the notes carry a fixed interest rate. Subsequently, the interest rate will be floating and set to equal the three-month Bankers' Acceptance Rate or London Interbank Offered Rate (LIBOR) plus a margin.

4 The notes would be converted automatically into Conversion Preference Shares in the event of bankruptcy and related events.

5 2018 - $750 million and US$1,200 million; 2017 - $750 million and US$1,200 million. Carries an interest rate equal to the three-month Bankers' Acceptance Rate plus a margin of 59 basis points or LIBOR plus a margin of 40 or 70 basis points.

6 2018 - $1,906 million and US$69 million; 2017 - $1,593 million and US$907 million.

7 Primarily capital lease obligations.

8 2018 - US$780 million; 2017 - US$391 million.

9 2018 - US$4,550 million; 2017 - US$5,050 million.

10 2018 - US$400 million; 2017 - US$400 million. Carries an interest rate equal to the three-month LIBOR plus a margin of 379.75 basis points.

11 2018 - US$764 million; 2017 - US$1,453 million.

12 2018 - US$920 million; 2017 - US$963 million.

13 Included in medium-term notes is $100 million with a maturity date of 2112.

14 2018 - $1,905 million and US$216 million; 2017 - $1,080 million and US$286 million.

15 2017 - US$400 million.

16 Debt acquired in conjunction with the Merger Transaction (Note 8).

17 2018 - US$173 million; 2017 - US$1,329 million.

18 2018 - US$110 million; 2017 - US$110 million.

19 2018 - US$6,040 million; 2017 - US$5,740 million.

20 2018 - US$400 million; 2017 - US$400 million. Carries an interest rate equal to the three-month LIBOR plus a margin of 70 basis points.

21 2018 - US$1,512 million; 2017 - US$2,254 million.

22 Primarily debt discount and debt issue costs.

23 Weighted average interest rate - 2.3%; 2017 - 1.4%.

SECURED DEBT

Senior secured notes, totaling $183 million as at December 31, 2018, includes project financings for M&N Canada and Express-Platte System. Ownership interests in M&N Canada and certain of its accounts, revenues, business contracts and other assets are pledged as collateral. Express-Platte System notes payable are secured by the assignment of the Express-Platte System transportation receivables and by the Canadian portion of the Express-Platte pipeline system assets.

CREDIT FACILITIES

The following table provides details of our committed credit facilities at December 31, 2018:

		2018
		Total
December 31,	Maturity	Facilities	Draws1	Available
(millions of Canadian dollars)
Enbridge Inc.	2019-2023	5,751	2,008	3,743
Enbridge (U.S.) Inc.	2020	1,932	1,065	867
Enbridge Energy Partners, L.P.2	2022	2,493	1,044	1,449
Enbridge Gas Distribution Inc.	2019-2020	1,018	760	258
Enbridge Pipelines Inc.	2020	3,000	2,200	800
Spectra Energy Partners, LP3,4	2022	3,414	2,065	1,349
Union Gas Limited4	2021	700	275	425
Total committed credit facilities		18,308	9,417	8,891

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

2 Includes $253 million (US$185 million) of facilities that expire in 2020.

3 Includes $459 million (US$336 million) of facilities that expire in 2021.

4 Committed credit facilities acquired in conjunction with the Merger Transaction (Note 8).

Enbridge terminated a US$650 million credit facility, which was scheduled to mature in 2019, and repaid drawn amounts. In addition, an unutilized Enbridge US$100 million credit facility expired.

Enbridge (U.S.) Inc. terminated an unutilized US$950 million credit facility, which was scheduled to mature in 2019. In addition, Enbridge (U.S.) Inc. terminated a US$500 million credit facility, which was scheduled to mature in 2019, and repaid drawn amounts.

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An unutilized EEP US$625 million credit facility matured on December 31, 2018.

Enbridge Income Fund substantially terminated its $1,500 million credit facility, which was scheduled to mature in 2020, and repaid drawn amounts.

Westcoast Energy Inc. terminated an unutilized $400 million credit facility, which was scheduled to mature in 2021. The facility was acquired in conjunction with the Merger Transaction.

On February 7, 2019 and February 8, 2019, we terminated certain Canadian and United States dollar credit facilities, including facilities held by Enbridge, Union Gas, EEP and SEP. We also increased existing facilities or obtained new facilities to replace the terminated ones under Enbridge, Enbridge (U.S.) Inc. and EGI. As a result, our total credit facility availability increased by approximately $390 millionCanadian dollar equivalent, when translated using the year end December 31, 2018 spot rate.

In addition to the committed credit facilities noted above, we have $807 million of uncommitted demand credit facilities, of which $548 million were unutilized as at December 31, 2018. As at December 31, 2017, we had $792 million of uncommitted credit facilities, of which $518 million were unutilized.

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 we have the option to extend such facilities, which are currently set to mature from 2020 to 2023.

As at December 31, 2018 and 2017, commercial paper and credit facility draws, net of short-term borrowings and non-revolving credit facilities that mature within one year of $7,967 million and $10,055 million, respectively, are supported by the availability of long-term committed credit facilities and therefore have been classified as long-term debt.

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LONG-TERM DEBT ISSUANCES

The following are long-term debt issuances made during 2018 and 2017, excluding the debt exchange discussed below:

Company	Issue Date		Principal Amount
(millions of Canadian dollars unless otherwise stated)
Enbridge Inc.
	March 2018	Fixed-to-floating rate subordinated notes due March 20781	US$850
	April 2018	Fixed-to-floating rate subordinated notes due April 20782		$750
	April 2018	Fixed-to-floating rate subordinated notes due April 20783	US$600
	May 2017	Floating rate notes due May 20194		$750
	June 2017	3.19% medium-term notes due December 2022		$450
	June 2017	3.20% medium-term notes due June 2027		$450
	June 2017	4.57% medium-term notes due March 2044		$300
	June 2017	Floating rate notes due June 20205	US$500
	July 2017	2.90% senior notes due July 2022	US$700
	July 2017	3.70% senior notes due July 2027	US$700
	July 2017	Fixed-to-floating rate subordinated notes due July 20776	US$1,000
	September 2017	Fixed-to-floating rate subordinated notes due September 20777		$1,000
	October 2017	Fixed-to-floating rate subordinated notes due September 20777		$650
	October 2017	Floating rate notes due January 20208	US$700
Enbridge Gas Distribution Inc.
	November 2017	3.51% medium-term notes due November 2047		$300
Spectra Energy Partners, LP
	January 2018	3.50% senior notes due January 20289	US$400
	January 2018	4.15% senior notes due January 20489	US$400
	June 2017	Floating rate notes due June 202010	US$400
Union Gas Limited
	November 2017	2.88% medium-term notes due November 2027		$250
	November 2017	3.59% medium-term notes due November 2047		$250

1 Notes mature in 60 years and are callable on or after year 10. For the initial 10 years, the notes carry a fixed interest rate of 6.25%. Subsequently, the interest rate will be set to equal the three-month LIBOR plus a margin of 364 basis points from years 10 to 30, and a margin of 439 basis points from years 30 to 60.

2 Notes mature in 60 years and are callable on or after year 10. For the initial 10 years, the notes carry a fixed interest rate of 6.625%. Subsequently, the interest rate will be set to equal the Canadian Dollar Offered Rate plus a margin of 432 basis points from years 10 to 30, and a margin of 507 basis points from years 30 to 60.

3 Notes mature in 60 years and are callable on or after year five. For the initial five years, the notes carry a fixed interest rate of 6.375%. Subsequently, the interest rate will be set to equal the three-month LIBOR plus a margin of 359 basis points from years five to 10, a margin of 384 basis points from years 10 to 25, and a margin of 459 basis points from years 25 to 60.

4 Carries an interest rate equal to the three-month Bankers' Acceptance Rate plus 59 basis points.

5 Carries an interest rate equal to the three-month LIBOR plus 70 basis points.

6 Matures in 60 years and are callable on or after year 10. For the initial 10 years, the notes carry a fixed interest rate of 5.5%. Subsequently, the interest rate will be set to equal the three-month LIBOR plus a margin of 342 basis points from year 10 to 30, and a margin of 417 basis points from year 30 to 60.

7 Matures in 60 years and are callable on or after year 10. For the initial 10 years, the notes carry a fixed interest rate of 5.4%. Subsequently, the interest rate will be set to equal the three-month Bankers' Acceptance Rate plus a margin of 325 basis points from year 10 to 30, and a margin of 400 basis points from year 30 to 60.

8 Carries an interest rate equal to the three-month LIBOR plus 40 basis points.

9 Issued through Texas Eastern Transmission, L.P. (Texas Eastern), a wholly-owned operating subsidiary of SEP.

10 Carries an interest rate equal to the three-month LIBOR plus 70 basis points.

LONG-TERM DEBT REPAYMENTS

The following are long-term debt repayments during 2018 and 2017, excluding the debt exchange discussed below:

Company	Retirement/Repayment Date		Principal Amount		Cash Consideration1
(millions of Canadian dollars unless otherwise stated)
Enbridge Inc.
	March 2017	Floating rate notes		$500

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	April 2017	5.60% medium-term notes	US$400
	June 2017	Floating rate notes	US$500
Enbridge Energy Partners, L.P.
	April 2018	6.50% senior notes	US$400
	October 2018	7.00% senior notes	US$100
Enbridge Gas Distribution Inc.
	April 2017	1.85% medium-term notes		$300
	December 2017	5.16% medium-term notes		$200
Enbridge Income Fund
	December 2018	4.00% medium-term notes		$125
	June 2017	5.00% medium-term notes		$100
	December 2017	2.92% medium-term notes		$225
Enbridge Pipelines (Southern Lights) L.L.C.
	June and December 2018	3.98% medium-term notes due June 2040	US$43
	June and December 2017	3.98% medium-term note due June 2040	US$37
Enbridge Pipelines Inc.
	November 2018	6.62% medium-term notes		$170
	November 2018	6.62% medium-term notes		$130
Enbridge Southern Lights LP
	January, July and December 2018	4.01% medium-term notes due June 2040		$27
	June 2017	4.01% medium-term notes due June 2040		$7
Midcoast Energy Partners, L.P.
Redemption
	July 20182	3.56% senior notes due September 2019	US$75		US$76
	July 20182	4.04% senior notes due September 2021	US$175		US$182
	July 20182	4.42% senior notes due September 2024	US$150		US$161
Spectra Energy Capital, LLC
Repurchase via Tender Offer
	March 20182	6.75% senior unsecured notes due 2032	US$64		US$80
	March 20182	7.50% senior unsecured notes due 2038	US$43		US$59
	July 20173	Senior notes carrying interest ranging from 3.3% to 7.5% due 2018 to 2038	US$761		US$857
Redemption
	March 20182	5.65% senior unsecured notes due 2020	US$163		US$172
	March 20182	3.30% senior unsecured notes due 2023	US$498		US$508
	July and September 20173	8.00% senior notes due 2019	US$500		US$581
Repayment
	April 2018	6.20% senior notes	US$272
	July 2018	6.75% senior notes	US$118
Spectra Energy Partners, LP
	September 2018	2.95% senior notes	US$500
	September 2017	6.00% senior notes	US$400
	June and December 2017	7.39% subordinated secured notes	US$12
Union Gas Limited
	April 2018	5.35% medium-term notes		$200
	August 2018	8.75% debentures		$125
	October 2018	8.65% senior debentures		$75
	November 2017	9.70% debentures		$125
Westcoast Energy Inc.
	May and November 2018	6.90% senior secured notes due 2019		$26
	May and November 2018	4.34% senior secured notes due 2019		$9
	September 2018	8.50% debenture		$150
	May and November 2017	6.90% senior secured notes due 2019		$26
	May and November 2017	4.34% senior secured notes due 2019		$24

1 Cash consideration disclosed for repayments where the cash paid differs from the principal amount.

2 The loss on debt extinguishment of $64 million (US$50 million), net of the fair value adjustment recorded upon completion of the Merger Transaction, was reported within Interest expense in the Consolidated Statements of Earnings.

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3 The loss on debt extinguishment of $50 million (US$38 million), net of the fair value adjustment recorded upon completion of the Merger Transaction, was reported within Interest expense in the Consolidated Statements of Earnings.

DEBT EXCHANGE

On December 21, 2018, Enbridge and the Fund completed a transaction to exchange certain series of the Legacy Fund Notes for an equal principal amount of newly issued medium term notes of Enbridge (Enbridge Notes), having financial terms that are the same as the financial terms of the Fund Notes.

The following Enbridge Notes were issued in exchange for the previously held Fund Notes:

• Enbridge 4.10% medium-term notes, due February 22, 2019 issued in exchange for Fund 4.10% medium-term notes, due February 22, 2019 with a principal amount of $300 million;

• Enbridge 4.85% medium-term notes, due November 12, 2020 issued in exchange for Fund 4.85% medium-term notes, due November 12, 2020 with a principal amount of $100 million;

• Enbridge 4.85% medium-term notes, due February 22, 2022 issued in exchange for Fund 4.85% medium-term notes, due February 22, 2022 with a principal amount of $200 million;

• Enbridge 3.94% medium-term notes, due January 13, 2023 issued in exchange for Fund 3.94% medium-term notes, due January 13, 2023 with a principal amount of $275 million;

• Enbridge 3.95% medium-term notes, due November 19, 2024 issued in exchange for Fund 3.95% medium-term notes, due November 19, 2024 with a principal amount of $500 million; and

• Enbridge 4.87% medium-term notes, due November 21, 2044 issued in exchange for Fund 4.87% medium-term notes, due November 21, 2044 with a principal amount of $250 million.

DEBT COVENANTS

Our credit facility agreements and term debt indentures include standard events of default and covenant provisions whereby accelerated repayment and/or termination of the agreements may result if we were to default on payment or violate certain covenants. As at December 31, 2018, we were in compliance with all debt covenants.

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INTEREST EXPENSE

Year ended December 31,	2018		2017		2016
(millions of Canadian dollars)
Debentures and term notes	3,011		3,011		1,714
Commercial paper and credit facility draws	171		206		197
Amortization of fair value adjustment - Spectra Energy acquisition	(131	)	(270	)	—
Capitalized	(348	)	(391	)	(321	)
	2,703		2,556		1,590

19.  ASSET RETIREMENT OBLIGATIONS

Our ARO relate mostly to the retirement of pipelines, renewable power generation assets, obligations related to right-of way agreements and contractual leases for land use.

The liability for the expected cash flows as recognized in the financial statements reflected discount rates ranging from 1.8% to 9.0%.

A reconciliation of movements in our ARO liabilities is as follows:

December 31,	2018		2017
(millions of Canadian dollars)
Obligations at beginning of year	793		232
Liabilities acquired	—		546
Liabilities disposed	(13	)	—
Liabilities incurred	145		—
Liabilities settled	(21	)	(22	)
Change in estimate	29		18
Foreign currency translation adjustment	22		(12	)
Accretion expense	34		31
Obligations at end of year	989		793
Presented as follows:
Accounts payable and other	6		2
Other long-term liabilities	983		791
	989		793

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20.  NONCONTROLLING INTERESTS

NONCONTROLLING INTERESTS

The following table provides additional information regarding Noncontrolling interests as presented in our Consolidated Statements of Financial Position:

December 31,	2018	2017
(millions of Canadian dollars)
Algonquin Gas Transmission, L.L.C1	518	476
Enbridge Energy Management, L.L.C.2	—	34
Enbridge Energy Partners, L.P.3	—	138
Enbridge Gas Distribution Inc.4	—	100
Maritimes & Northeast Pipeline, L.L.C1	613	572
Renewable energy assets5	1,961	806
Spectra Energy Partners, LP6	—	4,335
Union Gas Limited7	—	110
Westcoast Energy Inc.8	841	1,005
Other9	32	21
	3,965	7,597

1 Represents subsidiaries of SEP and the interests in these subsidiaries held by third parties.

2 On December 20, 2018, we executed the definitive agreement with EEM and acquired all of the publicly held shares of EEM not already owned by us or our subsidiaries. As at December 31, 2017, the balance represented 88.3% interest in EEM held by public shareholders.

3 On December 20, 2018, we executed the definitive agreement with EEP and acquired all of the publicly held Class A common units of EEP not already owned by us or our subsidiaries. As at December 31, 2017, the balance represented 68.2% interest in EEP held by public unitholders.

4 On November 29, 2018, EGD redeemed all of its four million cumulative redeemable preferred shares held by third parties. As at December 31, 2017, the balance of these preferred shares was $100 million.

5 On August 1, 2018, we closed the sale of 49% of our interest in the Renewable Assets (Note 8). The remaining balance represents the tax equity investors' interests in Magic Valley, Wildcat, Keechi, New Creek and Chapman Ranch wind facilities, which are accounted for using the HLBV method, with an additional 20.0% noncontrolling interest in each of the Magic Valley and Wildcat wind facilities held by third parties as at December 31, 2018 and 2017.

6 On December 17, 2018, we closed the definitive agreement with SEP and acquired all of the publicly listed common units of SEP not already owned by us or our subsidiaries. As at December 31, 2017, the balance represented 25.7% interest in SEP held by public unitholders.

7 On November 29, 2018, Union Gas redeemed all of its four million cumulative redeemable preferred shares held by third parties. As at December 31, 2017, the balance of these preferred shares was $110 million.

8 Represents the 16.6 million cumulative redeemable preferred shares and 12 million cumulative first preferred shares as at December 31, 2018 and 2017 held by third parties in Westcoast Energy Inc., and the 22.0% interest in Maritimes & Northeast Pipeline Limited Partnership held by third parties as at December 31, 2018 and 2017.

9 Represents subsidiary of EEP and the interests in this subsidiary held by third parties.

United States Sponsored Vehicles Buy-in

On August 24, 2018, we entered into a definitive agreement with SEP under which we agreed to acquire all of the outstanding public common units of SEP not already owned by us or our subsidiaries on the basis of 1.111 of our common shares for each common unit of SEP. Upon the closing of the transaction on December 17, 2018, we acquired all of the public common units of SEP and SEP became an indirect, wholly-owned subsidiary of Enbridge. The transaction is valued at $3.9 billion based on the closing price of our common shares on the New York Stock Exchange on December 14, 2018. As a result of this buy-in, we recorded a decrease in Noncontrolling interests, Additional paid-in capital and Deferred income tax liabilities of $3.0 billion, $642 million and $167 million, respectively.

On September 17, 2018, we entered into definitive agreements with each of EEP and EEM under which we agreed to acquire all of the outstanding public class A common units of EEP and all of the outstanding public listed shares of EEM not already owned by us or our subsidiaries. Under the agreements, EEP public unitholders will receive 0.335 of our common shares for each class A common unit of EEP, and EEM public shareholders will receive 0.335 of our common shares for each listed share of EEM. Upon the closing of the respective transactions on December 20, 2018, we acquired all of the public Class A common units of EEP and shares of EEM, and both EEP and EEM became indirect, wholly-owned subsidiaries of Enbridge. The EEP and EEM transactions are valued at $3.0 billion and $1.3 billion, respectively, based on the closing price of our common shares on the New York Stock Exchange on December 19, 2018. As a result of the buy-ins,

59

collectedly for EEP and EEM, we recorded an increase in Noncontrolling interests and a decrease in Additional paid-in capital and Deferred income tax liabilities of $185 million, $3.7 billion and $707 million, respectively.

For discussion on the roll-up of ENF, refer to CanadianSponsored Vehicles Buy-in under Redeemable Noncontrolling Interests below.

Renewable Assets

On August 1, 2018, we closed the sale of a 49% interest in all of our Canadian renewable assets and a 49% interest in two United States renewable assets to CPPIB (Note 8). As a result, we recorded an increase in Noncontrolling interests, Additional paid-in capital and Deferred income tax liabilities of $1,183 million, $79 million and $27 million, respectively, in the third quarter of 2018. For 2018, CPPIB's distributions and allocation of earnings were not proportionate to its ownership.

SEP Incentive Distribution Rights

As at December 31, 2017, we collectively owned a 75% ownership interest in SEP, together with 100% of SEP's incentive distribution rights (IDRs). On January 22, 2018, Enbridge and SEP announced the execution of a definitive agreement, resulting in us converting all of our IDRs and general partner economic interests in SEP into 172.5 million newly issued SEP common units. As part of the transaction, all of the IDRs were eliminated. In the first quarter of 2018, we held a non-economic general partner interest in SEP and owned approximately 403 million SEP common units, representing approximately 83% of SEP's outstanding common units. As a result of this restructuring, we recorded a decrease in Noncontrolling interests of $1.5 billion and increases in Additional paid-in capital and Deferred income tax liabilities of $1.1 billion and $333 million, respectively. Subsequently in 2018, we acquired all of the outstanding common units of SEP (refer to United States Sponsored Vehicles Buy-in above).

Enbridge Energy Partners, L.P.

United States Sponsored Vehicle Strategy

On April 28, 2017, we completed a strategic review of EEP and took the actions described below. As a result of these actions, we recorded an increase in Noncontrolling interests of $458 million, inclusive of foreign currency translation adjustments, and a decrease in Additional paid-in capital of $421 million, net of deferred income taxes of $253 million.

Acquisition of Midcoast Assets and Privatization of MEP

On April 27, 2017, we completed our previously-announced merger through a wholly-owned subsidiary, through which we privatized MEP by acquiring all of the outstanding publicly-held common units of MEP for total consideration of approximately US$170 million.

On June 28, 2017, we acquired, through a wholly-owned subsidiary, all of EEP’s interest in the Midcoast gas gathering and processing business for cash consideration of US$1.3 billion plus existing indebtedness of MEP of US$953 million.

As a result of the above transactions, 100% of the Midcoast gas gathering and processing business was owned by us and subsequently sold on August 1, 2018 (see Note 8 - Acquisitions and Dispositions for further details).

EEP Strategic Restructuring Actions

On April 27, 2017, EEP redeemed all of its outstanding Series 1 Preferred Units held by us at face value of US$1.2 billion through the issuance of 64.3 million Class A common units to us. We also irrevocably waived all of our rights associated with our ownership of 66.1 million Class D units and 1,000 Incentive Distribution Units of EEP, in exchange for the issuance of 1,000 Class F units. The Class F units are entitled to (i) 13% of all distributions in excess of US$0.295 per EEP unit, but equal to or less than US$0.35 per EEP unit, and (ii) 23% of all distributions in excess of US$0.35 per EEP unit. The irrevocable waiver was effective with respect to distributions declared with a record date after April 27, 2017. In connection with these strategic restructuring actions, EEP reduced its quarterly distribution from US$0.583 per unit to US$0.35 per unit. Further, in conjunction with the restructuring actions, EEP terminated a receivable purchase agreement with a special purpose entity wholly-owned by us.

Finalization of Bakken Pipeline System Joint Funding Agreement

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On April 27, 2017, we entered into a joint funding arrangement with EEP. Pursuant to this joint funding arrangement, we own 75% and EEP owns 25% of the combined 27.6% effective interest in the Bakken Pipeline System. Under this arrangement, EEP retains a five-year option to acquire an additional 20% interest in the Bakken Pipeline System. Upon the execution of the joint funding arrangement, EEP repaid the outstanding balance on its US$1.5 billion credit agreement with us, which it had drawn upon to fund the initial purchase.

REDEEMABLE NONCONTROLLING INTERESTS

The following table presents additional information regarding Redeemable noncontrolling interests as presented in our Consolidated Statements of Financial Position:

Year ended December 31,	2018		2017		2016
(millions of Canadian dollars)
Balance at beginning of year	4,067		3,392		2,141
Earnings attributable to redeemable noncontrolling interests	117		175		268
Other comprehensive income/(loss), net of tax
Change in unrealized loss on cash flow hedges	3		(21	)	(17	)
Other comprehensive loss from equity investees	14		—		—
Reclassification to earnings of loss on cash flow hedges	—		57		9
Foreign currency translation adjustments	4		(6	)	(3	)
Other comprehensive income/(loss), net of tax	21		30		(11	)
Distributions to unitholders	(300	)	(247	)	(202	)
Contributions from unitholders	70		1,178		591
Modified retrospective adoption of accounting standard (note 3)	(38	)	—		—
Net dilution gain/(loss)	76		(169	)	(81	)
Redemption value adjustment	456		(292	)	686
Sponsored vehicle buy-in1	(4,469	)	—		—
Balance at end of year	—		4,067		3,392

1 On November 8, 2018, we executed the definitive agreement with ENF and acquired all of the publicly held shares of ENF not

already owned by us or our subsidiaries.

Canadian Sponsored Vehicle Buy-in

On September 17, 2018, we entered into a definitive agreement with ENF under which we would acquire all of the outstanding public common shares of ENF not already owned by us or our subsidiaries on the basis of 0.735 of our common shares and cash of $0.45 for each common share of ENF. Upon the closing of the transaction on November 8, 2018, we acquired all of the public common shares of ENF and ENF become a wholly-owned subsidiary of Enbridge. The transaction, excluding the cash component, is valued at $4.5 billion based on the closing price of our common shares on the Toronto Stock Exchange on November 7, 2018. As a result of this buy-in, we recorded a decrease in Redeemable noncontrolling interests and Additional paid-in capital of $4.5 billion and $25 million, respectively, with nil deferred tax impact.

As at December 31, 2017 and 2016, Redeemable Noncontrolling Interest represented56.5% and 45.6%, respectively, of interests in the Fund’s trust units that are held by third parties.

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21.  SHARE CAPITAL

Our authorized share capital consists of an unlimited number of common shares with no par value and an unlimited number of preference shares.

COMMON SHARES

	2018		2017		2016
	Number		Number		Number
December 31,	of Shares	Amount	of Shares	Amount	of Shares	Amount
(millions of Canadian dollars; number of shares in millions)
Balance at beginning of year	1,695	50,737	943	10,492	868	7,391
Common shares issued1	—	—	33	1,500	56	2,241
Common shares issued in Merger Transaction (Note 8)	—	—	691	37,429	—	—
Common shares issued in Sponsored Vehicle buy-in (SEP) (Note 20)	91	3,888	—	—	—	—
Common shares issued in Sponsored Vehicle buy-in (EEP) (Note 20)	72	3,042	—	—	—	—
Common shares issued in Sponsored Vehicle buy-in (EEM) (Note 20)	30	1,267	—	—	—	—
Common shares issued in Sponsored Vehicle buy-in (ENF) (Note 20)	104	4,530	—	—	—	—
Dividend Reinvestment and Share Purchase Plan	28	1,181	25	1,226	16	795
Shares issued on exercise of stock options	2	32	3	90	3	65
Balance at end of year	2,022	64,677	1,695	50,737	943	10,492

1Gross proceeds of nil, $1.5 billion and $2.3 billion for the years ended December 31, 2018, 2017 and 2016, respectively; net issuance costs of nil, nil and $59 million for the years ended December 31, 2018, 2017 and 2016, respectively.

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PREFERENCE SHARES

	2018			2017			2016
	Number			Number			Number
December 31,	of Shares	Amount		of Shares	Amount		of Shares	Amount
(millions of Canadian dollars; number of shares in millions)
Preference Shares, Series A	5	125		5	125		5	125
Preference Shares, Series B	18	457		18	457		20	500
Preference Shares, Series C	2	43		2	43		—	—
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		30	750		30	750
Preference Shares, Series 19	20	500		20	500		—	—
Issuance costs		(155	)		(155	)		(147	)
Balance at end of year		7,747			7,747			7,255

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Characteristics of the preference shares are as follows:

	Dividend Rate		Dividend1	Per Share Base Redemption Value2	Redemption and Conversion Option Date2,3	Right to Convert Into3,4
(Canadian dollars unless otherwise stated)
Preference Shares, Series A	5.50	%	$1.37500	$25	—	—
Preference Shares, Series B	3.42	%	$0.85360	$25	June 1, 2022	Series C
Preference Shares, Series C5	3-month treasury bill plus 2.40%		—	$25	June 1, 2022	Series B
Preference Shares, Series D6	4.46	%	$1.11500	$25	March 1, 2023	Series E
Preference Shares, Series F6	4.69	%	$1.17225	$25	June 1, 2023	Series G
Preference Shares, Series H6	4.38	%	$1.09400	$25	September 1, 2023	Series I
Preference Shares, Series J	4.89	%	US$1.22160	US$25	June 1, 2022	Series K
Preference Shares, Series L	4.96	%	US$1.23972	US$25	September 1, 2022	Series M
Preference Shares, Series N6	5.09	%	$1.27150	$25	December 1, 2023	Series O
Preference Shares, Series P	4.00	%	$1.00000	$25	March 1, 2019	Series Q
Preference Shares, Series R	4.00	%	$1.00000	$25	June 1, 2019	Series S
Preference Shares, Series 16	5.95	%	US$1.48728	US$25	June 1, 2023	Series 2
Preference Shares, Series 3	4.00	%	$1.00000	$25	September 1, 2019	Series 4
Preference Shares, Series 5	4.40	%	US$1.10000	US$25	March 1, 2019	Series 6
Preference Shares, Series 7	4.40	%	$1.10000	$25	March 1, 2019	Series 8
Preference Shares, Series 9	4.40	%	$1.10000	$25	December 1, 2019	Series 10
Preference Shares, Series 11	4.40	%	$1.10000	$25	March 1, 2020	Series 12
Preference Shares, Series 13	4.40	%	$1.10000	$25	June 1, 2020	Series 14
Preference Shares, Series 15	4.40	%	$1.10000	$25	September 1, 2020	Series 16
Preference Shares, Series 17	5.15	%	$1.28750	$25	March 1, 2022	Series 18
Preference Shares, Series 19	4.90	%	$1.22500	$25	March 1, 2023	Series 20

1 The holder is entitled to receive a fixed, cumulative, quarterly preferential dividend, as declared by the Board of Directors. With the exception of Series A and Series C Preference Shares, such fixed dividend rate resets every five years beginning on the initial redemption and conversion option date. The Series 17 and Series 19 Preference Shares contain a feature where the fixed dividend rate, when reset every five years, will not be less than 5.15% and 4.90%, respectively. No other series of Preference Shares has this feature.

2 Series A Preference Shares may be redeemed any time at our option. For all other series of Preference Shares, we, may at our 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 3.2% (Series 20); 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).

5 The floating quarterly dividend amount for the Series C Preference Shares was increased to $0.22685 from $0.20342 on March 1, 2018, was increased to $0.22748 from $0.22685 on June 1, 2018, was increased to $0.23934 from $0.22748 on September 1, 2018 and was increased to $0.25459 from $0.23934 on December 1, 2018, due to reset on a quarterly basis following the issuance thereof.

6 No Series D, F, H, N, or 1 Preference shares were converted on the March 1, 2018, June 1, 2018, September 1, 2018, December 1, 2018 or June 1, 2018 conversion option dates, respectively. However, the quarterly dividend amounts for Series D, F, H, N, and 1, were increased to $0.27875 from $0.25000 on March 1, 2018, $0.29306 from $0.25000 on June 1, 2018, $0.27350 from $0.25000 on September 1, 2018, $0.31788 from $0.25000 on December 1, 2018 and US$0.37182 from US$0.25000 on June 1, 2018, respectively, due to reset on every fifth anniversary thereafter.

DIVIDEND REINVESTMENT AND SHARE PURCHASE PLAN

On November 2, 2018, we announced the suspension of our DRIP, effective immediately. Prior to the announcement, our shareholders were able to participate in the DRIP, which enabled participants to reinvest their dividends in our common shares at a 2% discount to market price and to make additional optional cash payments to purchase common shares at the market price, free of brokerage or other charges. Refer to Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Share Issuances for details on dividends paid.

SHAREHOLDER RIGHTS PLAN

The Shareholder Rights Plan is designed to encourage the fair treatment of shareholders in connection with any takeover offer for us. 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 our outstanding common shares without complying with certain provisions set out in the plan or without approval of our Board of Directors. Should such

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an acquisition occur, each rights holder, other than the acquiring person and related parties, will have the right to purchase our common shares at a 50% discount to the market price at that time.

22.  STOCK OPTION AND STOCK UNIT PLANS

We maintain four long-term incentive compensation plans: the ISO Plan, the Performance Stock Options (PSO) Plan, the Performance Stock Units (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 under the 2007 ISO and PSO Plans, of which 17 million have been issued to date. The PSU and RSU Plans grant notional units as if a unit was one Enbridge common share and are payable in cash.

Prior to the Merger Transaction, Spectra Energy had a long-term incentive plan providing for the granting of stock options, restricted and unrestricted stock awards and units, and other equity-based awards. Upon closing of the Merger Transaction, Enbridge replaced existing Spectra Energy share-based payment awards with awards that will be settled in shares of Enbridge, with Spectra Energy's cash-settled phantom awards included in the fair value of the net assets acquired (Note 8).

Total stock-based compensation expense recorded for the years ended December 31, 2018, 2017 and 2016 was $106 million, $165 million and $130 million, respectively. Disclosure of activity and assumptions for material stock-based compensation plans are included below.

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INCENTIVE STOCK OPTIONS

Key employees are granted ISOs to purchase common shares at the market price on the grant date. ISOs vest in equal annual installments over a four-year period and expire 10 years after the issue date.

December 31, 2018	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	34,366		45.41
Options granted	5,775		32.32
Options exercised1	(2,519	)	27.11
Options cancelled or expired	(3,235	)	44.11
Options outstanding at end of year	34,387		43.47	6.1	108
Options vested at end of year2	21,064		43.48	4.7	84

1 The total intrinsic value of ISOs exercised during the years ended December 31, 2018, 2017 and 2016 was $42 million, $62 million and $123 million, respectively, and cash received on exercise was $15 million, $17 million and $37 million, respectively.

2 The total fair value of ISOs vested during the years ended December 31, 2018, 2017 and 2016 was $36 million, $44 million and $36 million, respectively.

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

Year ended December 31,	2018		2017		2016
Fair value per option(Canadian dollars)1	3.86		6.00		7.37
Valuation assumptions
Expected option term(years)2	5		5		5
Expected volatility3	21.9	%	20.4	%	25.1	%
Expected dividend yield4	6.4	%	4.4	%	4.4	%
Risk-free interest rate5	2.2	%	1.2	%	0.8	%

1 Options granted to United States employees are based on NYSE 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 for the years ended December 31, 2018, 2017 and 2016 were $3.75, $5.66 and $7.01, respectively, for Canadian employees and US$3.30, US$5.72 and US$6.60, respectively, 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 years ended December 31, 2018, 2017 and 2016 for ISOs was $28 million, $40 million and $43 million, respectively. As at December 31, 2018, unrecognized compensation expense related to non-vested stock-based compensation arrangements granted under the ISO Plan was $23 million. The expense is expected to be fully recognized over a weighted average period of approximately two years.

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RESTRICTED STOCK UNITS

We have a RSU Plan where cash awards are paid to certain of our employees following a 35-month maturity period. RSU holders receive cash equal to our weighted average share price for 20 days prior to the maturity of the grant multiplied by the units outstanding on the maturity date.

December 31, 2018	Number		Weighted Average Remaining Contractual Life (years)	Aggregate Intrinsic Value
(units in thousands; intrinsic value in millions of Canadian dollars)
Units outstanding at beginning of year	1,693
Units granted	542
Units cancelled	(191	)
Units matured1	(971	)
Dividend reinvestment	140
Units outstanding at end of year	1,213		1.3	52

1 The total amount paid during the years ended December 31, 2018, 2017 and 2016 for RSUs was $41 million, $39 million and $56 million, respectively.

Compensation expense recorded for the years ended December 31, 2018, 2017 and 2016 for RSUs was $32 million, $46 million and $51 million, respectively. As at December 31, 2018, unrecognized compensation expense related to non-vested units granted under the RSU Plan was $26 million. The expense is expected to be fully recognized over a weighted average period of approximately two years.

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

Changes in AOCI attributable to our common shareholders for the years ended December 31, 2018, 2017 and 2016 are as follows:

	Cash Flow Hedges		Net Investment Hedges		Cumulative Translation Adjustment		Equity Investees	Pension and OPEB Adjustment		Total
(millions of Canadian dollars)
Balance at January 1, 2018	(644	)	(139	)	77		10	(277	)	(973	)
Other comprehensive income/(loss) retained in AOCI	(244	)	(509	)	4,301		16	(85	)	3,479
Other comprehensive (income)/loss reclassified to earnings
Interest rate contracts1	157		—		—		—	—		157
Commodity contracts2	(1	)	—		—		—	—		(1	)
Foreign exchange contracts3	7		—		—		—	—		7
Other contracts4	22		—		—		—	—		22
Amortization of pension and OPEB actuarial loss and prior service costs5	—		—		—		—	16		16
	(59	)	(509	)	4,301		16	(69	)	3,680
Tax impact
Income tax on amounts retained in AOCI	57		50		—		8	33		148
Income tax on amounts reclassified to earnings	(37	)	—		—		—	(4	)	(41	)
	20		50		—		8	29		107
Sponsored Vehicles buy-in6	(87	)	—		(55	)	—	—		(142	)
Balance at December 31, 2018	(770	)	(598	)	4,323		34	(317	)	2,672

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	Cash Flow Hedges		Net Investment Hedges		Cumulative Translation Adjustment		Equity Investees		Pension and OPEB Adjustment		Total
(millions of Canadian dollars)
Balance at January 1, 2017	(746	)	(629	)	2,700		37		(304	)	1,058
Other comprehensive income/(loss) retained in AOCI	1		478		(2,623	)	(11	)	18		(2,137	)
Other comprehensive (income)/loss reclassified to earnings
Interest rate contracts1	207		—		—		—		—		207
Commodity contracts2	(7	)	—		—		—		—		(7	)
Foreign exchange contracts3	(6	)	—		—		—		—		(6	)
Other contracts4	(6	)	—		—		—		—		(6	)
Amortization of pension and OPEB actuarial loss and prior service costs5	—		—		—		—		41		41
	189		478		(2,623	)	(11	)	59		(1,908	)
Tax impact
Income tax on amounts retained in AOCI	(16	)	12		—		(16	)	(10	)	(30	)
Income tax on amounts reclassified to earnings	(71	)	—		—		—		(22	)	(93	)
	(87	)	12		—		(16	)	(32	)	(123	)
Balance at December 31, 2017	(644	)	(139	)	77		10		(277	)	(973	)

	Cash Flow Hedges		Net Investment Hedges		Cumulative Translation Adjustment		Equity Investees		Pension and OPEB 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 and 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

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 benefit costs and are reported within Operating and administrative expense in the Consolidated Statements of Earnings.

6 Represents the historical noncontrolling interests and redeemable noncontrolling interests related to the Sponsored Vehicles reclassified to AOCI, upon the completion of the buy-in.

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24.  RISK MANAGEMENT AND FINANCIAL INSTRUMENTS

MARKET RISK

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

The following summarizes the types of market risks to which we are exposed and the risk management instruments used to mitigate them. We use a combination of qualifying and non-qualifying derivative instruments to manage the risks noted below.

Foreign Exchange Risk

We generate certain revenues, incur expenses, and hold a number of investments and subsidiaries that are denominated in currencies other than Canadian dollars. As a result, our earnings, cash flows and OCI are exposed to fluctuations resulting from foreign exchange rate variability.

We employ financial derivative instruments to hedge foreign currency denominated earnings exposure. A combination of qualifying and non-qualifying derivative instruments are used to hedge anticipated foreign currency denominated revenues and expenses, and to manage variability in cash flows. We hedge certain net investments in United States dollar denominated investments and subsidiaries using foreign currency derivatives and United States dollar denominated debt.

Interest Rate Risk

Our earnings and cash flows are exposed to short-term interest rate variability due to the regular repricing of our variable rate debt, primarily commercial paper. Pay fixed-receive floating interest rate swaps may be used to hedge against the effect of future interest rate movements. We have 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 2.8%.

We are exposed to changes in the fair value of fixed rate debt that arise as a result of the changes in market interest rates. Pay floating-receive fixed interest rate swaps are used, when applicable, to hedge against future changes to the fair value of fixed rate debt which mitigates the impact of fluctuations in the fair value of fixed rate debt via execution of fixed to floating interest rate swaps. As of December 31, 2018, we do not have any pay floating-receive fixed interest rate swaps outstanding.

Our earnings and cash flows are also exposed to variability in longer term interest rates ahead of anticipated fixed rate term debt issuances. Forward starting interest rate swaps are used to hedge against the effect of future interest rate movements. We have established a program within some of our subsidiaries to mitigate our 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 3.2%.

We also monitor our debt portfolio mix of fixed and variable rate debt instruments to manage a consolidated portfolio of floating rate debt within the Board of Directors approved policy limit of a maximum of 30% of floating rate debt as a percentage of total debt outstanding. We primarily use qualifying derivative instruments to manage interest rate risk.

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Commodity Price Risk

Our earnings and cash flows are exposed to changes in commodity prices as a result of our ownership interests in certain assets and investments, as well as through the activities of our energy services subsidiaries. These commodities include natural gas, crude oil, power and NGL. We employ financial and physical derivative instruments to fix a portion of the variable price exposures that arise from physical transactions involving these commodities. We use 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 our share price. We have exposure to our 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. We use equity derivatives to manage the earnings volatility derived from one form of stock-based compensation, restricted share units. We use 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 our derivative instruments.

We generally have a policy of entering into individual International Swaps and Derivatives Association, Inc. agreements, or other similar derivative agreements, with the majority of our financial 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 events, and reduces our credit risk exposure on financial derivative asset positions outstanding with the counterparties in those circumstances. The following table summarizes the maximum potential settlement amounts in the event of these specific circumstances. All amounts are presented gross in the Consolidated Statements of Financial Position.

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December 31, 2018	Derivative Instruments Used as Cash Flow Hedges		Derivative Instruments Used as Net Investment Hedges		Derivative Instruments Used as Fair Value Hedges	Non- Qualifying Derivative Instruments		Total Gross Derivative Instruments as Presented		Amounts Available for Offset		Total Net Derivative Instruments
(millions of Canadian dollars)
Accounts receivable and other
Foreign exchange contracts	—		—		—	47		47		(37	)	10
Interest rate contracts	22		—		—	—		22		(2	)	20
Commodity contracts	2		—		—	427		429		(114	)	315
	24		—		—	474		498		(153	)	345
Deferred amounts and other assets
Foreign exchange contracts	23		—		—	39		62		(39	)	23
Interest rate contracts	5		—		—	—		5		—		5
Commodity contracts	19		—		—	33		52		(21	)	31
	47		—		—	72		119		(60	)	59
Accounts payable and other
Foreign exchange contracts	(5	)	—		—	(610	)	(615	)	37		(578	)
Interest rate contracts	(163	)	—		—	(178	)	(341	)	2		(339	)
Commodity contracts	—		—		—	(273	)	(273	)	114		(159	)
Other contracts	(1	)	—		—	(4	)	(5	)	—		(5	)
	(169	)	—		—	(1,065	)	(1,234	)	153		(1,081	)
Other long-term liabilities
Foreign exchange contracts	(1	)	(15	)	—	(2,196	)	(2,212	)	39		(2,173	)
Interest rate contracts	(201	)	—		—	—		(201	)	—		(201	)
Commodity contracts	—		—		—	(178	)	(178	)	21		(157	)
Other contracts	(1	)	—		—	(1	)	(2	)	—		(2	)
	(203	)	(15	)	—	(2,375	)	(2,593	)	60		(2,533	)
Total net derivative asset/(liability)
Foreign exchange contracts	17		(15	)	—	(2,720	)	(2,718	)	—		(2,718	)
Interest rate contracts	(337	)	—		—	(178	)	(515	)	—		(515	)
Commodity contracts	21		—		—	9		30		—		30
Other contracts	(2	)	—		—	(5	)	(7	)	—		(7	)
	(301	)	(15	)	—	(2,894	)	(3,210	)	—		(3,210	)

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December 31, 2017	Derivative Instruments Used as Cash Flow Hedges		Derivative Instruments Used as Net Investment Hedges		Derivative Instruments Used as Fair Value Hedges		Non- Qualifying Derivative Instruments		Total Gross Derivative Instruments as Presented		Amounts Available for Offset		Total Net Derivative Instruments
(millions of Canadian dollars)
Accounts receivable and other
Foreign exchange contracts	1		4		—		138		143		(83	)	60
Interest rate contracts	6		—		2		—		8		(3	)	5
Commodity contracts	2		—		—		143		145		(64	)	81
	9		4		2		281		296		(150	)	146
Deferred amounts and other assets
Foreign exchange contracts	1		1		—		143		145		(125	)	20
Interest rate contracts	7		—		6		—		13		(2	)	11
Commodity contracts	17		—		—		6		23		(19	)	4
	25		1		6		149		181		(146	)	35
Accounts payable and other
Foreign exchange contracts	(5	)	(42	)	—		(312	)	(359	)	83		(276	)
Interest rate contracts	(140	)	—		(6	)	(183	)	(329	)	3		(326	)
Commodity contracts	—		—		—		(439	)	(439	)	64		(375	)
Other contracts	(1	)	—		—		(2	)	(3	)	—		(3	)
	(146	)	(42	)	(6	)	(936	)	(1,130	)	150		(980	)
Other long-term liabilities
Foreign exchange contracts	(4	)	(9	)	—		(1,299	)	(1,312	)	125		(1,187	)
Interest rate contracts	(38	)	—		(2	)	—		(40	)	2		(38	)
Commodity contracts	—		—		—		(186	)	(186	)	19		(167	)
Other contracts	(1	)	—		—		—		(1	)	—		(1	)
	(43	)	(9	)	(2	)	(1,485	)	(1,539	)	146		(1,393	)
Total net derivative asset/(liability)
Foreign exchange contracts	(7	)	(46	)	—		(1,330	)	(1,383	)	—		(1,383	)
Interest rate contracts	(165	)	—		—		(183	)	(348	)	—		(348	)
Commodity contracts	19		—		—		(476	)	(457	)	—		(457	)
Other contracts	(2	)	—		—		(2	)	(4	)	—		(4	)
	(155	)	(46	)	—		(1,991	)	(2,192	)	—		(2,192	)

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

	2018													2017
As at December 31,	2019		2020		2021		2022		2023		Thereafter			Total
Foreign exchange contracts - United States dollar forwards - purchase(millions of United States dollars)	925		1		—		—		—		—			759
Foreign exchange contracts - United States dollar forwards - sell(millions of United States dollars)	4,969		4,893		3,608		1,944		1,804		1,857			16,167
Foreign exchange contracts - British pound (GBP) forwards - purchase(millions of GBP)	—		—		—		—		—		—			18
Foreign exchange contracts - GBP forwards - sell(millions of GBP)	89		25		27		28		29		120			318
Foreign exchange contracts - Euro forwards - purchase (millions of Euro)	226		—		—		—		—		—			655
Foreign exchange contracts - Euro forwards - sell (millions of Euro)	—		23		94		94		92		606			1,262
Foreign exchange contracts - Japanese yen forwards - purchase(millions of yen)	32,662		—		—		20,000		—		—			52,662
Interest rate contracts - short-term pay fixed rate(millions of Canadian dollars)	8,616		6,243		4,188		412		49		156			7,138
Interest rate contracts - long-term receive fixed rate (millions of Canadian dollars)	—		—		—		—		—		—			4,196
Interest rate contracts - long-term pay fixed rate (millions of Canadian dollars)	3,777		3,185		1,596		—		—		—			5,402
Equity contracts(millions of Canadian dollars)	35		20		—		—		—		—			90
Commodity contracts - natural gas(billions of cubic feet)	(141	)	(16	)	(6	)	(4	)	—		—			(159	)
Commodity contracts - crude oil(millions of barrels)	4		—		—		—		—		—			(3	)
Commodity contracts - NGL(millions of barrels)	—		—		—		—		—		—			(12	)
Commodity contracts - power(megawatt per hour (MW/H))	64		66		(3	)	(43	)	(43	)	(43	)	1	(43	)	2

1 As at December 31, 2018, thereafter includes an average net purchase/(sell) of power of (43) MW/H for 2024 through 2025.

2 As at December 31, 2017, thereafter includes an average net purchase/(sell) of power of (43) MW/H for 2023 through 2025.

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

The following table presents the effect of cash flow hedges and net investment hedges on our consolidated earnings and consolidated comprehensive income, before the effect of income taxes:

	2018		2017		2016
(millions of Canadian dollars)
Amount of unrealized gain/(loss) recognized in OCI
Cash flow hedges
Foreign exchange contracts	19		(5	)	(19	)
Interest rate contracts	(190	)	6		(90	)
Commodity contracts	2		11		14
Other contracts	(3	)	1		39
Net investment hedges
Foreign exchange contracts	31		284		22
	(141	)	297		(34	)
Amount of (gain)/loss reclassified from AOCI to earnings(effective portion)
Foreign exchange contracts1	5		(104	)	2
Interest rate contracts2,3	161		388		145
Commodity contracts4	(1	)	(9	)	(12	)
Other contracts5	3		8		(29	)
	168		283		106
Amount of (gain)/loss reclassified from AOCI to earnings(ineffective portion and amount excluded from effectiveness testing)
Interest rate contracts2, 3	23		(4	)	61
	23		(4	)	61

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

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

3 For the year ended December 31, 2017, includes settlements of $296 million loss related to the termination of long-term interest rate swaps as not highly probable to issue long-term debt.

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

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

We estimate that a loss of $18 million from 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 we are hedging exposures to the variability of cash flows is 36 months as at December 31, 2018.

Fair Value Derivatives

For interest rate derivative instruments that are designated and qualify as fair value hedges, the gain or loss on the derivative as well as the offsetting loss or gain on the hedged item attributable to the hedged risk is included in Interest expense in the Consolidated Statements of Earnings.

Year ended December 31,	2018		2017
(millions of Canadian dollars)
Unrealized gain/(loss) on derivative	7		(10	)
Unrealized gain/(loss) on hedged item	1		11
Realized gain/(loss) on derivative	(8	)	2
Realized gain/(loss) on hedged item	(1	)	(2	)

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Non-Qualifying Derivatives

The following table presents the unrealized gains and losses associated with changes in the fair value of our non-qualifying derivatives:

Year ended December 31,	2018		2017		2016
(millions of Canadian dollars)
Foreign exchange contracts1	(1,390	)	1,284		935
Interest rate contracts2	5		157		73
Commodity contracts3	485		(199	)	(508	)
Other contracts4	(3	)	—		9
Total unrealized derivative fair value gain/(loss), net	(903	)	1,242		509

1 For the respective annual periods, reported within Transportation and other services revenues (2018 - $1,108 million loss; 2017 - $800 million gain; 2016 - $497 million gain) and Other income/(expense) (2018 - $282 million loss; 2017 - $484 million gain; 2016 - $438 million gain) in the Consolidated Statements of Earnings.

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

3 For the respective annual periods, reported within Transportation and other services revenues (2018 - $66 million gain; 2017 - $104 million loss; 2016 - $52 million loss), Commodity sales (2018 - $599 million gain; 2017 - $90 million gain; 2016 - $474 million loss), Commodity costs (2018 - $193 million loss; 2017 - $223 million loss; 2016 - $38 million gain) and Operating and administrative expense (2018 - $13 million gain; 2017 - $38 million gain; 2016 - $20 million loss) in the Consolidated Statements of Earnings.

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

LIQUIDITY RISK

Liquidity risk is the risk that we will not be able to meet our financial obligations, including commitments and guarantees, as they become due. In order to mitigate this risk, we forecast cash requirements over a 12 month rolling time period to determine whether sufficient funds will be available and maintain substantial capacity under our committed bank lines of credit to address any contingencies. Our 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. We also maintain 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, we maintain sufficient liquidity through committed credit facilities with a diversified group of banks and institutions which, if necessary, enables us to fund all anticipated requirements for approximately one year without accessing the capital markets. We are in compliance with all the terms and conditions of our committed credit facility agreements and term debt indentures as at December 31, 2018. As a result, all credit facilities are available to us and the banks are obligated to fund and have been funding us under the terms of the facilities.

CREDIT RISK

Entering into derivative instruments may result in exposure to credit risk from the possibility that a counterparty will default on its contractual obligations. In order to mitigate this risk, we enter into risk management transactions primarily with institutions that possess strong investment grade credit ratings. Credit risk relating to derivative counterparties is mitigated through maintenance and monitoring of 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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We have credit concentrations and credit exposure, with respect to derivative instruments, in the following counterparty segments:

December 31,	2018	2017
(millions of Canadian dollars)
Canadian financial institutions	28	82
United States financial institutions	107	19
European financial institutions	84	145
Asian financial institutions	6	2
Other1	337	137
	562	385

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

As at December 31, 2018, we provided letters of credit totaling nil in lieu of providing cash collateral to our counterparties pursuant to the terms of the relevant ISDA agreements. We held no cash collateral on derivative asset exposures as at December 31, 2018 and December 31, 2017.

Gross derivative balances have been presented without the effects of collateral posted. Derivative assets are adjusted for non-performance risk of our counterparties using their credit default swap spread rates, and are reflected at fair value. For derivative liabilities, our 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 EGD and Union Gas, credit risk is mitigated by the utilities' large and diversified customer base and the ability to recover an estimate for doubtful accounts through the ratemaking process. We actively monitor the financial strength of large industrial customers and, in select cases, have obtained additional security to minimize the risk of default on receivables. Generally, we classify and provide 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

Our financial assets and liabilities measured at fair value on a recurring basis include derivative instruments. We also disclose the fair value of other financial instruments not measured at fair value. The fair value of financial instruments reflects our best estimates of market value based on generally accepted valuation techniques or models and is supported by observable market prices and rates. When such values are not available, we use discounted cash flow analysis from applicable yield curves based on observable market inputs to estimate fair value.

FAIR VALUE OF FINANCIAL INSTRUMENTS

We categorize our 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. Our 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

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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.

We have also categorized the fair value of our held to maturity preferred share investment and long-term debt as Level 2. The fair value of our held to maturity preferred share investment is primarily based on the yield of certain Government of Canada bonds. The fair value of our 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. We have 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. We do not have any other financial instruments categorized in Level 3.

We use the most observable inputs available to estimate the fair value of our derivatives. When possible, we estimate the fair value of our derivatives based on quoted market prices. If quoted market prices are not available, we use estimates from third party brokers. For non-exchange traded derivatives classified in Levels 2 and 3, we use 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, we use observable market prices (interest, foreign exchange, commodity and share price) and volatility as primary inputs to these valuation techniques. Finally, we consider our own credit default swap spread as well as the credit default swap spreads associated with our counterparties in our estimation of fair value.

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We have categorized our derivative assets and liabilities measured at fair value as follows:

December 31, 2018	Level 1		Level 2		Level 3		Total Gross Derivative Instruments
(millions of Canadian dollars)
Financial assets
Current derivative assets
Foreign exchange contracts	—		47		—		47
Interest rate contracts	—		22		—		22
Commodity contracts	24		45		360		429
	24		114		360		498
Long-term derivative assets
Foreign exchange contracts	—		62		—		62
Interest rate contracts	—		5		—		5
Commodity contracts	—		30		22		52
	—		97		22		119
Financial liabilities
Current derivative liabilities
Foreign exchange contracts	—		(615	)	—		(615	)
Interest rate contracts	—		(341	)	—		(341	)
Commodity contracts	(7	)	(28	)	(238	)	(273	)
Other contracts	—		(5	)	—		(5	)
	(7	)	(989	)	(238	)	(1,234	)
Long-term derivative liabilities
Foreign exchange contracts	—		(2,212	)	—		(2,212	)
Interest rate contracts	—		(201	)	—		(201	)
Commodity contracts	—		(23	)	(155	)	(178	)
Other contracts	—		(2	)	—		(2	)
	—		(2,438	)	(155	)	(2,593	)
Total net financial asset/(liability)
Foreign exchange contracts	—		(2,718	)	—		(2,718	)
Interest rate contracts	—		(515	)	—		(515	)
Commodity contracts	17		24		(11	)	30
Other contracts	—		(7	)	—		(7	)
	17		(3,216	)	(11	)	(3,210	)

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December 31, 2017	Level 1		Level 2		Level 3		Total Gross Derivative Instruments
(millions of Canadian dollars)
Financial assets
Current derivative assets
Foreign exchange contracts	—		143		—		143
Interest rate contracts	—		8		—		8
Commodity contracts	1		30		114		145
	1		181		114		296
Long-term derivative assets
Foreign exchange contracts	—		145		—		145
Interest rate contracts	—		13		—		13
Commodity contracts	—		2		21		23
	—		160		21		181
Financial liabilities
Current derivative liabilities
Foreign exchange contracts	—		(359	)	—		(359	)
Interest rate contracts	—		(329	)	—		(329	)
Commodity contracts	(13	)	(87	)	(339	)	(439	)
Other contracts	—		(3	)	—		(3	)
	(13	)	(778	)	(339	)	(1,130	)
Long-term derivative liabilities
Foreign exchange contracts	—		(1,312	)	—		(1,312	)
Interest rate contracts	—		(40	)	—		(40	)
Commodity contracts	—		(3	)	(183	)	(186	)
Other contracts	—		(1	)	—		(1	)
	—		(1,356	)	(183	)	(1,539	)
Total net financial asset/(liability)
Foreign exchange contracts	—		(1,383	)	—		(1,383	)
Interest rate contracts	—		(348	)	—		(348	)
Commodity contracts	(12	)	(58	)	(387	)	(457	)
Other contracts	—		(4	)	—		(4	)
	(12	)	(1,793	)	(387	)	(2,192	)

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

December 31, 2018	Fair Value		Unobservable Input	Minimum Price/Volatility	Maximum Price/Volatility	Weighted Average Price/Volatility	Unit of Measurement
(fair value in millions of Canadian dollars)
Commodity contracts - financial1
Natural gas	(9	)	Forward gas price	2.54	6.37	3.58	$/mmbtu2
Crude	28		Forward crude price	27.50	123.20	59.32	$/barrel
NGL	—		Forward NGL price	—	—	—	$/gallon
Power	(91	)	Forward power price	16.21	96.72	48.33	$/MW/H
Commodity contracts - physical1
Natural gas	(119	)	Forward gas price	1.09	6.95	1.51	$/mmbtu2
Crude	186		Forward crude price	16.45	123.22	59.22	$/barrel
NGL	(6	)	Forward NGL price	0.13	1.40	0.59	$/gallon
	(11	)

1 Financial and physical forward commodity contracts are valued using a market approach valuation technique.

2 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 our 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

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values for our Level 3 derivatives. Changes in price volatility would change the value of the option contracts. Generally, a change in the estimate of forward commodity prices is unrelated to a change in the estimate of price volatility.

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

Year ended December 31,	2018		2017
(millions of Canadian dollars)
Level 3 net derivative asset/(liability) at beginning of period	(387	)	(295	)
Total gain/(loss)
Included in earnings1	206		(184	)
Included in OCI	2		4
Settlements	168		88
Level 3 net derivative liability at end of period	(11	)	(387	)

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

Our policy is to recognize transfers as at the last day of the reporting period. There were no transfers between levels as at December 31, 2018 or 2017.

FAIR VALUE OF OTHER FINANCIAL INSTRUMENTS

Our other long-term investments in other entities with no actively quoted prices are classified as Fair Value Measurement Alternative (FVMA) investments and are recorded at cost less impairment. The carrying value of FVMA and other long-term investments totaled $102 million and $99 million as at December 31, 2018 and 2017, respectively.

We have Restricted long-term investments held in trust totaling $323 million and $267 million as at December 31, 2018 and 2017, respectively, which are recognized at fair value.

We have a held to maturity preferred share investment carried at its amortized cost of $478 millionand $371 million as at December 31, 2018 and 2017, respectively. 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%. The fair value of this preferred share investment approximates its face value of $580 million as at December 31, 2018 and 2017.

As at December 31, 2018 and 2017, our long-term debt had a carrying value of $63.9 billion and $64.0 billion, respectively, before debt issuance costs and a fair value of $64.4 billion and $67.4 billion, respectively. We also have noncurrent notes receivable carried at book value recorded in Deferred amounts and other assets in the Consolidated Statements of Financial Position. As at December 31, 2018 and 2017, the noncurrent notes receivable had a carrying value of $97 million and $89 million, and a fair value of $97 million and $89 million, respectively.

The fair value of other financial assets and liabilities other than derivative instruments, other long-term investments, restricted long-term investments and long-term debt approximate their cost due to the short period to maturity.

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NET INVESTMENT HEDGES

We have designated a portion of our United States dollar denominated debt, as well as a portfolio of foreign exchange forward contracts, as a hedge of our net investment in United States dollar denominated investments and subsidiaries.

During the years ended December 31, 2018 and 2017, we recognized an unrealized foreign exchange loss of $479 million and a gain of $367 million, respectively, on the translation of United States dollar denominated debt and an unrealized gain on the change in fair value of our outstanding foreign exchange forward contracts of $30 million and $286 million, respectively, in OCI. During the years ended December 31, 2018 and 2017, we recognized a realized loss of $45 million and $198 million, respectively, in OCI associated with the settlement of foreign exchange forward contracts and also recognized a realized loss of $14 million and gain of $23 million, respectively, in OCI associated with the settlement of United States dollar denominated debt that had matured during the period. There was no ineffectiveness during the years ended December 31, 2018 and 2017.

25.   INCOME TAXES

INCOME TAX RATE RECONCILIATION

Year ended December 31,	2018		2017		2016
(millions of Canadian dollars)
Earnings before income taxes	3,570		569		2,451
Canadian federal statutory income tax rate	15	%	15	%	15	%
Expected federal taxes at statutory rate	536		85		368
Increase/(decrease) resulting from:
Provincial and state income taxes1	(24	)	133		34
Foreign and other statutory rate differentials	94		(601	)	(56	)
Impact of United States tax reform2	(2	)	(2,045	)	—
Effects of rate-regulated accounting	(163	)	(189	)	(116	)
Foreign allowable interest deductions	(134	)	(124	)	(107	)
Part VI.1 tax, net of federal Part I deduction	76		68		56
Impairment of goodwill3	192		15		—
Intercompany sale of investment4	—		—		6
United States BEAT tax	43		—		—
Non-taxable portion of gain/(loss) on sale of investment to unrelated party5	31		—		(61	)
Valuation allowance6	(172	)	(17	)	22
Intercorporate investments7	(149	)	77		—
Noncontrolling interests	(47	)	(80	)	(15	)
Other	(44	)	(19	)	11
Income tax (recovery)/expense	237		(2,697	)	142
Effective income tax rate	6.6	%	(474.0	)%	5.8	%

1 The change in provincial and state income taxes from 2017 to 2018 reflects the increase in earnings from the Canadian operations, the impact of the US tax reform on state income tax expense, and the impact of changes to the unitary state income tax rate in 2018.

2 The amount was due to the enactment of the TCJA by the United States on December 22, 2017, which included a reduction in the federal corporate income tax rate from 35% to 21% effective for taxation years beginning after December 31, 2017.

3 The amount relates to the federal component for the tax effect of impairment of goodwill.

4 In November 2016, 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 were recognized in earnings.

5 The amount represents the federal component of the non-taxable portion of the gain on the sales of the Canadian Natural Gas Gathering and Processing Businesses in 2018 and the South Prairie Region assets in 2016 to unrelated parties.

6 The increase from 2017 to 2018 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 2018, was now more likely than not to be realized.

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7 The amount relates to the federal component of changes in assertions regarding the manner of recovery of intercorporate investments such that deferred tax related to outside basis temporary differences was required to be recorded for Renewable Assets in 2018 and for EIPLP in 2017.

COMPONENTS OF PRETAX EARNINGS AND INCOME TAXES

Year ended December 31,	2018		2017		2016
(millions of Canadian dollars)
Earnings/(loss) before income taxes
Canada	118		2,200		2,034
United States	2,582		(2,431	)	(333	)
Other	870		800		750
	3,570		569		2,451
Current income taxes
Canada	311		129		74
United States	66		46		21
Other	8		5		4
	385		180		99
Deferred income taxes
Canada	(598	)	299		188
United States	439		(3,160	)	(151	)
Other	11		(16	)	6
	(148	)	(2,877	)	43
Income tax (recovery)/expense	237		(2,697	)	142

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,	2018		2017
(millions of Canadian dollars)
Deferred income tax liabilities
Property, plant and equipment	(7,018	)	(4,089	)
Investments	(4,441	)	(6,596	)
Regulatory assets	(756	)	(977	)
Other	(192	)	(50	)
Total deferred income tax liabilities	(12,407	)	(11,712	)
Deferred income tax assets
Financial instruments	1,103		697
Pension and OPEB plans	181		258
Loss carryforwards	1,820		1,781
Other	1,274		1,057
Total deferred income tax assets	4,378		3,793
Less valuation allowance	(51	)	(286	)
Total deferred income tax assets, net	4,327		3,507
Net deferred income tax liabilities	(8,080	)	(8,205	)
Presented as follows:
Total deferred income tax assets	1,374		1,090
Total deferred income tax liabilities	(9,454	)	(9,295	)
Net deferred income tax liabilities	(8,080	)	(8,205	)

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.

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As at December 31, 2018 and 2017, we recognized the benefit of unused tax loss carryforwards of $3.4 billion and $3.8 billion, respectively, in Canada which expire in 2025 and beyond.

As at December 31, 2018 and 2017, we recognized the benefit of unused tax loss carryforwards of $3.4 billion and $2.1 billion, respectively, in the United States which expire in 2023 and beyond.

As at December 31, 2018 and 2017, we recognized the benefit of unused capital loss carryforwards of nil and $143 million, respectively, in Canada.

As at December 31, 2018 and 2017, we recognized the benefit of unused capital loss carryforwards of nil and $20 million, respectively, in the United States.

We have not provided for deferred income taxes on the difference between the carrying value of substantially all of our 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 were $5.8 billion and $2.1 billion for the period December 31, 2018 and 2017, respectively. If such earnings are remitted, in the form of dividends or otherwise, we 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.

Enbridge and one or more of our subsidiaries are subject to taxation in Canada, the United States and other foreign jurisdictions. The material jurisdictions in which we are subject to potential examinations include the United States (Federal) and Canada (Federal, Alberta and Ontario). We are open to examination by Canadian tax authorities for the 2010 to 2018 tax years and by United States tax authorities for the 2013 to 2018 tax years. We are currently under examination for income tax matters in Canada for the 2013 to 2017 tax years and in the United States for the 2013 to 2014 tax years. We are not currently under examination for income tax matters in any other material jurisdiction where we are subject to income tax.

United States Tax Reform

On December 22, 2017, the United States enacted the TCJA. As disclosed in our Annual Report on Form 10-K, as filed with the Securities and Exchange Commission on February 16, 2018, we made certain estimates for the measurement and accounting of certain effects of the TCJA for the year ended and as at December 31, 2017. As we continue to gather, prepare and analyze the necessary information in reasonable detail to complete the accounting for the impact of TCJA, we continue to refine our estimates. During the first quarter of 2018 we refined our calculation of the regulatory liability associated with the TCJA which resulted in a $30 million reduction to the overall regulatory liability. An additional reduction to the regulated liability in the amount of $223 million was recorded in the fourth quarter in connection with rate cases filed that eliminated a portion of regulated liability formerly included in SEP's rate base.

We recorded $43 million in tax expense for the year ended December 31, 2018 in connection with the Base Erosion and Anti-abuse Tax (BEAT); and we recorded no provision for the Global Intangible Low Taxed Income Tax (GILTI).

Most changes to the TCJA are effective for taxation years beginning after December 31, 2017. While the changes are broad and complex, the most significant change was the reduction in the corporate federal income tax rate from 35% to 21%. In 2017 we were also impacted by a one-time deemed repatriation or “toll” tax on undistributed earnings and profits of United States controlled foreign affiliates, including Canadian subsidiaries.

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In 2017 we made reasonable estimates for the measurement and accounting of certain effects of the TCJA in accordance with SEC Staff Accounting Bulletin No.118 (SAB 118). Accordingly, we recorded a provisional $34 million increase to our 2017 current income tax provision related to the toll tax, payable over eight years. We recorded a provisional $2.0 billion decrease to our 2017 deferred income tax provision related to the reduction in the corporate federal income tax rate. The accounting for these provisional items decreased our accumulated deferred income tax liability by $3.1 billion and increased our regulatory liability by $1.1 billion in 2017. We have also adjusted our valuation allowance for certain deferred tax assets existing at December 31, 2016 for the reduction in the corporate federal income tax rate by $0.2 billion. We have recognized these provisional tax impacts and included these amounts in our consolidated financial statements for the year ended December 31, 2017.

UNRECOGNIZED TAX BENEFITS

Year ended December 31,	2018		2017
(millions of Canadian dollars)
Unrecognized tax benefits at beginning of year	150		84
Gross increases for tax positions of current year	2		15
Gross increases for tax positions of prior year	—		65
Gross decreases for tax positions of prior year	(12	)	—
Change in translation of foreign currency	3		(2	)
Lapses of statute of limitations	(3	)	(8	)
Settlements	(1	)	(4	)
Unrecognized tax benefits at end of year	139		150

The unrecognized tax benefits as at December 31, 2018, if recognized, would impact our effective income tax rate. We do not anticipate further adjustments to the unrecognized tax benefits during the next 12 months that would have a material impact on our consolidated financial statements.

We recognize accrued interest and penalties related to unrecognized tax benefits as a component of income taxes. Income taxes for the years ended December 31, 2018 and 2017 were $5 million expense and $3 million recovery, respectively, of interest and penalties. As at December 31, 2018 and 2017, interest and penalties of $12 million and $8 million, respectively, have been accrued.

26.  PENSION AND OTHER POSTRETIREMENT BENEFITS

PENSION PLANS

We maintain registered and non-registered, contributory and non-contributory pension plans which provide defined benefit and/or defined contribution pension benefits covering substantially all employees. The Canadian Plans provide Company funded defined benefit and/or defined contribution pension benefits to our Canadian employees. The United States Plans provide Company funded defined benefit pension benefits to our United States employees. We also maintain supplemental pension plans that provide pension benefits in excess of the basic plans for certain employees.

Defined Benefit Plans

Benefits payable from the defined benefit plans are based on each plan participant’s years of service and final average remuneration. These benefits are partially inflation-indexed after a plan participant’s retirement. Our contributions are made in accordance with independent actuarial valuations and are invested primarily in publicly-traded equity and fixed income securities.

Defined Contribution Plans

Contributions are generally based on each plan participant’s age, years of service and current eligible remuneration. For defined contribution plans, benefit costs equal amounts required to be contributed by us.

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Benefit Obligation, Plan Assets and Funded Status

The following table details the changes in the projected benefit obligation, the fair value of plan assets and the recorded asset or liability for our defined benefit pension plans:

	Canada				United States
December 31,	2018		2017		2018		2017
(millions of Canadian dollars)
Change in projected benefit obligation
Projected benefit obligation at beginning of year	4,033		2,270		1,279		508
Service cost	149		156		45		48
Interest cost	130		116		38		35
Participant contributions	25		6		—		—
Actuarial (gain)/loss	(146	)	145		(103	)	57
Benefits paid	(184	)	(165	)	(60	)	(42	)
Plan settlements	—		—		(65	)	(59	)
Transfer out	(10	)	—		—		—
Acquired in Merger Transaction	—		1,505		—		811
Foreign currency exchange rate changes	—		—		105		(63	)
Other	—		—		(25	)	(16	)
Projected benefit obligation at end of year1	3,997		4,033		1,214		1,279
Change in plan assets
Fair value of plan assets at beginning of year	3,619		2,019		1,097		361
Actual return/(loss) on plan assets	(42	)	308		(48	)	113
Employer contributions	113		161		40		57
Participant contributions	25		6		—		—
Benefits paid	(184	)	(165	)	(60	)	(42	)
Plan settlements	—		—		(65	)	(59	)
Transfer out	(8	)	—		—		—
Acquired in Merger Transaction	—		1,290				731
Foreign currency exchange rate changes	—		—		91		(51	)
Other	—		—		(10	)	(13	)
Fair value of plan assets at end of year2	3,523		3,619		1,045		1,097
Underfunded status at end of year	(474	)	(414	)	(169	)	(182	)
Presented as follows:
Deferred amounts and other assets	29		38		—		—
Accounts payable and other	(9	)	(60	)	(4	)	(3	)
Other long-term liabilities	(494	)	(392	)	(165	)	(179	)
	(474	)	(414	)	(169	)	(182	)

1 The accumulated benefit obligation for our Canadian pension plans was $3.7 billion as at December 31, 2018 and 2017. The accumulated benefit obligation for our United States pension plans was $1.2 billion as at December 31, 2018 and 2017.

2 Assets in the amount of $7 million (2017 - $9 million) and $39 million (2017 - $40 million), related to our Canadian and United States non-registered supplemental pension plan obligations, are held in grantor trusts that, in accordance with federal tax regulations, are not restricted from creditors. These assets are committed for the future settlement of benefit obligations included in the underfunded status as at the end of the year, however they are excluded from plan assets for accounting purposes.

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Certain of our pension plans have accumulated benefit obligations in excess of the fair value of plan assets. For these plans, the projected benefit obligations, accumulated benefit obligations and the fair value of plan assets were as follows:

	Canada		United States
December 31,	2018	2017	2018	2017
(millions of Canadian dollars)
Projected benefit obligations	1,422	1,444	1,214	1,280
Accumulated benefit obligations	1,299	1,306	1,179	1,217
Fair value of plan assets	1,064	1,131	1,045	1,098

Amount Recognized in Accumulated Other Comprehensive Income

The amounts of pre-tax AOCI relating to our pension plans are as follows:

	Canada		United States
December 31,	2018	2017	2018		2017
(millions of Canadian dollars)
Net actuarial loss	435	334	133		112
Prior service credit	—	—	(3	)	—
Total amount recognized in AOCI1	435	334	130		112

1 Includes amounts related to cumulative translation adjustment.

Net Benefit Costs Recognized

The components of net benefit cost and other amounts recognized in pre-tax OCI related to our pension plans are as follows:

		Canada							United States
Year ended December 31,		2018		2017		2016			2018		2017		2016
(millions of Canadian dollars)
Service cost		149		156		129			45		48		26
Interest cost		130		116		73			38		35		16
Expected return on plan assets		(245	)	(201	)	(127	)		(88	)	(57	)	(21	)
Amortization/settlement of net actuarial loss		25		29		32			7		10		3
Amortization/curtailment of prior service cost		—		—		—			3		—		—
Net defined benefit costs		59		100		107		—	5		36		24
Defined contribution benefit costs		11		11		3			19		15		—
Net benefit cost recognized in Earnings		70		111		110			24		51		24
Amount recognized in OCI:
	Amortization/settlement of net actuarial loss	(11	)	(14	)	(14	)		(7	)	(9	)	(6	)
	Amortization/curtailment of prior service cost	—		—		—			(3	)	—		—
	Net actuarial loss arising during the year	112		38		28			28		—		16
Total amount recognized in OCI		101		24		14			18		(9	)	10
Total amount recognized in Comprehensive income		171		135		124			42		42		34

We estimate that approximately $32 million related to the Canadian pension plans and $0 million related to the United States pension plans as at December 31, 2018 will be reclassified from AOCI into earnings in the next 12 months.

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Actuarial Assumptions

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

	Canada						United States
	2018		2017		2016		2018		2017		2016
Projected benefit obligations
Discount rate	3.8	%	3.6	%	4.0	%	3.9	%	3.5	%	4.0	%
Rate of salary increase	3.2	%	3.2	%	3.7	%	2.8	%	3.1	%	3.3	%
Net benefit cost
Discount rate	3.6	%	4.0	%	4.2	%	3.4	%	4.0	%	4.1	%
Rate of return on plan assets	6.8	%	6.5	%	6.5	%	7.4	%	7.2	%	7.2	%
Rate of salary increase	3.2	%	3.7	%	3.6	%	2.9	%	3.3	%	3.2	%

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.

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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 on a non-contributory basis.

The following table details the changes in the accumulated postretirement benefit obligation, the fair value of plan assets and the recorded asset or liability for our defined benefit OPEB plans:

	Canada				United States
December 31,	2018		2017		2018		2017
(millions of Canadian dollars)
Change in accumulated postretirement benefit obligation
Accumulated postretirement benefit obligation at beginning of year	321		179		337		133
Service cost	8		7		3		5
Interest cost	10		10		10		10
Participant contributions	—		—		6		4
Actuarial gain	(45	)	(8	)	(25	)	(34	)
Benefits paid	(11	)	(10	)	(29	)	(19	)
Plan amendments	—		(3	)	(8	)	1
Acquired in Merger Transaction	—		146		—		254
Foreign currency exchange rate changes	—		—		27		(17	)
Other	(1	)	—		(16	)	—
Accumulated postretirement benefit obligation at end of year	282		321		305		337
Change in plan assets
Fair value of plan assets at beginning of year	—		—		213		115
Actual return/(loss) on plan assets	—		—		(13	)	21
Employer contributions	11		10		8		1
Participant contributions	—		—		6		4
Benefits paid	(11	)	(10	)	(29	)	(19	)
Acquired in Merger Transaction	—		—		—		102
Foreign currency exchange rate changes	—		—		16		(11	)
Other	—		—		(20	)	—
Fair value of plan assets at end of year	—		—		181		213
Underfunded status at end of year	(282	)	(321	)	(124	)	(124	)
Presented as follows:
Deferred amounts and other assets	—		—		2		7
Accounts payable and other	(12	)	(12	)	(7	)	(7	)
Other long-term liabilities	(270	)	(309	)	(119	)	(124	)
	(282	)	(321	)	(124	)	(124	)

Amount Recognized in Accumulated Other Comprehensive Income

The amounts of pre-tax AOCI relating to our OPEB plans are as follows:

	Canada				United States
December 31,	2018		2017		2018		2017
(millions of Canadian dollars)
Net actuarial (gain)/loss	(29	)	17		(15	)	(15	)
Prior service credit	(2	)	(2	)	(15	)	(11	)
Total amount recognized in AOCI1	(31	)	15		(30	)	(26	)

1 Includes amounts related to cumulative translation adjustment.

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Net Benefit Costs Recognized

The components of net benefit cost and other amounts recognized in pre-tax OCI related to our OPEB plans are as follows:

	Canada						United States
Year ended December 31,	2018		2017		2016		2018		2017		2016
(millions of Canadian dollars)
Service cost	8		7		4		3		5		4
Interest cost	10		10		6		10		10		5
Expected return on plan assets	—		—		—		(12	)	(10	)	(6	)
Amortization/settlement of net actuarial gain	—		—		—		(1	)	—		—
Amortization/curtailment of prior service (credit)/cost	—		1		—		(4	)	—		—
Net benefit cost recognized in Earnings	18		18		10		(4	)	5		3
Amount recognized in OCI:
Amortization/settlement of net actuarial gain/(loss)	—		(1	)	(1	)	1		1		(1	)
Amortization/curtailment of prior service credit	—		—		—		4		—		—
Net actuarial (gain)/loss arising during the year	(46	)	(8	)	2		(1	)	(42	)	12
Prior service (credit)/cost	—		(3	)	—		(8	)	1		(12	)
Total amount recognized in OCI	(46	)	(12	)	1		(4	)	(40	)	(1	)
Total amount recognized in Comprehensive income	(28	)	6		11		(8	)	(35	)	2

We estimate that approximately nil related to the Canadian OPEB plans and $2 million related to the United States OPEB plans as at December 31, 2018 will be reclassified from AOCI into earnings in the next 12 months.

Actuarial Assumptions

The weighted average assumptions made in the measurement of the accumulated postretirement benefit obligations and net benefit cost of our OPEB plans are as follows:

	Canada						United States
	2018		2017		2016		2018		2017		2016
Accumulated postretirement benefit obligations
Discount rate	3.8	%	3.6	%	4.0	%	4.0	%	3.5	%	3.6	%
Net OPEB cost
Discount rate	3.6	%	4.0	%	4.2	%	3.3	%	4.0	%	3.8	%
Rate of return on plan assets	N/A		N/A		N/A		5.7	%	6.0	%	6.0	%

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.

Assumed Health Care Cost Trend Rates

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

	Canada				United States
	2018		2017		2018		2017
Health care cost trend rate assumed for next year	5.6	%	5.5	%	7.4	%	7.4	%
Rate to which the cost trend is assumed to decline (the ultimate trend rate)	4.4	%	4.4	%	4.5	%	4.5	%
Year that the rate reaches the ultimate trend rate	2034		2034		2037		2037

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A 1% change in the assumed health care cost trend rate would have the following effects for the year ended and as at December 31, 2018:

	Canada			United States
	1% Increase	1% Decrease		1% Increase	1% Decrease
(millions of Canadian dollars)
Effect on total service and interest costs	1	(1	)	1	(1	)
Effect on accumulated postretirement benefit obligation	20	(16	)	18	(17	)

PLAN ASSETS

We manage the investment risk of our 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) our operating environment and financial situation and our 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 asset allocation targets and major categories of plan assets are as follows:

	Canada					United States
	Target	December 31,				Target	December 31,
Asset Category	Allocation	2018		2017		Allocation	2018		2017
Equity securities	40.0 - 70.0%	45.8	%	52.0	%	52.5 - 70.0%	51.7	%	47.1	%
Fixed income securities	27.5 - 60.0%	33.4	%	34.2	%	27.5 - 30.0%	32.9	%	47.7	%
Other	0.0 - 20.0%	20.7	%	13.8	%	0.0 - 20.0%	15.4	%	5.2	%

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The following tables summarize the fair value of plan assets for our pension and OPEB plans recorded at each fair value hierarchy level.

Pension

	Canada							United States
	Level 11		Level 22		Level 33	Total		Level 11	Level 22		Level 33	Total
(millions of Canadian dollars)
December 31, 2018
Cash and cash equivalents	246		—		—	246		56	—		—	56
Equity securities
Canada	623		—		—	623		1	—		—	1
United States	(1	)	—		—	(1	)	50	—		—	50
Global	993		—		—	993		489	—		—	489
Fixed income securities
Government	661		—		—	661		265	—		—	265
Corporate	457		—		60	517		54	—		25	79
Infrastructure and real estate4	—		—		502	502		—	—		105	105
Forward currency contracts	—		(18	)	—	(18	)	—	—		—	—
Total pension plan assets at fair value	2,979		(18	)	562	3,523		915	—		130	1,045
December 31, 2017
Cash and cash equivalents	169		—		—	169		2	—		—	2
Equity securities
Canada	842		425		—	1,267		—	—		—	—
United States	427		—		—	427		343	—		—	343
Global	189		—		—	189		122	52		—	174
Fixed income securities
Government	933		—		—	933		—	—		—	—
Corporate	301		3		—	304		522	1		—	523
Infrastructure and real estate4	—		—		340	340		—	—		56	56
Forward currency contracts	—		(10	)	—	(10	)	—	(1	)	—	(1	)
Total pension plan assets at fair value	2,861		418		340	3,619		989	52		56	1,097

OPEB

	Canada				United States
	Level 11	Level 22	Level 33	Total	Level 11	Level 22	Level 33	Total
(millions of Canadian dollars)
December 31, 2018
Cash and cash equivalents	—	—	—	—	7	—	—	7
Equity securities
United States	—	—	—	—	63	—	—	63
Global	—	—	—	—	35	—	—	35
Fixed income securities
Government	—	—	—	—	68	—	—	68
Corporate	—	—	—	—	3	—	2	5
Infrastructure and real estate	—	—	—	—	—	—	3	3
Total OPEB plan assets at fair value	—	—	—	—	176	—	5	181
December 31, 2017
Cash and cash equivalents	—	—	—	—	1	—	—	1
Equity securities
United States	—	—	—	—	80	—	—	80
Global	—	—	—	—	36	—	—	36
Fixed income securities
Government	—	—	—	—	96	—	—	96
Total OPEB plan assets at fair value	—	—	—	—	213	—	—	213

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.

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

Pension

	Canada		United States
December 31,	2018	2017	2018	2017
(millions of Canadian dollars)
Balance at beginning of year	340	281	56	40
Unrealized and realized gains	77	26	9	5
Purchases and settlements, net	145	33	65	11
Balance at end of year	562	340	130	56

OPEB

	Canada		United States
December 31,	2018	2017	2018	2017
(millions of Canadian dollars)
Balance at beginning of year	—	—	—	—
Unrealized and realized gains	—	—	—	—
Purchases and settlements, net	—	—	5	—
Balance at end of year	—	—	5	—

EXPECTED BENEFIT PAYMENTS AND EMPLOYER CONTRIBUTIONS

Year ended December 31,	2019	2020	2021	2022	2023	2023-2027
(millions of Canadian dollars)
Pension
Canada	174	180	187	194	201	1,104
United States	124	96	97	98	95	438
OPEB
Canada	13	12	13	13	13	39
United States	26	26	25	24	23	98

In 2019, we expect to contribute approximately $114 million and $47 million to the Canadian and United States pension plans, respectively, and $13 million and $7 million to the Canadian and United States OPEB plans, respectively.

RETIREMENT SAVINGS PLANS

In addition to the retirement plans discussed above, we also have defined contribution employee savings plans available to both Canadian and United States employees. Employees may participate in a matching contribution where we match a certain percentage of before-tax employee contributions of up to 5% of eligible pay per pay period for Canadian employees and up to 6% of eligible pay per pay period for United States employees. For the years ended December 31, 2018, 2017 and 2016, we expensed pre-tax employer matching contributions of $13 million, $14 million and nil for Canadian employees and $27 million, $31 million and $13 million for United States employees, respectively.

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27. CHANGES IN OPERATING ASSETS AND LIABILITIES

Year ended December 31,	2018		2017		2016
(millions of Canadian dollars)
Accounts receivable and other	857		(783	)	(437	)
Accounts receivable from affiliates	54		24		(7	)
Inventory	164		(289	)	(371	)
Deferred amounts and other assets	226		(138	)	(183	)
Accounts payable and other	(151	)	277		386
Accounts payable to affiliates	(122	)	(62	)	71
Interest payable	25		124		20
Other long-term liabilities	(138	)	509		153
	915		(338	)	(368	)

28. 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.

SERVICE AGREEMENTS

Vector Pipeline L.P. (Vector), a joint venture, contracts our services to operate the pipeline. Amounts for these services, which are charged at cost in accordance with service agreements, were $7 million, $14 million and $7 million for the years ended December 31, 2018, 2017 and 2016, respectively.

TRANSPORTATION AGREEMENTS

Certain wholly-owned subsidiaries within the Liquids Pipelines, Gas Transmission and Midstream, Gas Distribution 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 us for transportation services for the years ended December 31, 2018, 2017 and 2016 were $572 million, $721 million and $644 million, respectively.

AFFILIATE REVENUES AND PURCHASES

Certain wholly-owned subsidiaries within the Gas Distribution and Energy Services segments made natural gas and NGL purchases of $322 million, $142 millionand$98 million from several joint venture affiliates during the years ended December 31, 2018, 2017 and 2016, respectively.

Natural gas sales of $122 million, $60 millionand$49 million were made by certain wholly-owned subsidiaries within the Energy Services segment to several joint venture affiliates during the years ended December 31, 2018, 2017 and 2016, respectively.

DCP Midstream processes certain of our pipeline customers' gas to meet gas quality specifications in order to be transported on our system. DCP Midstream processes the gas and sells the NGLs that are extracted from the gas. A portion of the proceeds from those sales are retained by DCP Midstream and the balance is remitted to us. We received proceeds of $52 million (US$40 million) and $47 million (US$36 million) during the years ended December 31, 2018, and 2017, respectively, from DCP Midstream related to those sales.

In addition to the above, we recorded other revenues from DCP Midstream and its affiliates related to the transportation and storage of natural gas of $14 million (US$11 million) and $4 million (US$3 million) during the years ended December 31, 2018, and 2017, respectively.

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In the ordinary course of business, we are reimbursed by joint venture partners for operating and maintenance expenses for certain projects. We received reimbursements from Spectra Energy joint ventures of $28 million (US$22 million) and $10 million (US$8 million) during the years ended December 31, 2018, and 2017, respectively.

RECOVERIES OF COSTS

We provide certain administrative and other services to certain operating entities acquired through the Merger Transaction, and recorded recoveries of costs from these affiliates of $104 million (US$80 million) and $88 million (US$68 million) for the years ended December 31, 2018, and 2017, respectively. Cost recoveries are recorded as a reduction to Operating and administrative expense in the Consolidated Statements of Earnings.

LONG-TERM NOTES RECEIVABLE FROM AFFILIATES

As at December 31, 2018, amounts receivable from affiliates include a series of loans totaling$769 million($275 million as at December 31, 2017), whichrequire quarterly interest payments at annual interest rates ranging from 4% to 8%. These amounts are included in deferred amounts and other assets in the Consolidated Statements of Financial position.

29.  COMMITMENTS AND CONTINGENCIES

COMMITMENTS

At December 31, 2018, we have commitments as detailed below.

	Total	Less than 1 year	2 years	3 years	4 years	5 years	Thereafter
(millions of Canadian dollars)
Annual debt maturities1	62,967	3,255	9,262	2,389	4,571	5,963	37,527
Interest obligations2	30,236	2,459	2,279	2,103	2,022	1,883	19,490
Purchase of services, pipe and other materials, including transportation3,4	10,493	3,833	1,473	1,000	754	406	3,027
Operating leases	1,079	132	134	100	98	93	522
Capital leases	23	7	—	—	2	2	12
Maintenance agreements	477	52	51	51	50	22	251
Land lease commitments	651	21	21	21	21	22	545
Total	105,926	9,759	13,220	5,664	7,518	8,391	61,374

1 Includes debentures, term notes, commercial paper and credit facility draws based on the facility's maturity date and excludes short-term borrowings, debt discount, debt issue costs and capital lease obligations. We have the ability under certain debt facilities to call and repay the obligations prior to scheduled maturities. Therefore, the actual timing of future cash repayments could be materially different than presented above.

2 Includes debentures and term notes bearing interest at fixed, floating and fixed-to-floating rates.

3 Includes capital and operating commitments.

4 Consists primarily of gas transportation and storage contracts, firm capacity payments and gas purchase commitments, transportation, service and product purchase obligations, and power commitments.

Total rental expense for operating leases included in Operating and administrative expense were $91 million, $108 million and $79 million for the years ended December 31, 2018, 2017 and 2016, respectively.

ENVIRONMENTAL

We are subject to various federal, state and local laws relating to the protection of the environment. These laws and regulations can change from time to time, imposing new obligations on us.

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Environmental risk is inherent to liquid hydrocarbon and natural gas pipeline operations, and Enbridge and our affiliates are, at times, subject to environmental remediation at various contaminated sites. We manage this environmental risk through appropriate environmental policies and practices to minimize any impact our operations may have on the environment. To the extent that we are unable to recover payment for environmental liabilities from insurance or other potentially responsible parties, we will be responsible for payment of liabilities arising from environmental incidents associated with the operating activities of our liquids and natural gas businesses.

AUX SABLE

Notice of Violation

In September 2014, Aux Sable US received a Notice and Finding of Violation (NFOV) from the United States Environmental Protection Agency (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, which is effective as of December 31, 2018, did not 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 our consolidated financial position or results of operations.

TAX MATTERS

We and our subsidiaries maintain tax liabilities related to uncertain tax positions. While fully supportable in our view, these tax positions, if challenged by tax authorities, may not be fully sustained on review.

OTHER LITIGATION

We 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 our consolidated financial position or results of operations.

30.  GUARANTEES

In the normal course of conducting business, we enter 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, and litigation and contingent liabilities. We may indemnify third parties for certain liabilities relating to environmental matters arising from operations prior to the purchase or transfer of certain assets and interests. Similarly, we may indemnify the purchaser of assets for certain tax liabilities incurred while we owned the assets, a misrepresentation related to taxes that result in a loss to the purchaser or other certain tax liabilities related to those assets.

We may also be a party to agreements with subsidiaries, jointly owned entities, unconsolidated entities such as equity method investees, or entities with other ownership arrangements that require us to provide financial and performance guarantees. Financial guarantees include stand-by letters of credit, debt guarantees, surety bonds and indemnifications. To varying degrees, these guarantees involve elements of

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performance and credit risk, which are not included on our Consolidated Statements of Financial Position. Performance guarantees require us to make payments to a third party if the guaranteed affiliate entity does not perform on its contractual obligations, such as debt agreements, purchase or sale agreements, and construction contracts and leases. We typically enter into these arrangements to facilitate commercial transactions with third parties.

The likelihood of having to perform under these guarantees and indemnifications is largely dependent upon future operations of various subsidiaries, investees and other third parties, or the occurrence of certain future events. We cannot reasonably estimate the total maximum potential amounts that could become payable to third parties and affiliates under such agreements described above; however, historically, we have not made any significant payments under guarantee or indemnification provisions. While these agreements may specify a maximum potential exposure, or a specified duration to the guarantee or indemnification obligation, there are circumstances where the amount and duration are unlimited. The guarantees and indemnifications have not had, and are not reasonably likely to have, a material effect on our financial condition, changes in financial condition, earnings, liquidity, capital expenditures or capital resources.

31. CONDENSED CONSOLIDATING FINANCIAL INFORMATION

On January 22, 2019, Enbridge entered into supplemental indentures with its wholly-owned subsidiaries, SEP and EEP (the Partnerships), pursuant to which Enbridge fully and unconditionally guaranteed, on a senior unsecured basis, the payment obligations of the Partnerships with respect to the outstanding series of notes issued under the respective indentures of the Partnerships. Concurrently, the Partnerships entered into a subsidiary guarantee agreement pursuant to which they guaranteed, on a senior unsecured basis, the outstanding series of senior notes of Enbridge. As a result of the guarantees, holders of any of the outstanding guaranteed notes of the Partnerships are in the same position with respect to the net assets, income and cash flows of Enbridge as holders of Enbridge’s outstanding guaranteed notes and vice versa. Other than the Partnerships, Enbridge subsidiaries (including the subsidiaries of the Partnerships, collectively, the Subsidiary Non-Guarantors), are not parties to the subsidiary guarantee agreement and have not otherwise guaranteed any of Enbridge’s outstanding series of senior notes.

Prior to entering into these guarantees, Enbridge received the requisite consents from the holders of the Partnerships’ outstanding senior notes such that once such guarantees were put in place, in lieu of the respective reporting obligations of Partnerships, Enbridge would be subject to reporting obligations similar to those in the indenture governing Enbridge's United States dollar denominated senior notes. The series of notes for which guarantees were entered into are described in the tables below:

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Consenting SEP notes and EEP notes under Guarantee

SEP Notes1	EEP Notes2
Floating Rate Senior Notes due 2020	9.875% Notes due 2019
4.600% Senior Notes due 2021	5.200% Notes due 2020
4.750% Senior Notes due 2024	4.375% Notes due 2020
3.500% Senior Notes due 2025	4.200% Notes due 2021
3.375% Senior Notes due 2026	5.875% Notes due 2025
5.950% Senior Notes due 2043	5.950% Notes due 2033
4.500% Senior Notes due 2045	6.300% Notes due 2034
	7.500% Notes due 2038
	5.500% Notes due 2040
	7.375% Notes due 2045

1 As at the effective date of the guarantees, the aggregate outstanding principal amount of SEP notes was approximately US$3.9 billion.

2 As at the effective date of the guarantees, the aggregate outstanding principal amount of EEP notes was approximately US$4.5 billion.

Enbridge Notes under Guarantees

USD Denominated1	CAD Denominated2
Senior Floating Rate Notes due 2020	4.100% Senior Notes due 2019
Senior Floating Rate Notes due 2020	Senior Floating Rate Notes due 2019
2.900% Senior Notes due 2022	4.770% Senior Notes due 2019
4.000% Senior Notes due 2023	4.530% Senior Notes due 2020
3.500% Senior Notes due 2024	4.850% Senior Notes due 2020
4.250% Senior Notes due 2026	4.260% Senior Notes due 2021
3.700% Senior Notes due 2027	3.160% Senior Notes due 2021
4.500% Senior Notes due 2044	4.850% Senior Notes due 2022
5.500% Senior Notes due 2046	3.190% Senior Notes due 2022
	3.940% Senior Notes due 2023
	3.940% Senior Notes due 2023
	3.950% Senior Notes due 2024
	3.200% Senior Notes due 2027
	6.100% Senior Notes due 2028
	7.220% Senior Notes due 2030
	7.200% Senior Notes due 2032
	5.570% Senior Notes due 2035
	5.750% Senior Notes due 2039
	5.120% Senior Notes due 2040
	4.240% Senior Notes due 2042
	4.570% Senior Notes due 2044
	4.870% Senior Notes due 2044
	4.560% Senior Notes due 2064

1 As at the effective date of the guarantees, the aggregate outstanding principal amount of the Enbridge United States dollar

denominated notes was approximately US$5.9 billion.

2 As at the effective date of the guarantees, the aggregate outstanding principal amount of the Enbridge Canadian dollar denominated notes was approximately $8.1 billion.

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In accordance with Rule 3-10 of the SEC's Regulation S-X, which provides an exemption from the reporting requirements of the Securities Exchange Act of 1934 for subsidiary issuers of guaranteed securities and subsidiary guarantors, in lieu of filing separate financial statements for each of the Partnerships, we have included the accompanying condensed consolidating financial information with separate columns representing the following:

1. Enbridge Inc., the Parent Issuer and Guarantor;

2. SEP, a Subsidiary Issuer and Guarantor;

3. EEP, a Subsidiary Issuer and Guarantor;

4. Subsidiary Non-Guarantors, as defined herein;

5. Consolidating and elimination entries required to consolidate the Parent Issuer and Guarantor and its subsidiaries, including the Subsidiary Issuers and Guarantors, and

6. Enbridge Inc. and subsidiaries on a consolidated basis.

For the purposes of the condensed consolidating financial information only, investments in subsidiaries are accounted for under the equity method. In addition, the Condensed Consolidating Statements of Cash Flows present the intercompany loan and distribution activity, as well as cash collection and payments made on behalf of our subsidiaries, as cash activities. These intercompany investments and related activities eliminate on consolidation and are presented separately only for the purpose of the accompanying Condensed Consolidating Statements. As the Spectra Merger did not occur until February 27, 2017, SEP-related information is only included in the accompanying Condensed Consolidating Statements subsequent to the date of the Spectra Merger.

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Condensed Consolidating Statements of Earnings and Comprehensive Income for the year ended December 31, 2018

	Parent Issuer and Guarantor		Subsidiary Issuer and Guarantor - SEP		Subsidiary Issuer and Guarantor - EEP		Subsidiary Non-Guarantors		Consolidating and elimination adjustments		Consolidated - Enbridge
(millions of Canadian dollars)
Operating revenues
Commodity sales	—		—		—		27,660		—		27,660
Gas distribution sales	—		—		—		4,360		—		4,360
Transportation and other services	—		—		—		14,358		—		14,358
Total operating revenues	—		—		—		46,378		—		46,378
Operating Expenses
Commodity costs	—		—		—		26,818		—		26,818
Gas distribution costs	—		—		—		2,583		—		2,583
Operating and administrative	180		14		54		6,622		(78	)	6,792
Depreciation and amortization	59		—		—		3,187		—		3,246
Impairment of long-lived assets	—		—		—		1,104		—		1,104
Impairment of goodwill	—		—		—		1,019		—		1,019
Total operating expenses	239		14		54		41,333		(78	)	41,562
Operating income/(loss)	(239	)	(14	)	(54	)	5,045		78		4,816
Income from equity investments	302		142		—		1,360		(295	)	1,509
Equity earnings/(loss) from consolidated subsidiaries	3,119		(1,634	)	921		(1,581	)	(825	)	—
Other
Net foreign currency gain/(loss)	(829	)	8		—		80		219		(522	)
Gain/(loss) on dispositions	360		—		—		(406	)	—		(46	)
Other, including other income/(expense) from affiliates	945		72		153		254		(908	)	516
Interest expense	(1,080	)	(302	)	(557	)	(1,689	)	925		(2,703	)
Earnings/(loss) before income taxes	2,578		(1,728	)	463		3,063		(806	)	3,570
Income tax recovery/(expense)	304		(319	)	3		(4,373	)	4,148		(237	)
Earnings/(loss)	2,882		(2,047	)	466		(1,310	)	3,342		3,333
Earnings attributable to noncontrolling interests and redeemable noncontrolling interests	—		—		—		—		(451	)	(451	)
Earnings/(loss) attributable to controlling interests	2,882		(2,047	)	466		(1,310	)	2,891		2,882
Preference share dividends	(367	)	—		—		—		—		(367	)
Earnings/(loss) attributable to common shareholders	2,515		(2,047	)	466		(1,310	)	2,891		2,515
Earnings/(loss)	2,882		(2,047	)	466		(1,310	)	3,342		3,333
Total other comprehensive income/(loss)	3,788		(9	)	28		556		(225	)	4,138
Comprehensive income/(loss)	6,670		(2,056	)	494		(754	)	3,117		7,471
Comprehensive income attributable to noncontrolling interests	—		—		—		—		(801	)	(801	)
Comprehensive income/(loss) attributable to controlling interests	6,670		(2,056	)	494		(754	)	2,316		6,670

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Condensed Consolidating Statements of Earnings and Comprehensive Income for the year ended December 31, 2017

	Parent Issuer and Guarantor		Subsidiary Issuer and Guarantor - SEP		Subsidiary Issuer and Guarantor - EEP		Subsidiary Non-Guarantors		Consolidating and elimination adjustments		Consolidated - Enbridge
(millions of Canadian dollars)
Operating revenues
Commodity sales	—		—		—		26,286		—		26,286
Gas distribution sales	—		—		—		4,215		—		4,215
Transportation and other services	—		—		—		13,877		—		13,877
Total operating revenues	—		—		—		44,378		—		44,378
Operating expenses
Commodity costs	—		—		—		26,065		—		26,065
Gas distribution costs	—		—		—		2,572		—		2,572
Operating and administrative	169		146		16		6,111		—		6,442
Depreciation and amortization	56		—		—		3,107		—		3,163
Impairment of long lived assets	—		—		—		4,463		—		4,463
Impairment of goodwill	—		—		—		102		—		102
Total operating expenses	225		146		16		42,420		—		42,807
Operating income/(loss)	(225	)	(146	)	(16	)	1,958		—		1,571
Income from equity investments	471		118		—		981		(468	)	1,102
Equity earnings from consolidated subsidiaries	2,130		752		926		881		(4,689	)	—
Other
Net foreign currency gain/(loss)	500		—		—		(22	)	(241	)	237
Gain/(loss) on dispositions	(11	)	—		—		27		—		16
Other, including other income/(expense) from affiliates	871		11		139		74		(896	)	199
Interest expense	(816	)	(221	)	(691	)	(1,753	)	925		(2,556	)
Earnings before income taxes	2,920		514		358		2,146		(5,369	)	569
Income tax (expense)/recovery	(61	)	—		9		2,706		43		2,697
Earnings	2,859		514		367		4,852		(5,326	)	3,266
Earnings attributable to noncontrolling interests and redeemable noncontrolling interests	—		—		—		—		(407	)	(407	)
Earnings attributable to controlling interests	2,859		514		367		4,852		(5,733	)	2,859
Preference share dividends	(330	)	—		—		—		—		(330	)
Earnings attributable to common shareholders	2,529		514		367		4,852		(5,733	)	2,529
Earnings	2,859		514		367		4,852		(5,326	)	3,266
Total other comprehensive income/(loss)	(2,031	)	12		204		(412	)	(51	)	(2,278	)
Comprehensive income	828		526		571		4,440		(5,377	)	988
Comprehensive income attributable to noncontrolling interests	—		—		—		—		(160	)	(160	)
Comprehensive income attributable to controlling interests	828		526		571		4,440		(5,537	)	828

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Condensed Consolidating Statements of Earnings and Comprehensive Income for the year ended December 31, 2016

	Parent Issuer and Guarantor		Subsidiary Issuer and Guarantor - EEP		Subsidiary Non-Guarantors		Consolidating and elimination adjustments		Consolidated - Enbridge
(millions of Canadian dollars)
Operating revenues
Commodity sales	—		—		22,816		—		22,816
Gas distribution sales	—		—		2,486		—		2,486
Transportation and other services	—		—		9,258		—		9,258
Total operating revenues	—		—		34,560		—		34,560
Operating expenses
Commodity costs	—		—		22,409		—		22,409
Gas distribution costs	—		—		1,596		—		1,596
Operating and administrative	126		70		4,162		—		4,358
Depreciation and amortization	50		—		2,190		—		2,240
Impairment of long lived assets	—		—		1,376		—		1,376
Total operating expenses	176		70		31,733		—		31,979
Operating income/(loss)	(176	)	(70	)	2,827		—		2,581
Income from equity investments	723		—		423		(718	)	428
Equity earnings/(loss) from consolidated subsidiaries	1,055		442		(81	)	(1,416	)	—
Other
Net foreign currency gain/(loss)	187		—		(3	)	(93	)	91
Gain on dispositions	—		—		848		—		848
Other, including other income/(expense) from affiliates	791		107		90		(895	)	93
Interest expense	(606	)	(560	)	(1,344	)	920		(1,590	)
Earnings/(loss) before income taxes	1,974		(81	)	2,760		(2,202	)	2,451
Income tax recovery/(expense)	95		—		(237	)	—		(142	)
Earnings/(loss)	2,069		(81	)	2,523		(2,202	)	2,309
Earnings attributable to noncontrolling interests and redeemable noncontrolling interests	—		—		—		(240	)	(240	)
Earnings/(loss) attributable to controlling interests	2,069		(81	)	2,523		(2,442	)	2,069
Preference share dividends	(293	)	—		—		—		(293	)
Earnings/(loss) attributable to common shareholders	1,776		(81	)	2,523		(2,442	)	1,776
Earnings/(loss)	2,069		(81	)	2,523		(2,202	)	2,309
Total other comprehensive income/(loss)	(574	)	54		186		(251	)	(585	)
Comprehensive income/(loss)	1,495		(27	)	2,709		(2,453	)	1,724
Comprehensive income attributable to noncontrolling interests	—		—		—		(229	)	(229	)
Comprehensive income/(loss) attributable to controlling interests	1,495		(27	)	2,709		(2,682	)	1,495

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Condensed Consolidating Statements of Financial Position as at December 31, 2018

	Parent Issuer and Guarantor	Subsidiary Issuer and Guarantor - SEP	Subsidiary Issuer and Guarantor - EEP	Subsidiary Non-Guarantors		Consolidating and elimination adjustments		Consolidated - Enbridge
(millions of Canadian dollars)
Assets
Current assets
Cash and cash equivalents	—	16	—	502		—		518
Restricted cash	9	—	—	110		—		119
Accounts receivable and other	283	15	8	6,211		—		6,517
Accounts receivable from affiliates	726	—	13	(142	)	(518	)	79
Short-term loans receivable from affiliates	3,943	—	3,689	653		(8,285	)	—
Inventory	—	—	—	1,339		—		1,339
	4,961	31	3,710	8,673		(8,803	)	8,572
Property, plant and equipment, net	140	—	—	94,400		—		94,540
Long-term loans receivable from affiliates	10,318	73	2,539	1,344		(14,274	)	—
Investments in subsidiaries	78,474	19,777	6,363	15,567		(120,181	)	—
Long-term investments	4,561	987	—	14,841		(3,682	)	16,707
Restricted long-term investments	—	—	—	323		—		323
Deferred amounts and other assets	1,700	9	17	8,558		(1,726	)	8,558
Intangible assets, net	234	—	—	2,138		—		2,372
Goodwill	—	—	—	34,459		—		34,459
Deferred income taxes	817	—	—	229		328		1,374
Total assets	101,205	20,877	12,629	180,532		(148,338	)	166,905
Liabilities and equity
Current liabilities
Short-term borrowings	—	—	—	1,024		—		1,024
Accounts payable and other	2,742	7	34	7,059		(6	)	9,836
Accounts payable to affiliates	946	233	56	(677	)	(518	)	40
Interest payable	283	56	105	225		—		669
Short-term loans payable to affiliates	426	682	—	7,177		(8,285	)	—
Environmental liabilities, current	—	—	—	27		—		27
Current portion of long-term debt	1,853	—	683	723		—		3,259
	6,250	978	878	15,558		(8,809	)	14,855
Long-term debt	22,893	7,276	6,943	23,215		—		60,327
Other long-term liabilities	2,428	2	30	8,100		(1,726	)	8,834
Long-term loans payable to affiliates	76	—	1,502	12,696		(14,274	)	—
Deferred income taxes	—	331	—	13,523		(4,400	)	9,454
	31,647	8,587	9,353	73,092		(29,209	)	93,470
Equity
Controlling interests1	69,558	12,290	3,276	107,440		(123,094	)	69,470
Noncontrolling interests	—	—	—	—		3,965		3,965
	69,558	12,290	3,276	107,440		(119,129	)	73,435
Total liabilities and equity	101,205	20,877	12,629	180,532		(148,338	)	166,905

1 Equity attributable to controlling interests for parent issuer and guarantor excludes reciprocal shareholding balance included within consolidating and elimination adjustments.

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Condensed Consolidating Statements of Financial Position as at December 31, 2017

	Parent Issuer and Guarantor	Subsidiary Issuer and Guarantor - SEP	Subsidiary Issuer and Guarantor - EEP	Subsidiary Non-Guarantors		Consolidating and elimination adjustments		Consolidated - Enbridge
(millions of Canadian dollars)
Assets
Current assets
Cash and cash equivalents	—	14	—	466		—		480
Restricted cash	2	—	—	105		—		107
Accounts receivable and other	292	8	—	6,753		—		7,053
Accounts receivable from affiliates	593	—	41	(73	)	(514	)	47
Short-term loans receivable from affiliates	1,861	—	3,085	2,977		(7,923	)	—
Inventory	—	—	—	1,528		—		1,528
	2,748	22	3,126	11,756		(8,437	)	9,215
Property, plant and equipment, net	136	—	—	90,575		—		90,711
Long-term loans receivable from affiliates	14,205	574	2,352	(3,177	)	(13,954	)	—
Investments in subsidiaries	55,466	21,528	5,993	16,672		(99,659	)	—
Long-term investments	8,408	918	—	14,972		(7,654	)	16,644
Restricted long-term investments	—	—	—	267		—		267
Deferred amounts and other assets	904	8	5	7,250		(1,725	)	6,442
Intangible assets, net	219	—	—	3,048		—		3,267
Goodwill	—	—	—	34,457		—		34,457
Deferred income taxes	809	—	—	254		27		1,090
Total assets	82,895	23,050	11,476	176,074		(131,402	)	162,093
Liabilities and equity
Current liabilities
Short-term borrowings	—	—	—	1,444		—		1,444
Accounts payable and other	1,927	100	19	7,432		—		9,478
Accounts payable to affiliates	56	171	—	444		(514	)	157
Interest payable	216	51	102	265		—		634
Short-term loans payable to affiliates	868	—	—	7,055		(7,923	)	—
Environmental liabilities, current	—	—	—	40		—		40
Current portion of long-term debt	—	626	501	1,744		—		2,871
	3,067	948	622	18,424		(8,437	)	14,624
Long-term debt	20,173	7,605	7,852	25,235		—		60,865
Other long-term liabilities	1,342	38	21	7,834		(1,725	)	7,510
Long-term loans payable to affiliates	76	4	764	13,110		(13,954	)	—
Deferred income taxes	—	—	—	9,295		—		9,295
	24,658	8,595	9,259	73,898		(24,116	)	92,294
Redeemable noncontrolling interests	—	—	—	—		4,067		4,067
Equity
Controlling interests1	58,237	14,455	2,217	102,176		(118,950	)	58,135
Noncontrolling Interests	—	—	—	—		7,597		7,597
	58,237	14,455	2,217	102,176		(111,353	)	65,732
Total liabilities and equity	82,895	23,050	11,476	176,074		(131,402	)	162,093

1 Equity attributable to controlling interests for parent issuer and guarantor excludes reciprocal shareholding balance included within consolidating and elimination adjustments.

103

Condensed Consolidating Statements of Cash Flows for the year ended December 31, 2018

	Parent Issuer and Guarantor		Subsidiary Issuer and Guarantor - SEP		Subsidiary Issuer and Guarantor - EEP		Subsidiary Non-Guarantors		Consolidating and elimination adjustments		Consolidated - Enbridge
(millions of Canadian dollars)
Net cash provided by/(used in) operating activities	154		1,751		(1,328	)	12,772		(2,847	)	10,502
Investing activities
Capital expenditures	(28	)	—		—		(6,778	)	—		(6,806	)
Long-term investments	(81	)	(12	)	—		(1,297	)	78		(1,312	)
Distributions from equity investments in excess of cumulative earnings	1,829		45		2,071		1,232		(3,900	)	1,277
Additions to intangible assets	(43	)	—		—		(497	)	—		(540	)
Proceeds from dispositions	1,790		—		—		2,662		—		4,452
Contributions to subsidiaries	(8,131	)	(79	)	(13	)	(1,655	)	9,878		—
Return of share capital from subsidiaries	3,753		—		—		—		(3,753	)	—
Advances to affiliates	(6,863	)	—		(1,703	)	(4,859	)	13,425		—
Repayment of advances to affiliates	9,427		518		1,504		3,298		(14,747	)	—
Other	—		—		—		(88	)	—		(88	)
Net cash provided by/(used in) investing activities	1,653		472		1,859		(7,982	)	981		(3,017	)
Financing activities
Net change in short-term borrowings	—		—		—		(420	)	—		(420	)
Net change in commercial paper and credit facility draws	(734	)	(962	)	(1,009	)	449		—		(2,256	)
Debenture and term note issues, net of issue costs	2,554		—		—		983		—		3,537
Debenture and term note repayments	—		(648	)	(509	)	(3,288	)	—		(4,445	)
Sale of noncontrolling interests in subsidiaries	—		—		—		—		1,289		1,289
Contributions from noncontrolling interests	—		—		—		—		24		24
Distributions to noncontrolling interests	—		—		—		—		(857	)	(857	)
Contributions from redeemable noncontrolling interests	—		—		—		—		70		70
Distributions to redeemable noncontrolling interests	—		—		—		—		(325	)	(325	)
Contributions from parents	—		—		1,007		8,223		(9,230	)	—
Distributions to parents	—		(1,902	)	(666	)	(7,653	)	10,221		—
Sponsored Vehicle buy-in cash payment	(64	)	—		—		—		—		(64	)
Redemption of preferred shares	—		—		—		(210	)	—		(210	)
Common shares issued	21		648		—		—		(648	)	21
Preference share dividends	(364	)	—		—		—		—		(364	)
Common share dividends	(3,480	)	—		—		—		—		(3,480	)
Advances from affiliates	710		648		3,501		8,566		(13,425	)	—
Repayment of advances from affiliates	(443	)	—		(2,855	)	(11,449	)	14,747		—
Other	—		(5	)	—		(18	)	—		(23	)
Net cash (used in)/provided by financing activities	(1,800	)	(2,221	)	(531	)	(4,817	)	1,866		(7,503	)
Effect of translation of foreign denominated cash and cash equivalents and restricted cash	—		—		—		68		—		68
Net increase in cash and cash equivalents and restricted cash	7		2		—		41		—		50
Cash and cash equivalents and restricted cash at beginning of year	2		14		—		571		—		587
Cash and cash equivalents and restricted cash at end of year	9		16		—		612		—		637

104

Condensed Consolidating Statements of Cash Flows for the year ended December 31, 2017

	Parent Issuer and Guarantor		Subsidiary Issuer and Guarantor - SEP		Subsidiary Issuer and Guarantor - EEP		Subsidiary Non-Guarantors		Consolidating and elimination adjustments		Consolidated - Enbridge
(millions of Canadian dollars)
Net cash (used in)/provided by operating activities	(1,023	)	(255	)	(1,681	)	11,411		(1,794	)	6,658
Investing activities
Capital expenditures	(21	)	—		—		(8,266	)	—		(8,287	)
Long-term investments	(202	)	(51	)	—		(3,535	)	202		(3,586	)
Distributions from equity investments in excess of cumulative earnings	1,448		22		1,907		103		(3,355	)	125
Additions to intangible assets	(47	)	—		—		(742	)	—		(789	)
Cash acquired in Merger Transaction	—		—		—		682		—		682
Proceeds from dispositions	—		—		1,742		1,103		(2,217	)	628
Reimbursement of capital expenditures	—		—		—		212		—		212
Contributions to subsidiaries	(4,866	)	—		(2,056	)	—		6,922		—
Return of share capital from subsidiaries	2,423		—		1,532		—		(3,955	)	—
Advances to affiliates	(7,145	)	(519	)	(1,410	)	(3,020	)	12,094		—
Repayment of advances to affiliates	4,506		—		2,129		2,887		(9,522	)	—
Other	—		—		—		(22	)	—		(22	)
Net cash (used in)/provided by investing activities	(3,904	)	(548	)	3,844		(10,598	)	169		(11,037	)
Financing activities
Net change in short-term borrowings	—		—		—		721		—		721
Net change in commercial paper and credit facility draws	(1,845	)	2,226		(316	)	(1,314	)	—		(1,249	)
Debenture and term note issues, net of issue costs	8,177		868		—		438		—		9,483
Debenture and term note repayments	(1,711	)	(533	)	—		(2,810	)	—		(5,054	)
Purchase of interest in consolidated subsidiary	—		—		(475	)	(1,969	)	2,217		(227	)
Contributions from noncontrolling interests	—		—		—		—		832		832
Distributions to noncontrolling interests	—		—		—		—		(919	)	(919	)
Contributions from redeemable noncontrolling interests	563		—		—		—		615		1,178
Distributions to redeemable noncontrolling interests	—		—		—		—		(247	)	(247	)
Contributions from parents	—		—		—		6,922		(6,922	)	—
Distributions to parents	—		(1,987	)	(789	)	(7,310	)	10,086		—
Preference shares issued	489		—		—		—		—		489
Redemption of preferred shares	—		—		(1,613	)	1,613		—		—
Common shares issued	1,549		227		1,646		—		(1,873	)	1,549
Preference share dividends	(330	)	—		(478	)	—		478		(330	)
Common share dividends1	(2,336	)	—		—		(414	)	—		(2,750	)
Advances from affiliates	407		—		2,613		9,074		(12,094	)	—
Repayment of advances from affiliates	(40	)	—		(2,847	)	(6,635	)	9,522		—
Net cash provided by/(used in) financing activities	4,923		801		(2,259	)	(1,684	)	1,695		3,476
Effect of translation of foreign denominated cash and cash equivalents and restricted cash	—		—		(2	)	—		(70	)	(72	)
Net decrease in cash and cash equivalents and restricted cash	(4	)	(2	)	(98	)	(871	)	—		(975	)
Cash and cash equivalents and restricted cash at beginning of year	6		16		98		1,442		—		1,562
Cash and cash equivalents and restricted cash at end of year	2		14		—		571		—		587

1Common share dividends for the year ended December 31, 2017 includes amounts distributed by Spectra Energy Corp. related to dividends accrued prior to the Merger Transaction.

105

Condensed Consolidating Statements of Cash Flows for the year ended December 31, 2016

	Parent Issuer and Guarantor		Subsidiary Issuer and Guarantor - EEP		Subsidiary Non-Guarantors		Consolidating and elimination adjustments		Consolidated - Enbridge
(millions of Canadian dollars)
Net cash provided by/(used in) operating activities	(65	)	(1,818	)	8,579		(1,491	)	5,205
Investing activities
Capital expenditures	(21	)	—		(5,107	)	—		(5,128	)
Long-term investments	(194	)	—		(514	)	194		(514	)
Distributions from equity investments in excess of cumulative earnings	1,233		2,717		—		(3,950	)	—
Additions to intangible assets	(37	)	—		(90	)	—		(127	)
Acquisitions	—		—		(644	)	—		(644	)
Proceeds from dispositions	—		—		1,379		—		1,379
Contributions to subsidiaries	(970	)	(463	)	—		1,433		—
Return of share capital from subsidiaries	350		—		—		(350	)	—
Advances to affiliates	(4,307	)	(1,623	)	(1,518	)	7,448		—
Repayment of advances to affiliates	1,577		1,382		400		(3,359	)	—
Other	—		17		(135	)	—		(118	)
Net cash (used in)/provided by investing activities	(2,369	)	2,030		(6,229	)	1,416		(5,152	)
Financing activities
Net change in short-term borrowings	—		—		(248	)	—		(248	)
Net change in commercial paper and credit facility draws	(1,083	)	289		(1,503	)	—		(2,297	)
Debenture and term note issues, net of issue costs	3,009		—		1,071		—		4,080
Debenture and term note repayments	(1,160	)	(400	)	(386	)	—		(1,946	)
Contributions from noncontrolling interests	—		—		—		28		28
Distributions to noncontrolling interests	—		—		—		(720	)	(720	)
Contributions from redeemable noncontrolling interests	—		—		—		591		591
Distributions to redeemable noncontrolling interests	—		—		—		(202	)	(202	)
Contributions from parents	—		—		1,433		(1,433	)	—
Distributions to parents	—		(1,060	)	(4,840	)	5,900		—
Preference shares issued	737		—		—		—		737
Common shares issued	2,260		—		—		—		2,260
Preference share dividends	(293	)	—		—		—		(293	)
Common share dividends	(1,150	)	—		—		—		(1,150	)
Advances from affiliates	518		1,000		5,930		(7,448	)	—
Repayment of advances from affiliates	(400	)	—		(2,959	)	3,359		—
Net cash provided by/(used in) financing activities	2,438		(171	)	(1,502	)	75		840
Effect of translation of foreign denominated cash and cash equivalents and restricted cash	—		1		(20	)	—		(19	)
Net increase in cash and cash equivalents and restricted cash	4		42		828		—		874
Cash and cash equivalents and restricted cash at beginning of year	2		56		630		—		688
Cash and cash equivalents and restricted cash at end of year	6		98		1,458		—		1,562

32.  SUBSEQUENT EVENTS

On January 1, 2019, the previously approved OEB application to amalgamate EGD and Union Gas took effect and the amalgamated company continued as EGI. Refer to Note 7 - Regulatory Matters for further discussion.

On January 15, 2019, Enbridge closed the acquisition of 100% of pipeline and tankage infrastructure assets at the Cheecham tank farm for a purchase price of $265 million. These assets were acquired from Athabasca Oil Corporation and were associated with the Leismer SAGD oil sands assets, and are included in our Liquids Pipelines segment.

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33.  QUARTERLY FINANCIAL DATA

	Q1	Q2	Q3		Q4		Total
(unaudited; millions of Canadian dollars, except per share amounts)
2018
Operating revenues	12,726	10,745	11,345		11,562		46,378
Operating income	878	1,571	854		1,513		4,816
Earnings	510	1,327	213		1,283		3,333
Earnings attributable to controlling interests	534	1,160	4		1,184		2,882
Earnings/(loss) attributable to common shareholders	445	1,071	(90	)	1,089		2,515
Earnings/(loss) per common share
Basic	0.26	0.63	(0.05	)	0.60		1.46
Diluted	0.26	0.63	(0.05	)	0.60		1.46
20171
Operating revenues	11,146	11,116	9,227		12,889		44,378
Operating income/(loss)	1,358	1,684	1,490		(2,961	)	1,571
Earnings/(loss)	945	1,241	1,015		65		3,266
Earnings/(loss) attributable to controlling interests	721	1,000	847		291		2,859
Earnings/(loss) attributable to common shareholders	638	919	765		207		2,529
Earnings/(loss) per common share
Basic	0.54	0.56	0.47		0.13		1.66
Diluted	0.54	0.56	0.47		0.12		1.65

1 The 2017 quarterly financial data reflects the effect of the Merger Transaction closed on February 27, 2017 (Note 8).

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