UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

x		QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 2018

OR

o		TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from            to           

Commission file number 1-10934

ENBRIDGE INC. (Exact Name of Registrant as Specified in Its Charter)

Canada		None
(State or Other Jurisdiction of Incorporation or Organization)		(I.R.S. Employer Identification No.)

200, 425 - 1st Street S.W.

Calgary, Alberta, Canada T2P 3L8

(Address of Principal Executive Offices) (Zip Code)

(403) 231-3900

(Registrant’s Telephone Number, Including Area Code)

Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No o

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes x No o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer x		Accelerated filer o
Non-accelerated filer o		Smaller reporting company o
Emerging growth company o

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No x

The registrant had 1,724,389,606 common shares outstanding as of October 26, 2018.

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		Page
	PART I
Item 1.	Financial Statements	6
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	43
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	67
Item 4.	Controls and Procedures	67
	PART II
Item 1.	Legal Proceedings	67
Item 1A.	Risk Factors	68
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	69
Item 3.	Defaults Upon Senior Securities	69
Item 4.	Mine Safety Disclosures	69
Item 5.	Other Information	69
Item 6.	Exhibits	70
	Signatures	70

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GLOSSARY

 

AOCI	Accumulated other comprehensive income/(loss)
Army Corps	United States Army Corps of Engineers
ASC	Accounting Standards Codification
ASU	Accounting Standards Update
CPPIB	Canada Pension Plan Investment Board
DRIP	Dividend Reinvestment and Share Purchase Plan
EBITDA	Earnings before interest, income taxes and depreciation and amortization
ECRLP	Enbridge Canadian Renewable LP
Eddystone Rail	Eddystone Rail Company, LLC
EEP	Enbridge Energy Partners, L.P.
EEQ	Enbridge Energy Management L.L.C.
EGD	Enbridge Gas Distribution Inc.
Enbridge	Enbridge Inc.
ENF	Enbridge Income Fund Holdings Inc.
ERII	Enbridge Renewable Infrastructure Investments S.a.r.l.
FERC	Federal Energy Regulatory Commission
IDRs	Incentive distribution rights
IJ	International Joint Tariff
kbpd	thousands of barrels per day
Line 10	Line 10 crude oil pipeline
MLP	Master Limited Partnership
MOLP	Midcoast Operating, L.P. and its subsidiaries
NGL	Natural gas liquids
OCI	Other comprehensive income/(loss)
OEB	Ontario Energy Board
Route Permit	Approved pipeline route for construction of the United States Line 3 Replacement Program
Sabal Trail	Sabal Trail Transmission, LLC
Seaway Pipeline	Seaway Crude Pipeline System
SEP	Spectra Energy Partners, LP
TCJA or United States Tax Reform	Tax Cuts and Jobs Act
the Court	United States District Court for the District of Columbia
the Fund Group	Enbridge Income Fund, Enbridge Commercial Trust, Enbridge Income Partners LP and the subsidiaries and investees of Enbridge Income Partners LP
the Merger Transaction	The stock-for-stock merger transaction on February 27, 2017 between Enbridge and Spectra Energy Corp
Union Gas	Union Gas Limited
U.S. L3R Program	United States Line 3 Replacement Program
VIE	Variable Interest Entity

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CONVENTIONS

The terms "we", "our", "us" and "Enbridge" as used in this report refer collectively to Enbridge Inc. 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.

Unless otherwise specified, all dollar amounts are expressed in Canadian dollars, all references to “dollars”, “$” or “C$” are to Canadian dollars and all references to “US$” are to United States dollars. All amounts are provided on a before tax basis, unless otherwise stated.

FORWARD-LOOKING INFORMATION

Forward-looking information, or forward-looking statements, have been included in this quarterly report on Form 10-Q to provide information about us and our subsidiaries and affiliates, including management’s assessment of us and our subsidiaries’ future plans and operations. This information may not be appropriate for other purposes. Forward-looking statements are typically identified by words such as ‘‘anticipate”, “believe”, “estimate”, “expect”, “forecast”, “intend”, “likely”, “plan”, “project”, “target” and similar words suggesting future outcomes or statements regarding an outlook. Forward-looking information or statements included or incorporated by reference in this document include, but are not limited to, statements with respect to the following: expected earnings before interest, income taxes and depreciation and amortization (EBITDA); expected earnings/(loss); expected earnings/(loss) per share; expected future cash flows; expected performance of the Liquids Pipelines, Gas Transmission and Midstream, Gas Distribution, Green Power and Transmission, and Energy Services businesses; financial strength and flexibility; expectations on sources of liquidity and sufficiency of financial resources; expected costs related to announced projects and projects under construction; expected in-service dates for announced projects and projects under construction; expected capital expenditures; expected equity funding requirements for our commercially secured growth program; expected future growth and expansion opportunities; expectations about our joint venture partners’ ability to complete and finance projects under construction; expected closing of acquisitions and dispositions and expected timing thereof; estimated future dividends; expected future actions of regulators; expected costs related to leak remediation and potential insurance recoveries; expectations regarding commodity prices; supply forecasts; expectations regarding the impact of the stock-for-stock merger transaction on February 27, 2017 between Enbridge and Spectra Energy Corp (the Merger Transaction) including our combined scale, financial flexibility, growth program, future business prospects and performance; United States Line 3 Replacement Program (U.S. L3R Program); expected impact of the Federal Energy Regulatory Commission (FERC) policy on treatment of income taxes; the sponsored vehicle strategy, including the proposed simplifications of our corporate structure; dividend payout policy; dividend growth and dividend payout expectation; expectations on impact of hedging program; and expectations resulting from the successful execution of our 2018-2020 Strategic Plan.

Although we believe these forward-looking statements are reasonable based on the information available on the date such statements are made and processes used to prepare the information, such statements are not guarantees of future performance and readers are cautioned against placing undue reliance on forward-looking statements. By their nature, these statements involve a variety of assumptions, known and unknown risks and uncertainties and other factors, which may cause actual results, levels of activity and achievements to differ materially from those expressed or implied by such statements. Material assumptions include assumptions about the following: the expected supply of and demand for crude oil, natural gas, natural gas liquids (NGL) and renewable energy; prices of crude oil, natural gas, NGL and renewable energy; exchange rates; inflation; interest rates; availability and price of labor and construction materials; operational reliability; customer and regulatory approvals; maintenance of support and regulatory approvals for our projects; anticipated in-service dates; weather; the timing and closing of dispositions; the realization of anticipated benefits and synergies of the Merger Transaction; governmental legislation; acquisitions and the timing thereof; the success of integration plans; impact of the dividend policy on our future cash flows; credit ratings; capital project funding; expected EBITDA; expected earnings/(loss); expected earnings/(loss) per share; expected future cash flows and estimated future dividends. Assumptions regarding the expected supply of and demand for crude oil, natural gas, NGL and renewable energy, and the prices of these commodities, are material to and underlie all forward-looking statements, as they may impact current and future levels of demand for our services. Similarly, exchange rates, inflation and interest rates impact the economies and business environments in which we operate and may impact levels of demand for our services and cost of inputs, and are therefore inherent in all forward-looking statements. Due to the interdependencies and correlation of these macroeconomic factors, the impact of any one assumption on a forward-looking statement cannot be determined with certainty, particularly with

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respect to the impact of the Merger Transaction on us, expected EBITDA, earnings/(loss), earnings/(loss) per share, or estimated future dividends. The most relevant assumptions associated with forward-looking statements on announced projects and projects under construction, including estimated completion dates and expected capital expenditures, include the following: the availability and price of labor and construction materials; the effects of inflation and foreign exchange rates on labor and material costs; the effects of interest rates on borrowing costs; the impact of weather and customer, government and regulatory approvals on construction and in-service schedules and cost recovery regimes.

Our forward-looking statements are subject to risks and uncertainties pertaining to the realization of anticipated benefits and synergies of the Merger Transaction, operating performance, regulatory parameters, dispositions, the proposed simplification of our corporate structure, dividend policy, project approval and support, renewals of rights-of-way, weather, economic and competitive conditions, public opinion, changes in tax laws and tax rates, changes in trade agreements, exchange rates, interest rates, commodity prices, political decisions and supply of and demand for commodities, including but not limited to those risks and uncertainties discussed in this quarterly report on Form 10-Q and in our other filings with Canadian and United States securities regulators. The impact of any one risk, uncertainty or factor on a particular forward-looking statement is not determinable with certainty as these are interdependent and our future course of action depends on management’s assessment of all information available at the relevant time. Except to the extent required by applicable law, Enbridge Inc. assumes no obligation to publicly update or revise any forward-looking statements made in this quarterly report on Form 10-Q or otherwise, whether as a result of new information, future events or otherwise. All subsequent forward-looking statements, whether written or oral, attributable to us or persons acting on our behalf, are expressly qualified in their entirety by these cautionary statements.

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PART I - FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

ENBRIDGE INC.

CONSOLIDATED STATEMENTS OF EARNINGS

	Three months ended September 30,					Nine months ended September 30,
	2018		2017			2018		2017
(unaudited; millions of Canadian dollars, except per share amounts)
Operating revenues
Commodity sales	6,919		5,012			20,638		18,498
Gas distribution sales	478		573			3,260		2,783
Transportation and other services	3,948		3,642			10,918		10,208
Total operating revenues (Note 3)	11,345		9,227			34,816		31,489
Operating expenses
Commodity costs	6,905		5,087			20,180		18,126
Gas distribution costs	112		215			1,857		1,659
Operating and administrative	1,652		1,587			4,929		4,784
Depreciation and amortization	799		848			2,452		2,388
Asset impairment (Note 6)	4		—			1,076		—
Goodwill impairment (Note 6)	1,019		—			1,019		—
Total operating expenses	10,491		7,737			31,513		26,957
Operating income	854		1,490			3,303		4,532
Income from equity investments	378		280			1,076		752
Other income/(expense)
Net foreign currency gain/(loss)	57		150			(171	)	257
Other	(33	)	75			61		182
Interest expense	(696	)	(653	)		(2,042	)	(1,704	)
Earnings before income taxes	560		1,342			2,227		4,019
Income tax expense (Note 12)	(347	)	(327	)		(177	)	(818	)
Earnings	213		1,015			2,050		3,201
Earnings attributable to noncontrolling interests and redeemable noncontrolling interests	(209	)	(168	)		(352	)	(633	)
Earnings attributable to controlling interests	4		847			1,698		2,568
Preference share dividends	(94	)	(82	)		(272	)	(246	)
Earnings/(loss) attributable to common shareholders	(90	)	765			1,426		2,322
Earnings/(loss) per common share attributable to common shareholders (Note 5)	(0.05	)	0.47			0.84		1.57
Diluted earnings/(loss) per common share attributable to common shareholders (Note 5)	(0.05	)	0.47			0.84		1.56

 See accompanying notes to the interim consolidated financial statements.

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ENBRIDGE INC.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

	Three months ended September 30,					Nine months ended September 30,
	2018		2017			2018		2017
(unaudited; millions of Canadian dollars)
Earnings	213		1,015			2,050		3,201
Other comprehensive income/(loss), net of tax
Change in unrealized gain on cash flow hedges	57		97			150		10
Change in unrealized gain/(loss) on net investment hedges	83		285			(200	)	505
Other comprehensive income from equity investees	(1	)	1			18		9
Reclassification to earnings of (gain)/loss on cash flow hedges	31		(14	)		104		93
Reclassification to earnings of pension and other postretirement benefits (OPEB) amounts	5		6			28		13
Foreign currency translation adjustments	(989	)	(2,057	)		1,637		(3,068	)
Other comprehensive income/(loss), net of tax	(814	)	(1,682	)		1,737		(2,438	)
Comprehensive income/(loss)	(601	)	(667	)		3,787		763
Comprehensive (income)/loss attributable to noncontrolling interests and redeemable noncontrolling interests	(102	)	155			(546	)	(204	)
Comprehensive income/(loss) attributable to controlling interests	(703	)	(512	)		3,241		559
Preference share dividends	(94	)	(82	)		(272	)	(246	)
Comprehensive income/(loss) attributable to common shareholders	(797	)	(594	)		2,969		313

See accompanying notes to the interim consolidated financial statements.

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ENBRIDGE INC.

CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY

	Nine months ended September 30,
	2018		2017
(unaudited; millions of Canadian dollars, except per share amounts)
Preference shares
Balance at beginning and end of period	7,747		7,255
Common shares
Balance at beginning of period	50,737		10,492
Common shares issued in Merger Transaction	—		37,429
Dividend Reinvestment and Share Purchase Plan	1,181		889
Shares issued on exercise of stock options	26		58
Balance at end of period	51,944		48,868
Additional paid-in capital
Balance at beginning of period	3,194		3,399
Stock-based compensation	40		70
Fair value of outstanding earned stock-based compensation from Merger Transaction	—		77
Options exercised	(14	)	(70	)
Enbridge Energy Company, Inc. common control transaction	—		78
Dilution loss on Enbridge Energy Partners, L.P. issuance of Class A units	—		(522	)
Dilution gain on Spectra Energy Partners, LP restructuring (Note 10)	1,136		—
Dilution gains/(losses) and other	(89	)	62
Sale of noncontrolling interests in subsidiaries (Note 10)	79		—
Balance at end of period	4,346		3,094
Deficit
Balance at beginning of period	(2,468	)	(716	)
Earnings attributable to controlling interests	1,698		2,568
Preference share dividends	(272	)	(246	)
Common share dividends declared	(2,297	)	(2,552	)
Dividends paid to reciprocal shareholder	25		22
Modified retrospective adoption of accounting standard (Note 2)	(86	)	—
Redemption value adjustment attributable to redeemable noncontrolling interests	(318	)	232
Adjustment for the recognition of unutilized tax deductions for stock-based compensation expense	—		41
Balance at end of period	(3,718	)	(651	)
Accumulated other comprehensive income/(loss) (Note 9)
Balance at beginning of period	(973	)	1,058
Other comprehensive income/(loss) attributable to common shareholders, net of tax	1,543		(2,009	)
Balance at end of period	570		(951	)
Reciprocal shareholding
Balance at beginning and end of period	(102	)	(102	)
Total Enbridge Inc. shareholders’ equity	60,787		57,513
Noncontrolling interests
Balance at beginning of period	7,597		577
Earnings attributable to noncontrolling interests	248		452
Other comprehensive income/(loss) attributable to noncontrolling interests, net of tax
Change in unrealized gain/(loss) on cash flow hedges	8		(13	)
Foreign currency translation adjustments	140		(446	)
Reclassification to earnings of loss on cash flow hedges	23		29
	171		(430	)
Comprehensive income attributable to noncontrolling interests	419		22
Noncontrolling interests resulting from Merger Transaction	—		8,877
Enbridge Energy Company, Inc. common control transaction	—		(331	)
Dilution gain on Enbridge Energy Partners, L.P. issuance of Class A units	—		832
Spectra Energy Partners, LP restructuring (Note 10)	(1,486	)	—
Sale of noncontrolling interests in subsidiaries (Note 10)	1,183		—
Distributions	(637	)	(634	)
Contributions	23		498
Deconsolidation of Sabal Trail Transmission, LLC	—		(2,318	)
Disposition of Olympic Pipeline	—		(24	)
Other	12		(16	)
Balance at end of period	7,111		7,483
Total equity	67,898		64,996
Dividends paid per common share	2.013		1.803

See accompanying notes to the interim consolidated financial statements.

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ENBRIDGE INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

	Nine months ended September 30,
	2018		2017
(unaudited; millions of Canadian dollars)
Operating activities
Earnings	2,050		3,201
Adjustments to reconcile earnings to net cash provided by operating activities:
Depreciation and amortization	2,452		2,388
Deferred income tax (recovery)/expense	(51	)	725
Changes in unrealized (gain)/loss on derivative instruments, net (Note 11)	319		(1,243	)
Earnings from equity investments	(1,076	)	(752	)
Distributions from equity investments	1,090		859
Asset impairment	1,076		—
Goodwill impairment	1,019		—
(Gain)/loss on dispositions	76		(116	)
Other	101		132
Changes in operating assets and liabilities	943		121
Net cash provided by operating activities	7,999		5,315
Investing activities
Capital expenditures	(4,584	)	(5,868	)
Long-term investments	(1,051	)	(3,012	)
Distributions from equity investments in excess of cumulative earnings (Note 7)	1,243		62
Additions to intangible assets	(491	)	(668	)
Cash acquired in Merger Transaction	—		681
Proceeds from dispositions	1,913		622
Reimbursement of capital expenditures	—		212
Other	(102	)	(63	)
Net cash used in investing activities	(3,072	)	(8,034	)
Financing activities
Net change in short-term borrowings	(196	)	705
Net change in commercial paper and credit facility draws	(2,358	)	956
Debenture and term note issues, net of issue costs	3,537		7,176
Debenture and term note repayments	(3,757	)	(4,446	)
Sale of noncontrolling interest in subsidiaries	1,289		—
Purchase of interest in consolidated subsidiary	—		(227	)
Contributions from noncontrolling interests	23		498
Distributions to noncontrolling interests	(637	)	(714	)
Contributions from redeemable noncontrolling interests	62		614
Distributions to redeemable noncontrolling interests	(264	)	(180	)
Common shares issued	17		22
Preference share dividends	(268	)	(246	)
Common share dividends	(2,254	)	(2,077	)
Other	(5	)	—
Net cash provided by/(used in) financing activities	(4,811	)	2,081
Effect of translation of foreign denominated cash and cash equivalents and restricted cash	23		(77	)
Net increase/(decrease) in cash and cash equivalents and restricted cash	139		(715	)
Cash and cash equivalents and restricted cash at beginning of period	587		1,562
Cash and cash equivalents and restricted cash at end of period	726		847

See accompanying notes to the interim consolidated financial statements.

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ENBRIDGE INC.

CONSOLIDATED STATEMENTS OF FINANCIAL POSITION

	September 30, 2018		December 31, 2017
(unaudited; millions of Canadian dollars; number of shares in millions)
Assets
Current assets
Cash and cash equivalents	643		480
Restricted cash	83		107
Accounts receivable and other	5,668		7,053
Accounts receivable from affiliates	75		47
Inventory	1,362		1,528
	7,831		9,215
Property, plant and equipment, net	90,679		90,711
Long-term investments	15,983		16,911
Deferred amounts and other assets	10,638		6,442
Intangible assets, net	3,273		3,267
Goodwill	33,477		34,457
Deferred income taxes	1,342		1,090
Total assets	163,223		162,093
Liabilities and equity
Current liabilities
Short-term borrowings	1,251		1,444
Accounts payable and other	7,599		9,518
Accounts payable to affiliates	190		157
Interest payable	611		634
Current portion of long-term debt	3,516		2,871
	13,167		14,624
Long-term debt	58,707		60,865
Other long-term liabilities	9,090		7,510
Deferred income taxes	10,040		9,295
	91,004		92,294
Contingencies (Note 14)
Redeemable noncontrolling interests	4,321		4,067
Equity
Share capital
Preference shares	7,747		7,747
Common shares (1,794 and 1,695 outstanding at September 30, 2018 and December 31, 2017, respectively)	51,944		50,737
Additional paid-in capital	4,346		3,194
Deficit	(3,718	)	(2,468	)
Accumulated other comprehensive income/(loss) (Note 9)	570		(973	)
Reciprocal shareholding	(102	)	(102	)
Total Enbridge Inc. shareholders’ equity	60,787		58,135
Noncontrolling interests	7,111		7,597
	67,898		65,732
Total liabilities and equity	163,223		162,093

See accompanying notes to the interim consolidated financial statements.

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NOTES TO THE INTERIM CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

1. BASIS OF PRESENTATION

 

The accompanying unaudited interim consolidated financial statements of Enbridge Inc. ("we", "our", "us" and "Enbridge") have been prepared in accordance with generally accepted accounting principles in the United States of America (U.S. GAAP) and Regulation S-X for interim consolidated financial information. They do not include all of the information and notes required by U.S. GAAP for annual consolidated financial statements and should therefore be read in conjunction with our audited consolidated financial statements and notes for the year ended December 31, 2017 included in our Annual Report on Form 10-K. In the opinion of management, the interim consolidated financial statements contain all normal recurring adjustments necessary to present fairly our financial position, results of operations and cash flows for the interim periods reported. These interim consolidated financial statements follow the same significant accounting policies as those included in our annual consolidated financial statements for the year ended December 31, 2017 included in our Annual Report on Form 10-K, except for the adoption of new standards (Note 2). Amounts are stated in Canadian dollars unless otherwise noted.

 

Our operations and earnings for interim periods can be affected by seasonal fluctuations within the gas distribution utility businesses, as well as other factors such as the supply of and demand for crude oil and natural gas, and may not be indicative of annual results.

Certain comparative figures in our Consolidated Statement of Cash Flows have been reclassified to conform to the current year's presentation. In addition, activities for the nine months ended September 30, 2017 relating to distributions to noncontrolling interests in relation to the stock-for-stock merger transaction on February 27, 2017 between Enbridge and Spectra Energy Corp (the Merger Transaction) have been reclassified, resulting in an increase to investing activities of $67 million and a decrease to financing activities of $67 million.

2. CHANGES IN ACCOUNTING POLICIES

 

ADOPTION OF NEW 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.

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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 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

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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 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 three and nine months ended September 30, 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	)

FUTURE ACCOUNTING POLICY CHANGES

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 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

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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 early adoption is permitted. We are currently assessing the impact of the new standard 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. We are currently assessing the impact of the new standard on our consolidated financial statements.

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 are currently assessing the impact of the new standard 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 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. The accounting update is effective January 1, 2020. We are currently assessing the impact of the new standard on our consolidated financial statements.

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Recognition of Leases

ASU 2016-02 was issued in February 2016 with the intent to increase transparency and comparability among organizations. It requires lessees of operating lease arrangements to recognize lease assets and lease liabilities on the statement 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. We will adopt the new standard on January 1, 2019 and we intend to apply the transition practical expedients offered in connection with this update. The election to apply the package of practical expedients allows an entity to not apply the new lease standard to the prior year comparative periods in the year of adoption. Application of the package of practical expedients also 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.

Further, 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 intend to elect 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 provides a practical expedient which allows lessors to combine associated lease and nonlease components within a contract when certain conditions are met. We intend to adopt the new transition option in connection with the adoption of the new lease requirements; however we continue to evaluate the lessor practical expedient to combine lease and nonlease components.

We have substantially completed the process of identifying existing lease contracts and are currently performing detailed evaluations of our leases under the new accounting requirements. We believe the most significant change to our financial statements will be the recognition of lease liabilities and right-of-use assets in our statement of financial position for operating leases. We continue to assess the necessary changes to accounting and business processes in order to implement the recognition and disclosure requirements of the new lease standard.

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3. 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
Three months ended September 30, 2018
(millions of Canadian dollars)
Transportation revenue	2,190		979		97		—		—		—		3,266
Storage and other revenue	31		53		55		—		—		—		139
Gas gathering and processing revenue	—		200		—		—		—		—		200
Gas distribution revenue	—		—		478		—		—		—		478
Electricity and transmission revenue	—		—		—		115		—		—		115
Commodity sales	—		298		—		—		—		—		298
Total revenue from contracts with customers	2,221		1,530		630		115		—		—		4,496
Commodity sales	—		—		—		—		6,621		—		6,621
Other revenue1	222		(6	)	11		2		—		(1	)	228
Intersegment revenue	86		4		4		—		25		(119	)	—
Total revenue	2,529		1,528		645		117		6,646		(120	)	11,345

	Liquids Pipelines		Gas Transmission and Midstream		Gas Distribution		Green Power and Transmission		Energy Services		Eliminations and Other		Consolidated
Nine months ended September 30, 2018
(millions of Canadian dollars)
Transportation revenue	6,327		2,889		487		—		—		—		9,703
Storage and other revenue	113		164		173		—		—		—		450
Gas gathering and processing revenue	—		636		—		—		—		—		636
Gas distribution revenue	—		—		3,260		—		—		—		3,260
Electricity and transmission revenue	—		—		—		417		—		—		417
Commodity sales	—		1,630		—		—		—		—		1,630
Total revenue from contracts with customers	6,440		5,319		3,920		417		—		—		16,096
Commodity sales	—		—		—		—		19,008		—		19,008
Other revenue1	(308	)	2		22		6		—		(10	)	(288	)
Intersegment revenue	256		8		10		—		106		(380	)	—
Total revenue	6,388		5,329		3,952		423		19,114		(390	)	34,816

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 September 30, 2018	1,625		267		1,203

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

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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 three and nine months ended September 30, 2018 included in contract liabilities at the beginning of the period is $19 million and $143 million, respectively. Increases in contract liabilities from cash received, net of amounts recognized as revenue during the three and nine months ended September 30, 2018 were $147 million and $345 million, respectively.

Performance Obligations

Segment	Nature of Performance Obligation
Liquids Pipelines	• Transportation and storage of crude oil and natural gas liquids (NGL)
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 three and nine months ended September 30, 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 $64.7 billion, of which $1.7 billion and $5.8 billion is expected to be recognized during the three months ending December 31, 2018, and the year ending December 31, 2019, respectively.

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

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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 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
Three months ended September 30, 2018
(millions of Canadian dollars)
Revenue from products transferred at a point in time1	—		298		20		—		—		318
Revenue from products and services transferred over time2	2,221		1,232		610		115		—		4,178
Total revenue from contracts with customers	2,221		1,530		630		115		—		4,496

	Liquids Pipelines		Gas Transmission and Midstream		Gas Distribution		Green Power and Transmission		Energy Services		Consolidated
Nine months ended September 30, 2018
(millions of Canadian dollars)
Revenue from products transferred at a point in time1	—		1,630		65		—		—		1,695
Revenue from products and services transferred over time2	6,440		3,689		3,855		417		—		14,401
Total revenue from contracts with customers	6,440		5,319		3,920		417		—		16,096

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 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

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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.

4.	SEGMENTED INFORMATION

Effective December 31, 2017, we changed our segment-level profit measure to Earnings before interest, income taxes, and depreciation and amortization from the previous measure of Earnings before interest and income taxes. We also renamed the Gas Pipelines and Processing segment to Gas Transmission and Midstream. The presentation of the prior year tables have been revised in order to align with the current presentation.

	Liquids Pipelines		Gas Transmission and Midstream		Gas Distribution		Green Power and Transmission		Energy Services		Eliminations and Other		Consolidated
Three months ended September 30, 2018
(millions of Canadian dollars)
Revenues	2,529		1,528		645		117		6,646		(120	)	11,345
Commodity and gas distribution costs	(5	)	(270	)	(137	)	—		(6,726	)	121		(7,017	)
Operating and administrative	(790	)	(519	)	(263	)	(38	)	(17	)	(25	)	(1,652	)
Asset impairment	—		—		—		(4	)	—		—		(4	)
Goodwill impairment	—		(1,019	)	—		—		—		—		(1,019	)
Income/(loss) from equity investments	131		262		(12	)	(6	)	3		—		378
Other income/(expense)	10		(42	)	23		(18	)	(2	)	53		24
Earnings/(loss) before interest, income taxes, and depreciation and amortization	1,875		(60	)	256		51		(96	)	29		2,055
Depreciation and amortization													(799	)
Interest expense													(696	)
Income tax expense													(347	)
Earnings													213
Capital expenditures1	651		413		311		6		—		(19	)	1,362

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	Liquids Pipelines		Gas Transmission and Midstream		Gas Distribution		Green Power and Transmission		Energy Services		Eliminations and Other		Consolidated
Three months ended September 30, 2017
(millions of Canadian dollars)
Revenues	2,324		1,862		716		109		4,284		(68	)	9,227
Commodity and gas distribution costs	(5	)	(703	)	(242	)	1		(4,421	)	68		(5,302	)
Operating and administrative	(770	)	(498	)	(246	)	(42	)	(11	)	(20	)	(1,587	)
Income/(loss) from equity investments	118		162		(3	)	—		3		—		280
Other income/(expense)	36		33		15		—		(5	)	146		225
Earnings/(loss) before interest, income taxes, and depreciation and amortization	1,703		856		240		68		(150	)	126		2,843
Depreciation and amortization													(848	)
Interest expense													(653	)
Income tax expense													(327	)
Earnings													1,015
Capital expenditures1	529		1,052		302		64		—		22		1,969

	Liquids Pipelines		Gas Transmission and Midstream		Gas Distribution		Green Power and Transmission		Energy Services		Eliminations and Other		Consolidated
Nine months ended September 30, 2018
(millions of Canadian dollars)
Revenues	6,388		5,329		3,952		423		19,114		(390	)	34,816
Commodity and gas distribution costs	(14	)	(1,481	)	(1,969	)	—		(18,965	)	392		(22,037	)
Operating and administrative	(2,251	)	(1,560	)	(782	)	(104	)	(50	)	(182	)	(4,929	)
Asset impairment	(154	)	(913	)	—		(4	)	—		(5	)	(1,076	)
Goodwill impairment	—		(1,019	)	—		—		—		—		(1,019	)
Income/(loss) from equity investments	399		699		(5	)	(27	)	10		—		1,076
Other income/(expense)	(15	)	25		66		(2	)	(1	)	(183	)	(110	)
Earnings/(loss) before interest, income taxes, and depreciation and amortization	4,353		1,080		1,262		286		108		(368	)	6,721
Depreciation and amortization													(2,452	)
Interest expense													(2,042	)
Income tax expense													(177	)
Earnings													2,050
Capital expenditures1	1,776		2,105		733		30		—		(11	)	4,633

	Liquids Pipelines		Gas Transmission and Midstream		Gas Distribution		Green Power and Transmission		Energy Services		Eliminations and Other		Consolidated
Nine months ended September 30, 2017
(millions of Canadian dollars)
Revenues	6,722		5,051		3,322		386		16,272		(264	)	31,489
Commodity and gas distribution costs	(13	)	(2,053	)	(1,740	)	4		(16,251	)	268		(19,785	)
Operating and administrative	(2,214	)	(1,305	)	(676	)	(123	)	(34	)	(432	)	(4,784	)
Income from equity investments	312		427		10		2		5		(4	)	752
Other income/(expense)	33		143		21		1		(3	)	244		439
Earnings/(loss) before interest, income taxes, and depreciation and amortization	4,840		2,263		937		270		(11	)	(188	)	8,111
Depreciation and amortization													(2,388	)
Interest expense													(1,704	)
Income tax expense													(818	)
Earnings													3,201
Capital expenditures1	1,723		3,081		794		293		1		90		5,982

 

1	Includes allowance for equity funds used during construction.

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5.	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 13 million for the three and nine months ended September 30, 2018 and 2017, resulting from our reciprocal investment in Noverco Inc.

 

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:

	Three months ended September 30,					Nine months ended September 30,
	2018		2017			2018		2017
(number of common shares in millions)
Weighted average shares outstanding	1,705		1,635			1,695		1,482
Effect of dilutive options	3		7			4		8
Diluted weighted average shares outstanding	1,708		1,642			1,699		1,490

For the three months ended September 30, 2018 and 2017, 21,081,642 and 12,917,175, respectively, anti-dilutive stock options with a weighted average exercise price of $52.17 and $56.79, respectively, were excluded from the diluted earnings per common share calculation.

For the nine months ended September 30, 2018 and 2017, 27,069,810 and 13,293,044, respectively, anti-dilutive stock options with a weighted average exercise price of $50.37 and $57.50, respectively, were excluded from the diluted earnings per common share calculation.

6.	ACQUISITIONS AND DISPOSITIONS

ASSETS HELD FOR SALE

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. The sale of the federally regulated facilities is expected to close in mid-2019 for proceeds of approximately $1.8 billion.

During the third quarter of 2018, we classified the Canadian Natural Gas Gathering and Processing Businesses assets as held for sale. 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 three and nine months ended September 30, 2018. Further, the held for sale

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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 Enbridge Energy Partners, L.P. (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 nine months ended September 30, 2018.

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

	September 30, 2018		December 31, 2017
(millions of Canadian dollars)
Accounts receivable and other (current assets held for sale)	154		424
Deferred amounts and other assets (long-term assets held for sale)1	4,841		1,190
Accounts payable and other (current liabilities held for sale)	(70	)	(315	)
Other long-term liabilities (long-term liabilities held for sale)2	(430	)	(34	)
Net assets held for sale	4,495		1,265

1	Included within Deferred amounts and other assets at September 30, 2018, is property, plant and equipment of $4.1 billion and goodwill of $482 million. Included within Deferred amounts and other assets at December 31, 2017, is property, plant and equipment of $1.1 billion.

2	Included within Other long-term liabilities at September 30, 2018 are deferred tax liabilities of $329 million.

DISPOSITIONS

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 farm 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 project. We will 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 farm 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 September 30, 2018 to reflect the interests that we do not hold (Note 10).

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Also, a deferred income tax recovery of $267 million ($196 million attributable to us) was recorded in the nine months ended September 30, 2018 as a result of the agreement entered into during the second quarter of 2018 for the Renewable Assets (Note 12).

In connection with our sale of the Renewable Assets, we have new consolidated and unconsolidated variable interest entities (VIEs) (Note 7).

Midcoast Operating, L.P.

On August 1, 2018, our indirect subsidiary, Enbridge (U.S.) Inc. 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). A loss on disposal of $74 million (US$57 million) was included in Other income/(expense) in the 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 $74 million discussed above. As at September 30, 2018, $75 million (US$58 million) and $306 million (US$237 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 nine months ended September 30, 2018.

7.	VARIABLE INTEREST ENTITIES

In connection with our sale of the Renewable Assets (Note 6), we have new consolidated and unconsolidated VIEs.

CONSOLIDATED VARIABLE INTEREST ENTITY

Enbridge Canadian Renewable LP (ECRLP)

To facilitate the sale on August 1, 2018, 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. We consolidate the VIE because of our indirect controlling financial interest in the VIE.

As at September 30, 2018, the carrying amounts of total assets and liabilities of ECRLP on our Consolidated Statements of Financial Position were $2.1 billion and $45 million, respectively. The creditors of the VIE do not have recourse to our general credit, other than through nominal assets of the holding company with the general partnership interest. We did not provide any additional financial support to ECRLP during the nine months ended September 30, 2018.

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UNCONSOLIDATED VARIABLE INTEREST ENTITY

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

To facilitate the sale on August 1, 2018, we transferred our interest in the Hohe See Offshore wind farm and its subsequent expansion to a newly formed partnership, 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 impact 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.

ERII has a carrying value of $118 million (€79 million) at September 30, 2018, within Long-term investments in our Consolidated Statements of Financial Position. Included within Deferred amounts and other assets in our Consolidated Statements of Financial Position at September 30, 2018, is a long-term receivable of $416 million (€277 million) relating to our loan to a consolidated subsidiary of ERII. The maximum exposure to loss as a result of our involvement with ERII is $534 million (€356 million), which is equal to the long-term investment carrying value plus the outstanding receivable discussed above.

OTHER

Sabal Trail Transmission, LLC

Spectra Energy Partners, LP (SEP) owns a 50% interest in Sabal Trail Transmission, LLC (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 4.246% senior notes due in 2028, US$600 million in aggregate principal amount of 4.682% senior notes due in 2038 and US$400 million in aggregate principal amount of 4.832% 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 Statement of Cash Flows for the nine months ended September 30, 2018. These events triggered reconsideration and as a result, it was concluded that Sabal Trail was no longer a VIE as at June 30, 2018 due to sufficient equity at risk to finance its activities.

8.	DEBT

CREDIT FACILITIES

The following table provides details of our committed credit facilities as at September 30, 2018:

 

 

		September 30, 2018
	Maturity	Total Facilities		Draws1		Available
(millions of Canadian dollars)
Enbridge Inc.	2019-2023	5,602		2,330		3,272
Enbridge (U.S.) Inc.	2019	1,829		—		1,829
Enbridge Energy Partners, L.P.2	2019-2022	3,167		2,210		957
Enbridge Gas Distribution Inc. (EGD)	2019-2020	1,017		779		238
Enbridge Income Fund	2020	1,500		9		1,491
Enbridge Pipelines Inc.	2020	3,000		1,214		1,786
Spectra Energy Partners, LP3	2022	3,232		2,153		1,079
Union Gas Limited (Union Gas)	2021	700		481		219
Total committed credit facilities		20,047		9,176		10,871

 

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

2	Includes $239 million (US$185 million) of commitments that expire in 2020.

3	Includes $435 million (US$336 million) of commitments that expire in 2021.

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During the second quarter of 2018, Enbridge (U.S.) Inc. terminated a US$500 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.

During the first quarter of 2018, Enbridge terminated a US$650 million credit facility, which was scheduled to mature in 2019, and repaid drawn amounts. In addition, Enbridge (U.S.) Inc. terminated an unutilized US$950 million credit facility, which was scheduled to mature in 2019.

During the first quarter of 2018, Westcoast Energy Inc. terminated an unutilized $400 million credit facility with a syndicate of banks. The facility was acquired in conjunction with the Merger Transaction and was scheduled to mature in 2021.

In addition to the committed credit facilities noted above, we maintain $790 million of uncommitted demand credit facilities, of which $564 million were unutilized as at September 30, 2018. As at December 31, 2017, we had $792 million of uncommitted credit facilities, of which $518 million were unutilized.

Our 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 scheduled to mature from 2019 to 2023.

As at September 30, 2018 and December 31, 2017, commercial paper and credit facility draws, net of short-term borrowings and non-revolving credit facilities that mature within one year of $7,534 million and $10,055 million, respectively, were supported by the availability of long-term committed credit facilities and therefore have been classified as long-term debt.

LONG-TERM DEBT ISSUANCES

During the nine months ended September 30, 2018, we completed the following long-term debt issuances:

Company	Issue Date			Principal Amount
(millions of Canadian dollars, unless otherwise stated)
Enbridge Inc.
	March 2018	Fixed-to-floating rate subordinated notes due 20781		US$850
	April 2018	Fixed-to-floating rate subordinated notes due 20782		$750
	April 2018	Fixed-to-floating rate subordinated notes due 20783		US$600
Spectra Energy Partners, LP4
	January 2018	3.50% senior notes due 2028		US$400
	January 2018	4.15% senior notes due 2048		US$400

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 London Interbank Offered Rate (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	Issued through Texas Eastern Transmission, LP, a wholly-owned operating subsidiary of SEP.

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LONG-TERM DEBT REPAYMENTS

During the nine months ended September 30, 2018, we completed the following long-term debt repayments:

Company	Retirement/Repayment Date			Principal Amount	Cash Consideration1
(millions of Canadian dollars, unless otherwise stated)
Enbridge Energy Partners, L.P.
	April 2018	6.50% senior notes		US$400
Enbridge Pipelines (Southern Lights) L.L.C
	June 2018	3.98% medium-term notes due June 2040		US$20
Enbridge Southern Lights LP
	January 2018	4.01% medium-term notes due June 2040		$9
	July 2018	4.01% medium-term notes due June 2040		$8
Midcoast Energy Partners, L.P.
Redemption2
	July 2018	3.56% senior notes due September 2019		US$75	US$76
	July 2018	4.04% senior notes due September 2021		US$175	US$182
	July 2018	4.42% senior notes due September 2024		US$150	US$161
Spectra Energy Capital, LLC
Repurchase via Tender Offer2
	March 2018	6.75% senior unsecured notes due 2032		US$64	US$80
	March 2018	7.50% senior unsecured notes due 2038		US$43	US$59
Redemption2
	March 2018	5.65% senior unsecured notes due 2020		US$163	US$172
	March 2018	3.30% senior unsecured notes due 2023		US$498	US$508
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
Union Gas Limited
	April 2018	5.35% medium-term notes		$200
	August 2018	8.75% debenture		$125
Westcoast Energy Inc.
	May 2018	6.90% senior secured notes		$13
	May 2018	4.34% senior secured notes		$4
	September 2018	8.50% debenture		$150

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 a fair value adjustment recorded upon completion of the Merger Transaction, was reported within Interest expense in the Consolidated Statements of Earnings.

SUBORDINATED TERM NOTES

As at September 30, 2018 and December 31, 2017, our fixed-to-floating subordinated term notes had a principal value of $7,053 million and $4,344 million, respectively.

FAIR VALUE ADJUSTMENT

As at September 30, 2018, the net fair value adjustment for total debt assumed in the Merger Transaction was $975 million. During the three and nine months ended September 30, 2018, the amortization of the fair value adjustment, recorded as a reduction to Interest expense in the Consolidated Statements of Earnings, was $23 million and $112 million, respectively.

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 September 30, 2018, we were in compliance with all debt covenants.

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9.	COMPONENTS OF ACCUMULATED OTHER COMPREHENSIVE INCOME

 

Changes in AOCI attributable to our common shareholders for the nine months ended September 30, 2018 and 2017 are as follows:

	Cash Flow  Hedges		Net Investment Hedges		Cumulative Translation Adjustment		Equity Investees		Pension and OPEB Adjustment		Total
(millions of Canadian dollars)
Balance as at January 1, 2018	(644	)	(139	)	77		10		(277	)	(973	)
Other comprehensive income/(loss) retained in AOCI	167		(232	)	1,495		(8	)	—		1,422
Other comprehensive (income)/loss reclassified to earnings
Interest rate contracts1	92		—		—		—		—		92
Commodity contracts2	(1	)	—		—		—		—		(1	)
Foreign exchange contracts3	6		—		—		—		—		6
Other contracts4	10		—		—		—		—		10
Amortization of pension and OPEB actuarial loss and prior service costs5	—		—		—		—		36		36
	274		(232	)	1,495		(8	)	36		1,565
Tax impact
Income tax on amounts retained in AOCI	(26	)	32		—		9		—		15
Income tax on amounts reclassified to earnings	(29	)	—		—		—		(8	)	(37	)
	(55	)	32		—		9		(8	)	(22	)
Balance as at September 30, 2018	(425	)	(339	)	1,572		11		(249	)	570

	Cash Flow Hedges		Net Investment Hedges		Cumulative Translation Adjustment		Equity Investees		Pension and OPEB Adjustment		Total
(millions of Canadian dollars)
Balance as at January 1, 2017	(746	)	(629	)	2,700		37		(304	)	1,058
Other comprehensive income/(loss) retained in AOCI	29		496		(2,616	)	(4	)	—		(2,095	)
Other comprehensive (income)/loss reclassified to earnings
Interest rate contracts1	104		—		—		—		—		104
Commodity contracts2	(5	)	—		—		—		—		(5	)
Foreign exchange contracts3	(2	)	—		—		—		—		(2	)
Other contracts4	(3	)	—		—		—		—		(3	)
Amortization of pension and OPEB actuarial loss and prior service costs5	—		—		—		—		21		21
	123		496		(2,616	)	(4	)	21		(1,980	)
Tax impact
Income tax on amounts retained in AOCI	(9	)	9		—		13		—		13
Income tax on amounts reclassified to earnings	(34	)	—		—		—		(8	)	(42	)
	(43	)	9		—		13		(8	)	(29	)
Balance as at September 30, 2017	(666	)	(124	)	84		46		(291	)	(951	)

 

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

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

3	Reported within Other income/(expense) in the Consolidated Statements of Earnings.

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

5	These components are included in the computation of net periodic benefit costs and are reported within Other income/(expense) in the Consolidated Statements of Earnings.

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10. NONCONTROLLING INTERESTS

 

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 6). 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, for the nine months ended September 30, 2018. For the three months ended September 30, 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. We now hold a non-economic general partner interest in SEP and own 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, for the nine months ended September 30, 2018.

11. RISK MANAGEMENT AND FINANCIAL INSTRUMENTS

MARKET RISKS

Our earnings, cash flows and other comprehensive income (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 are 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 2.6%.

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As a result of the Merger Transaction, 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 to hedge against future changes to the fair value of fixed rate debt. We have assumed a program within our subsidiaries to mitigate the impact of fluctuations in the fair value of fixed rate debt via execution of fixed to floating interest rate swaps with an average swap rate of 2.2%.

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 assumed 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 3.1%.

We also monitor our debt portfolio mix of fixed and variable rate debt instruments to manage a consolidated portfolio of floating rate debt as a percentage of total debt outstanding. We primarily use qualifying derivative instruments to manage interest rate risk.

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.

Emission Allowance Price Risk

Emission allowance price risk is the risk of gain or loss due to changes in the market price of emission allowances that our gas distribution business has been required to purchase for itself and most of its customers to meet greenhouse gas compliance obligations under the Ontario Cap and Trade program. Similar to the gas supply procurement framework, the Ontario Energy Board's (OEB) framework for emission allowance procurement allows recovery of fluctuations in emission allowance prices in customer rates, subject to OEB approval.

 

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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September 30, 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	—		1		—		66		67		(49	)	18
Interest rate contracts	49		—		—		—		49		(3	)	46
Commodity contracts	1		—		—		119		120		(85	)	35
	50		1		—		185		236		(137	)	99
Deferred amounts and other assets
Foreign exchange contracts	4		—		—		39		43		(29	)	14
Interest rate contracts	42		—		—		—		42		(1	)	41
Commodity contracts	18		—		—		12		30		(25	)	5
Other contracts	—		—		—		—		—		—		—
	64		—		—		51		115		(55	)	60
Accounts payable and other
Foreign exchange contracts	(5	)	—		—		(371	)	(376	)	49		(327	)
Interest rate contracts	(50	)	—		(9	)	(179	)	(238	)	3		(235	)
Commodity contracts	—		—		—		(411	)	(411	)	85		(326	)
Other contracts	(1	)	—		—		(8	)	(9	)	—		(9	)
	(56	)	—		(9	)	(969	)	(1,034	)	137		(897	)
Other long-term liabilities
Foreign exchange contracts	—		(11	)	—		(1,420	)	(1,431	)	29		(1,402	)
Interest rate contracts	(6	)	—		(3	)	—		(9	)	1		(8	)
Commodity contracts	—		—		—		(153	)	(153	)	25		(128	)
Other contracts	(3	)	—		—		(4	)	(7	)	—		(7	)
	(9	)	(11	)	(3	)	(1,577	)	(1,600	)	55		(1,545	)
Total net derivative asset/(liability)
Foreign exchange contracts	(1	)	(10	)	—		(1,686	)	(1,697	)	—		(1,697	)
Interest rate contracts	35		—		(12	)	(179	)	(156	)	—		(156	)
Commodity contracts	19		—		—		(433	)	(414	)	—		(414	)
Other contracts	(4	)	—		—		(12	)	(16	)	—		(16	)
	49		(10	)	(12	)	(2,310	)	(2,283	)	—		(2,283	)

 

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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					2
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)					-2
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.

September 30, 2018	2018		2019		2020		2021		2022		Thereafter1
Foreign exchange contracts - United States dollar forwards - purchase (millions of United States dollars)	591		3		1		—		—		—
Foreign exchange contracts - United States dollar forwards - sell (millions of United States dollars)	1,592		3,262		3,258		1,689		1,676		3,489
Foreign exchange contracts - British pound (GBP) forwards - sell (millions of GBP)	—		89		25		27		28		149
Foreign exchange contracts - Euro forwards - purchase (millions of Euro)	42		208		—		—		—		—
Foreign exchange contracts - Euro forwards - sell (millions of Euro)	—		—		23		94		94		698
Foreign exchange contracts - Japanese yen forwards - purchase (millions of yen)	—		32,662		—		—		20,000		—
Interest rate contracts - short-term pay fixed rate (millions of Canadian dollars)	1,251		3,590		1,093		121		93		203
Interest rate contracts - long-term receive fixed rate (millions of Canadian dollars)	145		582		555		188		102		—
Interest rate contracts - long-term debt pay fixed rate (millions of Canadian dollars)	1,894		600		573		—		—		—
Equity contracts (millions of Canadian dollars)	40		35		20		—		—		—
Commodity contracts - natural gas (billions of cubic feet)	(7	)	(58	)	(18	)	(5	)	8		1
Commodity contracts - crude oil (millions of barrels)	4		4		—		—		—		—
Commodity contracts - NGL (millions of barrels)	(1	)	—		—		—		—		—
Commodity contracts - power (megawatt per hour) (MW/H))	57		64		66		(3	)	(43	)	(43	)

1 As at September 30, 2018, 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:

	Three months ended September 30,					Nine months ended September 30,
	2018		2017			2018		2017
(millions of Canadian dollars)
Amount of unrealized gain/(loss) recognized in OCI
Cash flow hedges
Foreign exchange contracts	(16	)	(2	)		2		(1	)
Interest rate contracts	69		83			186		28
Commodity contracts	4		—			1		12
Other contracts	(10	)	16			(12	)	1
Net investment hedges
Foreign exchange contracts	25		148			36		221
	72		245			213		261
Amount of (gain)/loss reclassified from AOCI to earnings (effective portion)
Foreign exchange contracts1	7		(3	)		4		(104	)
Interest rate contracts2	40		50			124		134
Commodity contracts3	—		—			(1	)	(4	)
Other contracts4	7		(11	)		10		2
	54		36			137		28
Amount of (gain)/loss reclassified from AOCI to earnings (ineffective portion and amount excluded from effectiveness testing)
Interest rate contracts2	(2	)	(1	)		8		5
	(2	)	(1	)		8		5

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

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

We estimate that a loss of $1 million of AOCI related to cash flow hedges will be reclassified to earnings in the next 12 months. Actual amounts reclassified to earnings depend on the foreign exchange rates, interest rates and commodity prices in effect when derivative contracts that are currently outstanding mature. For all forecasted transactions, the maximum term over which we are hedging exposures to the variability of cash flows is 27 months as at September 30, 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. The difference in the amounts, if any, represents hedge ineffectiveness.

	Three months ended September 30,					Nine months ended September 30,
	2018		2017			2018		2017
(millions of Canadian dollars)
Unrealized gain/(loss) on derivative	3		—			(9	)	(1	)
Unrealized gain/(loss) on hedged item	(3	)	1			8		2
Realized gain/(loss) on derivative	(3	)	2			(4	)	2
Realized gain/(loss) on hedged item	3		(2	)		4		(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:

	Three months ended September 30,					Nine months ended September 30,
	2018		2017			2018		2017
(millions of Canadian dollars)
Foreign exchange contracts1	345		503			(356	)	1,210
Interest rate contracts2	6		(1	)		4		13
Commodity contracts3	(113	)	(160	)		43		22
Other contracts4	(8	)	3			(10	)	(2	)
Total unrealized derivative fair value gain/(loss), net	230		345			(319	)	1,243

1	For the respective nine months ended periods, reported within Transportation and other services revenues (2018 - $346 million loss; 2017 - $726 million gain) and Other income/(expense) (2018 - $10 million loss; 2017 - $484 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 nine months ended periods, reported within Transportation and other services revenues (2018 - $16 million loss; 2017 - $85 million loss), Commodity sales (2018 - $42 million loss; 2017 - $67 million gain), Commodity costs (2018 - $90 million gain; 2017 - $22 million gain) and Operating and administrative expense (2018 - $11 million gain; 2017 - $18 million gain) 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 September 30, 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 investment grade credit ratings. Credit risk relating to derivative counterparties is mitigated by credit exposure limits and contractual requirements, netting arrangements, and ongoing monitoring of counterparty credit exposure using external credit rating services and other analytical tools.

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We have credit concentrations and credit exposure, with respect to derivative instruments, in the following counterparty segments:

	September 30, 2018		December 31, 2017
(millions of Canadian dollars)
Canadian financial institutions	28		82
United States financial institutions	44		19
European financial institutions	79		145
Asian financial institutions	31		2
Other1	86		137
	268		385

 

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

 

As at September 30, 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 September 30, 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.

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Level 2

Level 2 includes derivative valuations determined using directly or indirectly observable inputs other than quoted prices included within Level 1. Derivatives in this category are valued using models or other industry standard valuation techniques derived from observable market data. Such valuation techniques include inputs such as quoted forward prices, time value, volatility factors and broker quotes that can be observed or corroborated in the market for the entire duration of the derivative. Derivatives valued using Level 2 inputs include non-exchange traded derivatives such as over-the-counter foreign exchange forward and cross currency swap contracts, interest rate swaps, physical forward commodity contracts, as well as commodity swaps and options for which observable inputs can be obtained.

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:

September 30, 2018	Level 1		Level 2		Level 3		Total Gross Derivative Instruments
(millions of Canadian dollars)
Financial assets
Current derivative assets
Foreign exchange contracts	—		67		—		67
Interest rate contracts	—		49		—		49
Commodity contracts	1		9		110		120
	1		125		110		236
Long-term derivative assets
Foreign exchange contracts	—		43		—		43
Interest rate contracts	—		42		—		42
Commodity contracts	—		5		25		30
Other contracts	—		—		—		—
	—		90		25		115
Financial liabilities
Current derivative liabilities
Foreign exchange contracts	—		(376	)	—		(376	)
Interest rate contracts	—		(238	)	—		(238	)
Commodity contracts	(11	)	(37	)	(363	)	(411	)
Other contracts	—		(9	)	—		(9	)
	(11	)	(660	)	(363	)	(1,034	)
Long-term derivative liabilities
Foreign exchange contracts	—		(1,431	)	—		(1,431	)
Interest rate contracts	—		(9	)	—		(9	)
Commodity contracts	—		(11	)	(142	)	(153	)
Other contracts	—		(7	)	—		(7	)
	—		(1,458	)	(142	)	(1,600	)
Total net financial liabilities
Foreign exchange contracts	—		(1,697	)	—		(1,697	)
Interest rate contracts	—		(156	)	—		(156	)
Commodity contracts	(10	)	(34	)	(370	)	(414	)
Other contracts	—		(16	)	—		(16	)
	(10	)	(1,903	)	(370	)	(2,283	)

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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 liabilities
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	)

 

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

September 30, 2018	Fair Value		Unobservable Input	Minimum Price		Maximum Price		Weighted Average Price		Unit of Measurement
(fair value in millions of Canadian dollars)
Commodity contracts - financial1
Natural gas	(6	)	Forward gas price	2.34		4.93		3.36		$/mmbtu2
Crude	(38	)	Forward crude price	51.62		178.33		76.45		$/barrel
NGL	(2	)	Forward NGL price	1.39		1.67		1.58		$/gallon
Power	(93	)	Forward power price	26.01		72.42		47.74		$/MW/H
Commodity contracts - physical1
Natural gas	(83	)	Forward gas price	1.08		6.24		2.75		$/mmbtu2
Crude	(141	)	Forward crude price	29.79		123.22		81.29		$/barrel
NGL	(7	)	Forward NGL price	0.71		2.16		1.13		$/gallon
	(370	)

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 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:

	Nine months ended September 30,
	2018		2017
(millions of Canadian dollars)
Level 3 net derivative liability at beginning of period	(387	)	(295	)
Total gain/(loss)
Included in earnings1	(146	)	1
Included in OCI	—		11
Settlements	163		83
Level 3 net derivative liability at end of period	(370	)	(200	)

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 September 30, 2018 or 2017.

 

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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 other long-term investments totaled $100 million and $99 million as at September 30, 2018 and December 31, 2017, respectively.

 

We have Restricted long-term investments held in trust totaling $307 million and $267 million as at September 30, 2018 and December 31, 2017, respectively, which are recognized at fair value.

 

We have a held to maturity preferred share investment carried at its amortized cost of $370 million and $371 million as at September 30, 2018 and December 31, 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 4.50%. As at September 30, 2018 and December 31, 2017, the fair value of this preferred share investment approximates its face value of $580 million.

 

As at September 30, 2018 and December 31, 2017, our long-term debt had a carrying value of $62.5 billion and $64.0 billion, respectively, before debt issuance costs and a fair value of $63.8 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 September 30, 2018 and December 31, 2017, the noncurrent notes receivable has a carrying value of $92 million and $89 million, respectively, and a fair value of $92 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.

 

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 nine months ended September 30, 2018 and 2017, we recognized an unrealized foreign exchange loss of $209 million and a gain of $350 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 $36 million and $222 million, respectively, in OCI. During the nine months ended September 30, 2018 and 2017, we recognized realized losses of $46 million and $128 million, respectively, in OCI associated with the settlement of foreign exchange forward contracts and recognized a realized loss of $13 million and a realized gain of $52 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 nine months ended September 30, 2018 and 2017.

12. INCOME TAXES

The effective income tax rates for the three months ended September 30, 2018 and 2017 were an expense of 62.0% and 24.4%, respectively, and for the nine months ended September 30, 2018 and 2017 were an expense of 7.9% and 20.4%, respectively. The period-over-period change in the effective income tax rate is due to the effects of rate-regulated accounting for income taxes, the goodwill impairment recorded in the third quarter of 2018, and other permanent items relative to the decrease in earnings for the three and nine months ended September 30, 2018, the impact of the United States federal corporate income tax rate reduction enacted in 2017, and a recovery in the second quarter of 2018 related to a change in assertion for the investment in Canadian renewable assets due to the sale which resulted in the recognition of previously unrecognized tax basis. Refer to Note 6. Acquisitions and Dispositions - Dispositions - Renewable Assets for further discussion of the transaction.

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On December 22, 2017, the United States enacted the TCJA and we made reasonable estimates for the measurement and accounting of certain effects of the TCJA in our consolidated financial statements for the year ended December 31, 2017. We recorded a nil provision for the three and nine months ended September 30, 2018, based on existing guidance and legislation, for the remaining effects of the TCJA including the Global Intangible Low Taxed Income tax and the Base Erosion and Anti-abuse Tax.

13. PENSION AND OTHER POSTRETIREMENT BENEFITS

	Three months ended September 30,					Nine months ended September 30,
	2018		2017			2018		2017
(millions of Canadian dollars)
Service cost	46		65			162		181
Interest cost	39		46			126		125
Expected return on plan assets	(72	)	(71	)		(234	)	(195	)
Amortization of actuarial loss	6		11			21		28
Plan curtailments	—		—			2		—
Amortization of prior service costs	—		(1	)		(1	)	(1	)
Net periodic benefit costs	19		50			76		138

14. CONTINGENCIES

 

We are involved in 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 interim consolidated financial position or results of operations.

TAX MATTERS

We 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.

SIMPLIFICATION OF CORPORATE STRUCTURE

During the third quarter of 2018, we entered into definitive agreements with SEP, EEP, EEM and Enbridge Income Fund Holdings Inc. (ENF) under which we will acquire all of the outstanding public securities of the respective sponsored vehicles. The security holders of SEP, EEP, EEM and ENF will be entitled to receive 1.111, 0.335, 0.335 and 0.735 of our common shares for each of their own outstanding public securities, respectively. In addition, ENF shareholders will also receive cash payment of no less than $0.45 for each outstanding public common share of ENF, which amounts to approximately $63 million in the minimum. Closing of the transactions is subject to security holder approvals, customary closing conditions and other conditions, as applicable to the specific sponsored vehicle.

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15. SUBSEQUENT EVENTS

On October 1, 2018, we closed the sale of the provincially regulated facilities of our Canadian natural gas gathering and processing businesses for proceeds of approximately $2.5 billion. Refer to Note 6. Acquisitions and Dispositions for further discussion of the transaction.

The BC Pipeline T-South System moves natural gas into the Pacific Northwest region and is comprised of two pipelines that run parallel to each other. On October 9, 2018, a rupture occurred on one of the natural gas transmission pipelines within this system and ignited at the site. Both pipelines were shut down following the rupture. Following various assessments and National Energy Board approval, both of the pipelines were returned to service at a lower operating pressure. We are cooperating and working with the Transportation Safety Board in its investigation to determine the cause of the incident.

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ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

INTRODUCTION

 

The following discussion and analysis of our financial condition and results of operations is based on and should be read in conjunction with our consolidated financial statements and the accompanying notes included in Part 1. Item 1. Financial Statements of this report and in conjunction with the audited consolidated financial statements and accompanying footnotes in our Annual Report on Form 10-K for the year ended December 31, 2017, as filed with the Securities and Exchange Commission on February 16, 2018.

SIMPLIFICATION OF CORPORATE STRUCTURE

On May 17, 2018, we announced four separate non-binding all-share proposals to the respective boards of directors of our sponsored vehicles, Spectra Energy Partners, LP (SEP), Enbridge Energy Partners, L.P. (EEP), Enbridge Energy Management, L.L.C. (EEQ) and Enbridge Income Fund Holdings Inc. (ENF), to acquire, in separate combination transactions, all of the outstanding equity securities of those sponsored vehicles not beneficially owned by us.

On August 24, 2018, we announced that we entered into a definitive agreement with SEP under which we will acquire all of the outstanding public common units of SEP on the basis of 1.111 of our common shares for each common unit of SEP. The transaction is valued at US$3.3 billion based on the closing price of our common shares on the New York Stock Exchange on August 23, 2018. Closing of the transaction is targeted to occur in the fourth quarter of 2018, subject to customary closing conditions.

On September 18, 2018, we announced that we entered into definitive agreements with each of EEP and EEQ under which we will acquire all of the outstanding public class A common units of EEP and all of the outstanding public listed shares of EEQ. EEP public unitholders will receive 0.335 of our common shares for each class A common unit of EEP, and EEQ public shareholders will receive 0.335 of our common shares for each listed share of EEQ. The transactions are valued at US$3.5 billion based on the closing price of our common shares on the New York Stock Exchange on September 17, 2018. Closing of the transactions is targeted to occur in the fourth quarter of 2018, subject to securing the respective EEP unitholder and EEQ shareholder approvals and other customary closing conditions. In addition, the closing of the EEQ transaction is conditioned on the EEP buy-in transaction, but the closing of the EEP transaction is not conditioned on the EEQ transaction.

On September 18, 2018, we announced that we entered into a definitive agreement with ENF under which we will acquire all of the issued and outstanding public common shares of ENF on the basis of 0.735 of our common shares and cash of no less than $0.45 for each common share of ENF. The transaction is valued at $4.7 billion based on the closing price of our common shares on the Toronto Stock Exchange on September 17, 2018. Closing of the transaction is targeted to occur in the fourth quarter of 2018, subject to ENF shareholder approval, the approval of the Court of Queen's Bench of Alberta and other customary closing conditions.

The transactions, as proposed, are not expected to have a material impact on our results of operations or cash flows over the 2018 to 2020 horizon.

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ASSET MONETIZATION

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 farm 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 project. We will maintain a 51% interest in the Renewable Assets and will continue to manage, operate and provide administrative services for these assets.

Midcoast Operating, L.P.

On August 1, 2018, our indirect subsidiary, Enbridge (U.S.) Inc. 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).

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 for a cash purchase price of approximately $4.3 billion to Brookfield Infrastructure Partners L.P. and its institutional partners. Separate agreements were entered into for those facilities currently governed by provincial regulations and those governed by federal regulations. On October 1, 2018, we closed the sale of the provincially regulated facilities for proceeds of approximately $2.5 billion. The sale of the federally regulated facilities is expected to close in mid-2019 for proceeds of approximately $1.8 billion.

Refer to Liquidity and Capital Resources - Sources and Uses of Cash for details on the use of proceeds from our asset monetization activity discussed above.

BRITISH COLUMBIA PIPELINE RUPTURE

The BC Pipeline T-South system (BC Pipeline System) moves natural gas into the Pacific Northwest region and is comprised of two pipelines, a 36-inch and a 30-inch, that run parallel to each other. On October 9, 2018, a rupture occurred on the 36-inch natural gas transmission pipeline. The rupture ignited at the site, which is in a rural area. There were no injuries as a result of the incident.

Both pipelines were shut down following the rupture on the 36-inch line. The 30-inch line, which runs parallel to the impacted line, was safely returned to service and has been running at a reduced operating pressure since October 11, 2018 following various assessments and National Energy Board (NEB) approval. After replacing the impacted segment, the 36-inch line has now been returned to service at a lower operating pressure. We are cooperating and working with the Transportation Safety Board in its investigation to determine the cause of the rupture on the 36-inch line.

The total costs associated with the incident, before expected recoveries, are still being determined. We are included in a comprehensive insurance program that is maintained for our subsidiaries and affiliates, which includes liability, property and business interruption insurance. Additionally, tolls on the BC Pipeline System are calculated in accordance with a NEB-approved settlement. We do not believe this incident will result in a material impact to us over time.

ONTARIO ENERGY BOARD DECISION ON AMALGAMATION

On August 30, 2018, we received a decision from the Ontario Energy Board (OEB) approving the amalgamation of Enbridge Gas Distribution (EGD) and Union Gas Limited (Union Gas). On October 15,

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2018, we announced that we will proceed with the amalgamation of EGD and Union Gas, with an expected effective date of January 1, 2019.

MINNESOTA PUBLIC UTILITIES COMMISSION APPROVAL OF U.S. LINE 3 REPLACEMENT PROGRAM

On June 28, 2018, the Minnesota Public Utilities Commission (MNPUC) approved the issuance of a Certificate of Need (Certificate) and pipeline route (Route Permit) for construction of the United States Line 3 Replacement Program (U.S. L3R Program) in Minnesota. The Route Permit adopted our preferred route, with minor modifications and subject to certain conditions. For further details refer to Growth Projects - Regulatory Matters - United States Line 3 Replacement Program (EEP).

REVISED FERC POLICY ON TREATMENT OF INCOME TAXES

On March 15, 2018, the Federal Energy Regulatory Commission (FERC) revised a long standing policy announcing that it would no longer permit entities organized as Master Limited Partnerships (MLPs) to recover an income tax allowance for interstate pipeline assets with cost-of-service rates. The announcement of the Revised Policy Statement was accompanied by: (i) a Notice of Proposed Rulemaking proposing interstate natural gas pipelines file a one-time report to quantify the impact of the federal income tax rate reduction and the impact of the revised Policy Statement on each pipeline; and (ii) a Notice of Inquiry seeking comment on how FERC should address changes related to accumulated deferred income taxes and bonus depreciation.

We hold our United States liquids and natural gas pipelines through a number of different ownership structures, including MLPs. SEP and EEP responded to the FERC announcement regarding tax allowance, both directly and through industry associations, objecting to the change in FERC policy and requesting a re-hearing. On April 27, 2018, the FERC issued a tolling order for the purpose of affording it additional time for consideration of matters raised on re-hearing. These FERC announcements have adversely affected MLPs generally.

On July 18, 2018, the FERC issued an Order that: (1) dismissed all requests for rehearing of its March 15, 2018 revised policy statement and explained that its revised policy statement does not establish a binding rule, but is instead an expression of general policy that the Commission intends to follow in the future; and (2) provides guidance that if an MLP or other tax pass-through pipeline eliminates its income tax allowance from its cost of service pursuant to FERC’s Revised Policy Statement, then Accumulated Deferred Income Taxes (ADIT) will similarly be removed from its cost of service and MLP pipelines may also eliminate previously-accumulated sums in ADIT. As a statement of general policy, the FERC will consider alternative application of its tax allowance and ADIT policy on a case-by-case basis.

There are many uncertainties with regards to the implementation of the recent FERC actions, including the potential for different outcomes as the result of a rate case or customer challenges. While there will be varying impacts to each of our sponsored vehicles, on a consolidated basis we do not expect a material impact to our results of operations or cash flows over the 2018 to 2020 horizon. Under the International Joint Tariff (IJT) mechanism on the mainline system, anticipated reductions in the EEP tariff arising from the FERC order would create an offsetting revenue increase on the Canadian mainline system owned by the Fund Group (comprising Enbridge Income Fund, Enbridge Commercial Trust, Enbridge Income Partners LP (EIPLP) and the subsidiaries of EIPLP). At SEP, if implemented as announced, and ultimately supported through a rate case, the ability to eliminate ADIT from cost of service would likely offset the elimination of an income tax allowance in cost of service rates.

UNITED STATES TAX REFORM UPDATE

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On December 22, 2017, the United States enacted the Tax Cuts and Jobs Act (TCJA or United States Tax Reform). 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 the 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. This resulted in a reduction of the US$860 million overall regulatory liability at SEP by US$25 million.

We also recorded no provision for the three and nine months ended September 30, 2018, based on existing guidance and legislation, for the Global Intangible Low Taxed Income tax and the Base Erosion and Anti-abuse Tax.

SEP INCENTIVE DISTRIBUTION RIGHTS

On January 22, 2018, Enbridge and SEP announced the execution of a definitive agreement, resulting in us converting all of our incentive distribution rights (IDRs) and general partner economic interests in SEP into 172.5 million newly issued SEP common units. As part of the transaction, all of SEP's IDRs have been eliminated.

RESULTS OF OPERATIONS

 

	Three months ended September 30,					Nine months ended September 30,
	2018		2017			2018		2017
(millions of Canadian dollars, except per share amounts)
Segment earnings/(loss) before interest, income taxes and depreciation and amortization
Liquids Pipelines	1,875		1,703			4,353		4,840
Gas Transmission and Midstream	(60	)	856			1,080		2,263
Gas Distribution	256		240			1,262		937
Green Power and Transmission	51		68			286		270
Energy Services	(96	)	(150	)		108		(11	)
Eliminations and Other	29		126			(368	)	(188	)
Depreciation and amortization	(799	)	(848	)		(2,452	)	(2,388	)
Interest expense	(696	)	(653	)		(2,042	)	(1,704	)
Income tax expense	(347	)	(327	)		(177	)	(818	)
Earnings attributable to noncontrolling interests and redeemable noncontrolling interests	(209	)	(168	)		(352	)	(633	)
Preference share dividends	(94	)	(82	)		(272	)	(246	)
Earnings/(loss) attributable to common shareholders	(90	)	765			1,426		2,322
Earnings/(loss) per common share	(0.05	)	0.47			0.84		1.57
Diluted earnings/(loss) per common share	(0.05	)	0.47			0.84		1.56

 

EARNINGS ATTRIBUTABLE TO COMMON SHAREHOLDERS

Three months ended September 30, 2018, compared with the three months ended September 30, 2017

Earnings Attributable to Common Shareholders were negatively impacted by $1,156 million due to certain unusual, infrequent or other factors, primarily explained by the following:

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•	a goodwill impairment charge of $1,019 million after-tax attributable to us in 2018 resulting from the classification of our Canadian natural gas gathering and processing businesses as held for sale, refer to Part 1. Item 1. Financial Statements - Note 6. Acquisitions and Dispositions - Assets Held for Sale;

•

a non-cash, unrealized derivative fair value gain of $257 million ($145 million after-tax attributable to us) in 2018, compared with a gain of $362 million ($212 million after-tax attributable to us) in the corresponding 2017 period, reflecting net fair value gains and losses arising from changes in the mark-to-market value of derivative financial instruments used to manage foreign exchange and commodity prices risks;

•	a loss of $74 million in 2018 ($117 million after-tax attributable to us) resulting from the sale of MOLP, refer to Part 1. Item 1. Financial Statements - Note 6. Acquisitions and Dispositions - Dispositions; and

•	asset monetization transaction costs of $45 million ($49 million after-tax attributable to us) recorded in 2018 attributable to divestiture activity in the quarter, refer to Asset Monetization; partially offset by

•	employee severance, transition and transformation costs of $17 million ($14 million after-tax attributable to us) in 2018, compared with $76 million ($72 million after-tax attributable to us) in the corresponding 2017 period.

The non-cash, unrealized derivative fair value gains and losses discussed above, generally arise as a result of a comprehensive long-term economic hedging program to mitigate interest rate, foreign exchange and commodity price risks. This program creates volatility in reported short-term earnings through the recognition of unrealized non-cash gains and losses on financial derivative instruments used to hedge these risks. Over the long-term, we believe our hedging program supports the reliable cash flows and dividend growth upon which our investor value proposition is based.

After taking into consideration the factors above, the remaining $301 million increase in Earnings Attributable to Common Shareholders is primarily explained by the following significant business factors:

•	stronger contributions from our Liquids Pipelines segment due to a higher realized foreign exchange hedge rate used to lock-in United States dollar denominated Canadian Mainline revenues, a higher IJT Benchmark Toll and higher throughput driven by capacity optimization initiatives implemented in 2017;

•	contributions from new Liquids Pipelines assets placed into service in 2017;

•	contributions from new Gas Transmission and Midstream assets placed into service in 2017 and the first quarter of 2018;

•	increased earnings from our Gas Transmission and Midstream equity investments primarily due to favorable margins, favorable commodity prices and increased volumes;

•	increased earnings from our Gas Distribution segment due to expansion projects and higher distribution charges resulting from increases in rate base and customer base; and

•	increased earnings from our Energy Services segment due to the widening of certain location differentials, which increased opportunities to generate profitable margins.

Lower earnings per common share relative to the third quarter of 2017 are primarily due to the decrease in Earnings Attributable to Common Shareholders resulting from the unusual, infrequent and other factors discussed above, an increase in common shares due to the issuance of approximately 33 million common shares in December 2017 through a private placement offering and ongoing quarterly issuances under our Dividend Reinvestment and Share Purchase Plan (DRIP).

Nine months ended September 30, 2018, compared with the nine months ended September 30, 2017

Earnings Attributable to Common Shareholders for the nine month period ended September 30, 2018 were positively impacted by contributions in the first two months of 2018 of approximately $364 million from assets whose performance was not reflected in Earnings Attributable to Common Shareholders for

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the first two months of 2017 due to the timing of the stock-for-stock merger transaction on February 27, 2017 between Enbridge and Spectra Energy Corp (the Merger Transaction).

After taking into consideration the contribution of additional earnings from the Merger Transaction, Earnings Attributable to Common Shareholders were negatively impacted by $2,329 million due to certain unusual, infrequent or other factors, primarily explained by the following:

•	a goodwill impairment charge of $1,019 million after-tax attributable to us in 2018 resulting from the classification of our Canadian natural gas gathering and processing businesses as held for sale, refer to Part 1. Item 1. Financial Statements - Note 6. Acquisitions and Dispositions - Assets Held for Sale;

•	a loss in 2018 of $913 million ($701 million after-tax attributable to us) on MOLP resulting from a revision to the fair value of the assets held for sale based on the sale price; refer to Part I. Item 1. Financial Statements - Note 6. Acquisitions and Dispositions;

•

a non-cash, unrealized derivative fair value loss of $318 million ($163 million after-tax attributable to us) in 2018, compared with a gain of $1,239 million ($748 million after-tax attributable to us) in the corresponding 2017 period, reflecting net fair value gains and losses arising from changes in the mark-to-market value of derivative financial instruments used to manage foreign exchange and commodity prices risks;

•	a loss of $154 million ($95 million after-tax attributable to us) in 2018 related to the Line 10 crude oil pipeline (Line 10), which is a component of our mainline system, resulting from its classification as an asset held for sale and the subsequent measurement at the lower of carrying value or fair value less costs to sell;

•	the absence in 2018 of a $66 million gain ($8 million after-tax attributable to us) recorded in 2017 on the sale of pipe offset by project wind-down costs related to EEP's Sandpiper Project;

•	asset monetization transaction costs of $65 million ($64 million after-tax attributable to us) recorded in 2018 attributable to divestiture activity in the period, refer to Asset Monetization; and

•	a loss of $74 million in 2018 ($117 million after-tax attributable to us) resulting from the sale of MOLP, refer to Part 1. Item 1. Financial Statements - Note 6. Acquisitions and Dispositions - Dispositions; partially offset by

•	employee severance, transition and transformation costs of $143 million ($137 million after-tax attributable to us) in 2018, compared with $284 million ($201 million after-tax attributable to us) in the corresponding 2017 period;

•	the absence in 2018 of transaction costs of $180 million ($131 million after-tax attributable to us) recorded in 2017 related to the Merger Transaction;

•	a deferred income tax recovery of $267 million ($196 million attributable to us) in 2018 related to a change in assertion for the investment in Canadian renewable assets due to the sale which resulted in the recognition of previously unrecognized tax basis;

•	a gain of $190 million after-tax attributable to us in 2018, compared with a gain of $47 million in the corresponding 2017 period, resulting from the reallocation of income between our interest and the noncontrolling interests in EEP to resolve capital account deficits as required under EEP’s partnership agreement; and

•	a gain of $63 million after-tax attributable to us in 2018 resulting from the impact of United States Tax Reform on our United States Green Power and Transmission assets.

After taking into consideration the factors above, the remaining $1,069 million increase in Earnings Attributable to Common Shareholders is primarily explained by the following significant business factors:

•	stronger contributions from our Liquids Pipelines segment due to a higher foreign exchange hedge rate used to lock-in United States dollar denominated Canadian Mainline revenues, a higher IJT Benchmark Toll and higher throughput driven by capacity optimization initiatives implemented in 2017;

•	contributions from new Liquids Pipelines assets placed into service in 2017;

•	contributions from new Gas Transmission and Midstream assets placed into service in 2017 and the first quarter of 2018;

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•	increased earnings from our Gas Transmission and Midstream equity investments primarily due to favorable margins, favorable commodity prices and increased volumes;

•	increased earnings from our Gas Distribution segment due to colder weather, expansion projects and higher distribution charges resulting from increases in rate base and customer base; and

•	increased earnings from our Energy Services segment due to the widening of certain location differentials, which increased opportunities to generate profitable margins; partially offset by

•	higher interest expense primarily due to long-term debt issuances in 2017 and the first half of 2018 to finance capital expansions.

Lower earnings per common share are primarily due to the decrease in Earnings Attributable to Common Shareholders resulting from the unusual, infrequent and other factors discussed above, the increase in common shares due to the issuance of approximately 33 million common shares in December 2017 in a private placement offering, the issuance of approximately 691 million common shares in February 2017 as part of the consideration for the the stock-for-stock merger transaction on February 27, 2017 as part of the consideration for the Merger Transaction and ongoing quarterly issuances under our DRIP.

BUSINESS SEGMENTS

LIQUIDS PIPELINES

 

	Three months ended September 30,					Nine months ended September 30,
	2018		2017			2018		2017
(millions of Canadian dollars)
Earnings before interest, income taxes and depreciation and amortization	1,875		1,703			4,353		4,840

 

Three months ended September 30, 2018, compared with the three months ended September 30, 2017

EBITDA was negatively impacted by $108 million due to certain unusual, infrequent or other factors, primarily explained by the following:

•	a non-cash, unrealized gain of $211 million in 2018 compared with a $342 million gain in 2017 reflecting net fair value gains and losses arising from changes in the mark-to-market value of derivative financial instruments used to manage foreign exchange and commodity price risks; and

•	the absence in 2018 of a $27 million gain recorded in the third quarter of 2017 on the sale of the Olympic refined products pipeline; partially offset by

•	a gain of $28 million in 2018 compared with a gain of $4 million in 2017 on the sale of pipe related to EEP's Sandpiper Project; and

•	employee severance, transition and transformation costs of $3 million in 2018 compared with $21 million in 2017.

After taking into consideration the factors above, the remaining $280 million increase is primarily explained by the following significant business factors:

•	a higher foreign exchange hedge rate used to lock-in United States dollar denominated Canadian Mainline revenues of $1.26 in 2018 compared with $1.07 in 2017;

•	a higher IJT Benchmark Toll of $4.15 in 2018 compared with $4.07 in 2017;

•	higher Canadian Mainline ex-Gretna throughput of 2,578 thousands of barrels per day (kbpd) in 2018 compared with 2,492 kbpd in 2017 driven by capacity optimization initiatives implemented in 2017;

•	higher Lakehead System throughput of 2,727 kbpd in 2018 compared with 2,620 kbpd in 2017 driven by capacity optimization initiatives implemented in 2017;

•	contributions from the Wood Buffalo Extension Pipeline placed into service in December 2017;

•	higher Bakken Pipeline System throughput period-over-period; and

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•	the net favorable effect of translating United States dollar EBITDA at a higher Canadian to United States dollar average exchange rate (Average Exchange Rate) of $1.31 in 2018 compared with $1.25 in 2017.

Nine months ended September 30, 2018, compared with the nine months ended September 30, 2017

EBITDA for the nine month period ended September 30, 2018 was positively impacted by contributions in the first two months of 2018 of approximately $53 million from assets whose performance was not reflected in EBITDA for the first two months of 2017 due to the timing of the completion of the Merger Transaction.

After taking into consideration the contribution of additional earnings from the Merger Transaction, EBITDA was negatively impacted by $1,374 million due to certain unusual, infrequent or other factors, primarily explained by the following:

•	a non-cash, unrealized loss of $362 million in 2018 compared with a $781 million gain in 2017 reflecting net fair value gains and losses arising from changes in the mark-to-market value of derivative financial instruments used to manage foreign exchange and commodity price risks;

•	a loss of $154 million in 2018 related to Line 10, which is a component of our mainline system, resulting from its classification as an asset held for sale and the subsequent measurement at the lower of carrying value or fair value less costs to sell;

•	a gain of $28 million in 2018 compared with a $66 million gain in 2017 on the sale of pipe offset by project wind-down costs related to EEP's Sandpiper Project; and

•	the absence in 2018 of a $27 million gain recorded in 2017 on the sale of the Olympic refined products pipeline.

After taking into consideration the factors above, the remaining $834 million increase is primarily explained by the following significant business factors:

•	a higher foreign exchange hedge rate used to lock-in United States dollar denominated Canadian Mainline revenues of $1.26 in 2018 compared with $1.05 in 2017;

•	a higher IJT Benchmark Toll of $4.10 in 2018 compared with $4.06 in 2017;

•	higher Canadian Mainline ex-Gretna throughput of 2,613 kbpd in 2018 compared with 2,511 kbpd in 2017 driven by capacity optimization initiatives implemented in 2017;

•	higher Lakehead System throughput of 2,756 kbpd in 2018 compared with 2,657 kbpd in 2017 driven by capacity optimization initiatives implemented in 2017;

•	contributions from assets placed into service during 2017, including the Wood Buffalo Extension Pipeline, the Norlite Pipeline System and the acquisition of a minority interest in the Bakken Pipeline System;

•	higher Bakken Pipeline System and Waupisoo Pipeline throughput period-over-period; and

•	increased transportation revenues resulting from an increase in the level of committed take-or-pay volumes and higher spot volumes on Flanagan South Pipeline driven by strong demand in the United States Gulf Coast; partially offset by

•	the net unfavorable effect of translating United States dollar EBITDA at a lower Average Exchange Rate of $1.29 in 2018 compared with $1.31 in 2017.

GAS TRANSMISSION AND MIDSTREAM

 

	Three months ended September 30,					Nine months ended September 30,
	2018		2017			2018		2017
(millions of Canadian dollars)
Earnings/(loss) before interest, income taxes and depreciation and amortization	(60	)	856			1,080		2,263

 

 

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Three months ended September 30, 2018, compared with the three months ended September 30, 2017

EBITDA was negatively impacted by $1,013 million due to certain unusual, infrequent or other market factors primarily explained by the following:

•	a goodwill impairment charge of $1,019 million in 2018 resulting from the classification of our Canadian natural gas gathering and processing businesses as held for sale, refer to Part 1. Item 1. Financial Statements - Note 6. Acquisitions and Dispositions - Assets Held for Sale;

•	a loss of $74 million in 2018 resulting from the sale of MOLP, refer to Part 1. Item 1. Financial Statements - Note 6. Acquisitions and Dispositions - Dispositions; and

•	asset monetization transaction costs of $20 million recorded in 2018 resulting from the termination of MOLP commodity hedges; partially offset by

•	a non-cash, unrealized gain of $23 million in 2018 compared with a loss of $20 million in 2017 reflecting net fair value gains and losses arising from the change in the mark-to-market value of derivative financial instruments used to manage foreign exchange and commodity price risk;

•	a non-cash, equity earnings adjustment of $4 million in 2018 compared with $25 million in 2017 related to changes in the mark-to-market value of derivative financial instruments at our equity investee, DCP Midstream, LLC; and

•	pipeline inspection and repair costs of $25 million recorded in 2017 primarily due to the Texas Eastern pipeline incident.

After taking into consideration the factors above, the remaining $97 million increase is primarily explained by the following significant business factors:

•	contributions from assets placed into service in 2017 and the first quarter of 2018, including Sabal Trail Transmission, LLC (Sabal Trail), Access South and Adair Southwest;.

•	increased earnings from our Nexus joint venture resulting from higher capitalized costs during construction of the pipeline system;

•	increased fractionation margins at our Aux Sable joint venture driven by higher natural gas liquids (NGL) prices and increased demand;

•	favorable seasonal firm and interruptible revenues from our Alliance joint venture that resulted from wider basis differentials;

•	increased margins on our United States Midstream assets due to favorable commodity prices which resulted in higher volumes; and

•	the net favorable effect of translating United States dollar EBITDA at a higher Average Exchange Rate of $1.31 in 2018 compared with $1.25 in 2017; partially offset by

•	higher operating costs on our United States Transmission and Offshore assets due to higher property taxes, higher repair and maintenance costs, and higher pipeline integrity costs.

Nine months ended September 30, 2018, compared with the nine months ended September 30, 2017

EBITDA for the nine month period ended September 30, 2018 was positively impacted by contributions in the first two months of 2018 of approximately $570 million from assets whose performance was not reflected in EBITDA for the first two months 2017 due to the timing of the completion of the Merger Transaction. When compared to pre-merger results from the prior period, operating results from the new assets include higher earnings primarily from business expansion projects on Algonquin Gas Transmission, Sabal Trail and Texas Eastern Transmission, LP.

After taking into consideration the contribution of additional earnings from the Merger Transaction, EBITDA was negatively impacted by $1,969 million due to certain unusual, infrequent or other market factors primarily explained by the following:

•	a goodwill impairment charge of $1,019 million in 2018 resulting from the classification of our Canadian natural gas gathering and processing businesses as held for sale, refer to Part 1. Item 1. Financial Statements - Note 6. Acquisitions and Dispositions - Assets Held for Sale;

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•	a loss of $913 million on MOLP resulting from a revision to the fair value of the assets held for sale based on the sale price; refer to Part I. Item 1. Financial Statements - Note 6. Acquisitions and Dispositions - Dispositions;

•	a loss of $74 million in 2018 resulting from the sale of MOLP, refer to Part 1. Item 1. Financial Statements - Note 6. Acquisitions and Dispositions - Dispositions; and

•	asset monetization transaction costs of $20 million recorded in 2018 resulting from the termination of MOLP commodity hedges; partially offset by

•	a non-cash, unrealized gain of $25 million in 2018 compared with a gain of $7 million recorded in 2017 reflecting net fair value gains and losses arising from the change in the mark-to-market value of derivative financial instruments used to manage foreign exchange and commodity price risk; and

•	pipeline inspection and repair costs of $34 million recorded in 2017 primarily due to the Texas Eastern pipeline incident.

After taking into consideration the factors above, the remaining $216 million increase is primarily explained by the following significant business factors:

•	contributions from assets placed into service in 2017 and the first quarter of 2018, including the Sabal Trail, Access South, Adair Southwest and Lebanon Extension, High Pine and Wyndwood pipelines;

•	increased earnings from our DCP Midstream LP joint venture driven by favorable commodity prices and increased volumes;

•	increased earnings from our Nexus joint venture resulting from higher capitalized costs during construction of the pipeline system;

•	increased fractionation margins at our Aux Sable joint venture driven by higher NGL prices and increased demand;

•	favorable seasonal firm and interruptible revenues from our Alliance joint venture that resulted from wider basis differentials; and

•	lower operating costs achieved on our Canadian Midstream assets due to decreased turnaround costs; partially offset by

•	higher operating costs on our United States Transmission assets due to higher property taxes, higher repair and maintenance costs, and higher pipeline integrity costs; and

•	the net unfavorable effect of translating United States dollar EBITDA at a lower Average Exchange Rate of $1.29 in 2018 compared with $1.31 in 2017.

GAS DISTRIBUTION

	Three months ended September 30,					Nine months ended September 30,
	2018		2017			2018		2017
(millions of Canadian dollars)
Earnings before interest, income taxes and depreciation and amortization	256		240			1,262		937

 

Three months ended September 30, 2018, compared with the three months ended September 30, 2017

EBITDA increased by $16 million primarily due to higher earnings from expansion projects, and higher distribution charges primarily resulting from increases in rate base and customer base.

Nine months ended September 30, 2018, compared with the nine months ended September 30, 2017

EBITDA for the nine month period ended September 30, 2018 was positively impacted by contributions in the first two months of 2018 of approximately $180 million from Union Gas whose performance was not

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reflected in EBITDA for the first two months of 2017 due to the timing of the completion of the Merger Transaction. When compared to pre-merger results from the prior period, Union Gas' operating results benefited from colder weather and higher revenues primarily due to expansion.

After taking into consideration the contribution of additional earnings from the Merger Transaction, EBITDA was negatively impacted by $20 million due to certain unusual, infrequent and other business factors, primarily explained by the following:

•	a non-cash, unrealized gain of $3 million in 2018 compared with a gain of $13 million in 2017 arising from the change in the mark-to-market value of our equity investee's, Noverco Inc.'s derivative financial instruments; and

•	a negative equity earnings adjustment of $9 million at our equity investee, Noverco Inc. in 2018 arising from United States Tax Reform.

After taking into consideration the factors above, the remaining $165 million increase is primarily explained by the following significant business factors:

•	increased earnings of $45 million period-over-period resulting from colder weather experienced in our franchise service areas when compared to the corresponding period in 2017; and

•	higher earnings from expansion projects, and higher distribution charges primarily resulting from increases in rate base and customer base.

GREEN POWER AND TRANSMISSION

 

 

	Three months ended September 30,					Nine months ended September 30,
	2018		2017			2018		2017
(millions of Canadian dollars)
Earnings before interest, income taxes and depreciation and amortization	51		68			286		270

 

Three months ended September 30, 2018, compared with the three months ended September 30, 2017

EBITDA was negatively impacted by $22 million primarily due to a loss of $20 million in 2018 resulting from the sale of 49% of our interest in the Hohe See Offshore wind farm and its subsequent expansion, refer to Part 1. Item 1. Financial Statements - Note 6. Acquisitions and Dispositions - Dispositions.

After taking into consideration the factor above, EBITDA was comparable with the corresponding 2017 period.

Nine months ended September 30, 2018, compared with the nine months ended September 30, 2017

EBITDA was negatively impacted by $51 million due to certain unusual, infrequent and other factors, primarily explained by the following:

•	a loss of $20 million in 2018 resulting from the sale of 49% of our interest in the Hohe See Offshore wind farm and its subsequent expansion, refer to Part 1. Item 1. Financial Statements - Note 6. Acquisitions and Dispositions - Dispositions;

•	an asset impairment charge of $22 million in 2018 from our equity investment in NRGreen Power Limited Partnership related to the Chickadee Creek waste heat recovery facility in Alberta; and

▪	a loss of $11 million in 2018 representing our share of losses incurred by our equity investee, Rampion Offshore Wind Limited due to the repair and restoration of damaged cables.

After taking into consideration the factors above, the remaining $67 million increase is primarily explained by the following significant business factors:

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•	stronger wind resources and lower operating costs at Canadian and United States wind farms;

•	contributions from the Chapman Ranch Wind Project, which was placed into service in October 2017;

•	contributions from the Rampion Offshore Wind Project, which generated first power in November 2017 and reached full operating capacity in the second quarter of 2018; and

•	a net gain of $11 million from an arbitration settlement related to our Canadian wind facilities.

ENERGY SERVICES

	Three months ended September 30,					Nine months ended September 30,
	2018		2017			2018		2017
(millions of Canadian dollars)
Earnings/(loss) before interest, income taxes and depreciation and amortization	(96	)	(150	)		108		(11	)

 

EBITDA from Energy Services is dependent on market conditions and results achieved in one period may not be indicative of results to be achieved in future periods.

Three months ended September 30, 2018, compared with the three months ended September 30, 2017

EBITDA increased by $20 million primarily due to a non-cash, unrealized loss of $106 million in 2018 compared with a loss of $124 million in 2017 reflecting the revaluation of financial derivatives used to manage the profitability of transportation and storage transactions and manage the exposure to movements in commodity prices.

After taking into consideration the factor above, the remaining $34 million increase is primarily due to increased earnings from Energy Services' Canadian and United States crude operations due to the widening of certain location differentials in 2018, which increased opportunities to generate profitable margins.

Nine months ended September 30, 2018, compared with the nine months ended September 30, 2017

EBITDA was negatively impacted by $6 million primarily due to a non-cash, unrealized gain of $14 million in 2018 compared with a gain of $22 million in 2017 reflecting the revaluation of financial derivatives used to manage the profitability of transportation and storage transactions and manage the exposure to movements in commodity prices.

After taking into consideration the factor above, the remaining $125 million increase is primarily explained by the following significant business factors:

•	the impact of colder weather and other factors in 2018 on natural gas location differentials which created more opportunities to generate profitable margins from our Energy Services' gas marketing business; and

•	increased earnings from Energy Services' Canadian and United States crude operations due to the widening of certain location differentials in 2018, which increased opportunities to generate profitable margins.

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ELIMINATIONS AND OTHER

 

	Three months ended September 30,					Nine months ended September 30,
	2018		2017			2018		2017
(millions of Canadian dollars)
Earnings/(loss) before interest, income taxes and depreciation and amortization	29		126			(368	)	(188	)

 

Eliminations and Other includes operating and administrative costs and the impact of foreign exchange hedge settlements, which are not allocated to business segments. Eliminations and Other also includes 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.

Three months ended September 30, 2018, compared with the three months ended September 30, 2017

EBITDA was negatively impacted by $32 million due to certain unusual, infrequent and other factors, primarily explained by the following:

•	a non-cash, unrealized gain of $131 million in 2018 compared with a $161 million gain in 2017 reflecting net fair value gains and losses arising from the change in the mark-to-market value of derivative financial instruments used to manage foreign exchange risk; and

•	asset monetization transaction costs of $25 million recorded in 2018; partially offset by

•	employee severance, transition and transformation costs of $14 million in 2018 compared with $39 million in 2017.

After taking into consideration the factors above, the remaining $65 million decrease is primarily explained by a realized loss of $59 million in 2018 compared with a loss of $17 million in 2017 related to settlements under our foreign exchange risk management program. Offsetting translation gains are reflected in the applicable business segment results.

Nine months ended September 30, 2018, compared with the nine months ended September 30, 2017

EBITDA was negatively impacted by $145 million due to certain unusual, infrequent and other factors, primarily explained by the following:

•	no non-cash unrealized gains or losses in 2018 compared with a $416 million gain in 2017 reflecting net fair value gains and losses arising from the change in the mark-to-market value of derivative financial instruments used to manage foreign exchange risk; and

•	asset monetization transaction costs of $45 million recorded in 2018; partially offset by

•	employee severance, transition and transformation costs of $102 million in 2018 compared with $243 million in 2017;

•	the absence in 2018 of transaction costs compared with $174 million of costs recorded in 2017 related to the Merger Transaction; and

•	project development costs of $5 million in 2018 compared with $21 million in 2017.

After taking into consideration the factors above, the remaining $35 million decrease is primarily explained by the following significant business factors:

•	two additional months of eliminations and other costs post-Merger Transaction; partially offset by

•	synergies achieved on the integration of corporate functions; and

•	a realized loss of $154 million in 2018 compared with a loss of $159 million in 2017 related to settlements under our foreign exchange risk management program; offsetting translation gains are reflected in the applicable business segment results.

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GROWTH PROJECTS – COMMERCIALLY SECURED PROJECTS

 

The following table summarizes the status of our commercially secured projects, organized by business segment:

		Enbridge's Ownership Interest		Estimated Capital Cost1	Expenditures to Date2	Status	Expected In-Service Date
(Canadian dollars, unless stated otherwise)
LIQUIDS PIPELINES
1.	Canadian Line 3 Replacement Program (the Fund Group)3	100	%	$5.3 billion	$3.2 billion	Under construction	2H - 2019
2.	U.S. Line 3 Replacement Program (EEP)4	100	%	US$2.9 billion	US$0.9 billion	Pre-construction5	2H - 2019
3.	Other - United States6	100	%	US$0.4 billion	US$0.4 billion	Substantially complete	2H - 2019
4.	Other - Canada7	100	%	$0.1 billion	$0.1 billion	Complete	In service
GAS TRANSMISSION AND MIDSTREAM
5.	Atlantic Bridge (SEP)	100	%	US$0.6 billion	US$0.4 billion	Under construction	Q4 - 2018
6.	NEXUS (SEP)	50	%	US$1.3 billion	US$1.1 billion	Complete	In service
7.	Reliability and Maintainability Project	100	%	$0.5 billion	$0.5 billion	Complete	In service
8.	Valley Crossing Pipeline	100	%	US$1.6 billion	US$1.6 billion	Complete	In service
9.	Spruce Ridge Program	100	%	$0.5 billion	$0.1 billion	Pre-construction	Q1 - 2020
10.	T-South Expansion Program	100	%	$1.0 billion	$0.1 billion	Pre-construction	2H - 2020
11.	Other - United States8	100	%	US$2.1 billion	US$1.1 billion	Various stages	2018 - 2021
12.	Other - Canada9	100	%	$0.6 billion	$0.6 billion	Complete	In service
GREEN POWER AND TRANSMISSION
13.	Rampion Offshore Wind Project	24.9	%	$0.8 billion	$0.6 billion	Complete	In service
				(£0.37 billion)	(£0.3 billion)
14.	Hohe See Offshore Wind Project and Expansion10	25	%	$1.1 billion	$0.5 billion	Under construction	2H - 2019
				(€0.67 billion)	(€0.3 billion)

1 These amounts are estimates and are subject to upward or downward adjustment based on various factors. Where appropriate, the amounts reflect our share of joint venture projects.

2 Expenditures to date reflect total cumulative expenditures incurred from inception of the project up to September 30, 2018.

3 The Fund Group is comprised of Enbridge Income Fund, Enbridge Commercial Trust, Enbridge Income Partners LP and the subsidiaries and investees of Enbridge Income Partners LP.

4 The U.S. L3R Program is being funded 99% by Enbridge and 1% by EEP.

5 Construction of the Wisconsin portion of the project is complete as noted below. The remaining project is in pre-construction status.

6 Includes the Lakehead System Mainline Expansion - Line 61. Estimated in-service date will be adjusted to coincide with the in-service date of the U.S. L3R Program.

7 Includes the $0.1 billion Line 45 Cheecham connectivity project placed into service in the second quarter of 2018.

8 Includes the US$0.2 billion Stampede Offshore oil lateral placed into service in the first quarter of 2018 and the US$0.2 million Texas Eastern Appalachian Lease project placed into service in October 2018.

9 Includes the $0.4 billion High Pine and the $0.2 billion Wyndwood pipeline expansion, both placed into service in the first quarter of 2018.

10 Upon closing of the sale of our Renewable Assets, our ownership interest was reduced to approximately 25%. Refer to Asset Monetization.

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A full description of each of our projects is provided in our Annual Report on Form 10-K, as filed with the Securities and Exchange Commission on February 16, 2018. Significant updates that have occurred since the date of filing are discussed below.

LIQUIDS PIPELINES

•	United States Line 3 Replacement Program (EEP) - the Wisconsin portion of the U.S. L3R Program is in service. For additional updates on the project, refer to Growth Projects - Regulatory Matters - United States Line 3 Replacement Program (EEP).

GAS TRANSMISSION AND MIDSTREAM

•	Atlantic Bridge - the expansion of SEP's Algonquin Gas Transmission systems to transport 133 mmcf/d of natural gas to the New England region. Due to ongoing permitting delays in Massachusetts, the revised cost of the project is US$0.6 billion. This is approximately 17% above prior estimates.

•	NEXUS - a natural gas pipeline system connecting SEP's Texas Eastern pipeline system in Ohio to the Union Gas Dawn hub in Ontario, via Vector Pipeline L.P., providing capacity of up to approximately 1.5 bcf/d. The project was placed into service in October 2018.

•

Reliability and Maintainability Project - a natural gas pipeline project designed to enhance the performance of the southern segment of the British Columbia Pipeline system to accommodate the increased base load on the system. The project involves adding new compressor units at three compressor stations along the pipeline system as well as upgrading existing pipeline crossovers and adding new crossovers at key locations. The project was placed into service in August 2018.

•

Valley Crossing Pipeline - a natural gas pipeline connecting the Agua Dulce hub in Texas to an offshore tie-in with the Sur de Texas-Tuxpan project, which is being constructed by a third party. The project will help Mexico meet its growing gas fired electric generation needs by providing capacity of up to approximately 2.6 billion cubic feet per day. Based on an updated execution plan, the revised cost of the project is US$1.6 billion. This is approximately 12% above prior estimates and reflects scope changes, reroutes and offshore weather delays. The project was placed into service on October 31, 2018.

•	Spruce Ridge Program - natural gas pipeline expansion of Westcoast Energy Inc.'s British Columbia Pipeline in northern British Columbia, which consists of the Aitken Creek Looping project and the Spruce Ridge Expansion project. As a result of regulatory delays, the revised expected in-service date of the program is the first quarter of 2020.

GREEN POWER AND TRANSMISSION

•	Rampion Offshore Wind Project - the project generated first power in November 2017. All remaining turbines were commissioned in March 2018 and full operating capacity was reached in the second quarter of 2018.

GROWTH PROJECTS - REGULATORY MATTERS

United States Line 3 Replacement Program (EEP)

EEP is in the process of obtaining the appropriate permits for constructing the U.S. L3R Program in Minnesota. The project requires both a Certificate and Route Permit from the MNPUC.

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On June 28, 2018, the MNPUC approved the issuance of a Certificate and Route Permit that adopts EEP’s preferred route, with minor modifications and subject to certain conditions. The MNPUC issued its Certificate order on September 5, 2018. The Route Permit was issued on October 26, 2018. Permits are also required from the United States Army Corps of Engineers (Army Corps), state agencies (including the Minnesota Department of Natural Resources and the Minnesota Pollution Control Agency) and local government authorities in Minnesota. EEP anticipates the receipt of all required permits in time to commence construction activities during the first quarter of 2019, and continues to anticipate an in-service date for the project in the second half of 2019.

OTHER ANNOUNCED PROJECTS UNDER DEVELOPMENT

 

The following projects have been announced by us, but have not yet met our criteria to be classified as commercially secured:

LIQUIDS PIPELINES

•

Gray Oak Pipeline Project - the Gray Oak Pipeline, LLC announced on April 24, 2018, that it received sufficient binding commitments on an initial open season to proceed with construction of the Gray Oak Pipeline. A second open season was completed in July 2018. The Gray Oak Pipeline will provide crude oil transportation from West Texas to destinations in the Corpus Christi and Sweeny/Freeport markets. The pipeline is expected to be placed in service by the end of 2019 and could have an ultimate capacity of approximately one million barrels per day, subject to additional shipper commitments. We have secured an option to acquire an interest in the pipeline.

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LIQUIDITY AND CAPITAL RESOURCES

 

The maintenance of financial strength and flexibility is fundamental to our growth strategy, particularly in light of the significant number and size of capital projects currently secured or under development. Access to timely funding from capital markets could be limited by factors outside our control, including but not limited to financial market volatility resulting from economic and political events both inside and outside North America. To mitigate such risks, we actively manage financial plans and strategies to ensure we maintain sufficient liquidity to meet routine operating and future capital requirements. In the near term, we generally expect to utilize cash from operations together with commercial paper issuance and/or credit facility draws and the proceeds of capital market offerings to fund liabilities as they become due, finance capital expenditures, fund debt retirements and pay common and preference share dividends. We target to maintain sufficient liquidity through securement of committed credit facilities with a diversified group of banks and financial institutions to enable us to fund all anticipated requirements for approximately one year without accessing the capital markets.

 

Our financing plan is regularly updated to reflect evolving capital requirements and financial market conditions and identifies a variety of potential sources of debt and equity funding alternatives.

 

CAPITAL MARKET ACCESS

We ensure ready access to capital markets, subject to market conditions, through maintenance of shelf prospectuses that allow for issuance of long-term debt, equity and other forms of long-term capital when market conditions are attractive.

Credit Facilities and Liquidity

To ensure ongoing liquidity and to mitigate the risk of capital market disruption, we maintain ready access to funds through committed bank credit facilities and actively manage our bank funding sources to optimize pricing and other terms. The following table provides details of our committed credit facilities as at September 30, 2018.

		September 30, 2018
	Maturity Dates	Total Facilities		Draws1		Available
(millions of Canadian dollars)
Enbridge Inc.	2019-2023	5,602		2,330		3,272
Enbridge (U.S.) Inc.	2019	1,829		—		1,829
Enbridge Energy Partners, L.P.2	2019-2022	3,167		2,210		957
Enbridge Gas Distribution Inc.	2019-2020	1,017		779		238
Enbridge Income Fund	2020	1,500		9		1,491
Enbridge Pipelines Inc.	2020	3,000		1,214		1,786
Spectra Energy Partners, LP3	2022	3,232		2,153		1,079
Union Gas	2021	700		481		219
Total committed credit facilities		20,047		9,176		10,871

 

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

2	Includes $239 million (US$185 million) of commitments that expire in 2020.

3	Includes $435 million (US$336 million) of commitments that expire in 2021.

During the second quarter of 2018, Enbridge (U.S.) Inc. terminated a US$500 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.

During the first quarter of 2018, Enbridge terminated a US$650 million credit facility, which was scheduled to mature in 2019, and repaid drawn amounts. In addition, Enbridge (U.S.) Inc. terminated an unutilized US$950 million credit facility, which was scheduled to mature in 2019.

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During the first quarter of 2018, Westcoast Energy Inc. terminated an unutilized $400 million credit facility with a syndicate of banks. The facility was acquired in conjunction with the Merger Transaction and was scheduled to mature in 2021.

In addition to the committed credit facilities noted above, we maintain $790 million of uncommitted demand credit facilities, of which $564 million were unutilized as at September 30, 2018. As at December 31, 2017, we had $792 million of uncommitted credit facilities, of which $518 million were unutilized.

Our net available liquidity of $11,514 million as at September 30, 2018, was inclusive of $643 million of unrestricted cash and cash equivalents as reported in the Consolidated Statements of Financial Position.

 

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 September 30, 2018, we were in compliance with all debt covenants and we expect to continue to comply with such covenants.

LONG-TERM DEBT ISSUANCES

During the nine months ended September 30, 2018, we completed the following long-term debt issuances:

Company	Issue Date			Principal Amount
(millions of Canadian dollars, unless otherwise stated)
Enbridge Inc.
	March 2018	Fixed-to-floating rate subordinated notes due 20781		US$850
	April 2018	Fixed-to-floating rate subordinated notes due 20782		$750
	April 2018	Fixed-to-floating rate subordinated notes due 20783		US$600
Spectra Energy Partners, LP4
	January 2018	3.50% senior notes due 2028		US$400
	January 2018	4.15% senior notes due 2048		US$400

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 London Interbank Offered Rate (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	Issued through Texas Eastern Transmission, LP, a wholly-owned operating subsidiary of SEP.

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LONG-TERM DEBT REPAYMENTS

During the nine months ended September 30, 2018, we completed the following long-term debt repayments to further simplify our debt financing structure post-merger:

Company	Retirement/Repayment Date			Principal Amount	Cash Consideration1
(millions of Canadian dollars, unless otherwise stated)
Enbridge Energy Partners, L.P.
	April 2018	6.50% senior notes		US$400
Enbridge Pipelines (Southern Lights) L.L.C
	June 2018	3.98% medium-term notes due June 2040		US$20
Enbridge Southern Lights LP
	January 2018	4.01% medium-term notes due June 2040		$9
	July 2018	4.01% medium-term notes due June 2040		$8
Midcoast Energy Partners, L.P.
Redemption2
	July 2018	3.56% senior notes due September 2019		US$75	US$76
	July 2018	4.04% senior notes due September 2021		US$175	US$182
	July 2018	4.42% senior notes due September 2024		US$150	US$161
Spectra Energy Capital, LLC
Repurchase via Tender Offer2
	March 2018	6.75% senior unsecured notes due 2032		US$64	US$80
	March 2018	7.50% senior unsecured notes due 2038		US$43	US$59
Redemption2
	March 2018	5.65% senior unsecured notes due 2020		US$163	US$172
	March 2018	3.30% senior unsecured notes due 2023		US$498	US$508
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
Union Gas
	April 2018	5.35% medium-term notes		$200
	August 2018	8.75% debenture		$125
Westcoast Energy Inc.
	May 2018	6.90% senior secured notes		$13
	May 2018	4.34% senior secured notes		$4
	September 2018	8.50% debenture		$150

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 a fair value adjustment recorded upon completion of the Merger Transaction, was reported within Interest expense in the Consolidated Statements of Earnings.

Strong growth in internal cash flow, ready access to liquidity from diversified sources and a stable business model support our credit profile. We actively monitor and manage key financial metrics with the objective of sustaining investment grade credit ratings from the major credit rating agencies and help ensure ongoing access to bank funding and term debt capital on attractive terms. Key measures of financial strength that are closely managed include the ability to service debt obligations from operating cash flow and the ratio of debt to total capital. As at September 30, 2018, our debt capitalization ratio was 46.8%, compared with 48.3% as at December 31, 2017.

There are no material restrictions on our cash. Total restricted cash of $83 million, includes EGD's and Union Gas’ receipt of cash from the Government of Ontario to fund its Green Investment Fund program. In addition, our restricted cash includes cash collateral and amounts received in respect of specific shipper commitments. Cash and cash equivalents held by EEP, the Fund Group and SEP are generally not readily accessible by us until distributions are declared and paid by these entities, which occurs quarterly for EEP and SEP, and monthly for the Fund Group. Further, cash and cash equivalents held by certain foreign subsidiaries may not be readily accessible for alternative uses by us.

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Excluding current maturities of long-term debt, we had a negative working capital position as at September 30, 2018. The major contributing factor to the negative working capital position was the ongoing funding of our growth capital program.

 

To address this negative working capital position, we maintain significant liquidity in the form of committed credit facilities and other sources as previously discussed, which enable the funding of liabilities as they become due. As at September 30, 2018 and December 31, 2017, our net available liquidity totaled $11,514 million and $12,959 million, respectively.

SOURCES AND USES OF CASH

 

	Nine months ended September 30,
	2018		2017
(millions of Canadian dollars)
Operating activities	7,999		5,315
Investing activities	(3,072	)	(8,034	)
Financing activities	(4,811	)	2,081
Effect of translation of foreign denominated cash and cash equivalents and restricted cash	23		(77	)
Increase/(decrease) in cash and cash equivalents and restricted cash	139		(715	)

 

Significant sources and uses of cash for the nine months ended September 30, 2018 and September 30, 2017 are summarized below:

 

Operating Activities

 

•	The growth in cash flow delivered by operations during the nine months ended September 30, 2018 is a reflection of the positive operating factors discussed under Results of Operations. The increase in operating cash flow was driven mainly by contributions from new assets placed into service in 2017 and 2018 and from new assets following the completion of the Merger Transaction.

•

Changes in operating assets and liabilities included within operating activities were $943 million and $121 million for the nine months ended September 30, 2018 and 2017, respectively. Our operating assets and liabilities fluctuate in the normal course due to various factors, including the impact of fluctuations in commodity prices and activity levels on working capital within the Energy Services and Gas Distribution segments, the timing of tax payments, as well as timing of cash receipts and payments generally.

Investing Activities

 

•

The decrease of cash used in investing activities during the nine months ended September 30, 2018 compared with the corresponding period in 2017 was primarily attributable to activity in 2017 that was not present in 2018, related primarily to the acquisition of an interest in the Bakken Pipeline System of $2.0 billion (US$1.5 billion), partially offset by cash acquired in the Merger Transaction of $0.7 billion.

•

Adding to the decrease in cash used for investing activities in 2018 were proceeds from asset dispositions of $1.9 billion from our sale of MOLP and international renewable assets compared with proceeds from asset dispositions of $0.6 billion in the corresponding period in 2017. Proceeds from the dispositions of these assets were used in our growth capital program and to repay maturing term notes and credit facilities as discussed in Financing activities.

•	Further adding to the decrease of cash used in investing activities were distributions from equity investments in excess of cumulative earnings of $1,243 million and $62 million for the nine months ended September 30, 2018 and 2017, respectively. On April 30, 2018, SEP received a

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distribution from Sabal Trail in the amount of $952 million (US$744 million) as a partial return of capital for construction and development costs previously funded by Sabal Trail's partners.

•	We are continuing with the execution of our growth capital program which is further described in Growth Projects - Commercially Secured Projects. The timing of project approval, construction and in-service dates impacts the timing of cash requirements.

 

Financing Activities

 

•

During the nine months ended 2018, we used cash in financing activities of $4,811 million compared to cash provided by financing activities of $2,081 million for the corresponding period in 2017. The change was primarily attributable to repayments of maturing term notes and credit facilities and a decrease of long-term debt issued in 2018 when compared to the same period in 2017. During the nine months ended September 30, 2018, we sold an interest in our Canadian and US renewable assets to the CPPIB. The proceeds of these dispositions and the dispositions of our MOLP and international renewable assets discussed in Investing Activities above, were primarily used to repay maturing term notes and credit facilities, while proceeds from hybrid securities issued during the first half of 2018 were primarily used to repay credit facilities and to repurchase or redeem Spectra Energy Capital, LLC’s outstanding senior unsecured notes.

•

Cash from financing activities decreased as a result of decreased contributions from noncontrolling interests and redeemable noncontrolling interests of $475 million and $552 million, respectively. Noncontrolling interest contributions received in 2017 related to completed projects for which there were no contributions received from noncontrolling interests in 2018. In April 2017, contributions from redeemable noncontrolling interests were received from a secondary public offering attributable to our holdings in ENF. There were no similar offerings during the nine months ended September 30, 2018.

•

Finally, with the exception of dividends paid to Spectra Energy Corp shareholders that were declared prior to the Merger Transaction, our common share dividend payments increased in the nine months ended September 30, 2018, primarily due to the increase in the common share dividend rate in the first quarter of 2018, as well as an increase in the number of common shares outstanding as a result of common shares issued in connection with the Merger Transaction and the issuance of approximately 33 million common shares in December 2017 in a private placement offering.

Dividend Reinvestment and Share Purchase Plan

For the three months ended September 30, 2018 and 2017, dividends declared were $1,152 million and $1,001 million, respectively, of which $761 million and $650 million, respectively, were paid in cash and reflected in financing activities. The remaining $391 million and $351 million, respectively, of dividends paid were reinvested pursuant to the DRIP and resulted in the issuance of common shares rather than a cash payment. For the three months ended September 30, 2018 and 2017, 33.9% and 35.1%, respectively, of total dividends declared were reinvested through the DRIP.

For the nine months ended September 30, 2018 and 2017, dividends declared were $2,297 million and $2,552 million, respectively. For the nine months ended September 30, 2018 and 2017, total dividends paid were $3,435 million and $2,552 million, respectively, of which $2,254 million and $1,663 million, respectively, were paid in cash and reflected in financing activities. The remaining $1,181 million and $889 million, respectively, of dividends paid were reinvested pursuant to the DRIP and resulted in the issuance of common shares rather than a cash payment. In addition to amounts paid in cash and reflected in financing activities for the nine months ended September 30, 2017, were $414 million in dividends declared to Spectra Energy Corp shareholders prior to the Merger Transaction that were paid after the Merger Transaction. For the nine months ended September 30, 2018 and 2017, 34.4% and 34.8%, respectively, of total dividends paid were reinvested through the DRIP.

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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.

As a result of the announcement, shareholders only receive dividends in cash effective with the dividend currently scheduled to be paid on December 1, 2018, to shareholders of record on November 15, 2018. If we elect to reinstate the DRIP in the future, the shareholders that were enrolled in the DRIP at the time of suspension and remain enrolled at the time of its reinstatement will automatically resume participation in the DRIP.

Our Board of Directors has declared the following quarterly dividends. All dividends are payable on December 1, 2018, to shareholders of record on November 15, 2018.

 

	Dividend per share
Common Shares		$0.67100
Preference Shares, Series A		$0.34375
Preference Shares, Series B		$0.21340
Preference Shares, Series C1		$0.23934
Preference Shares, Series D2		$0.27875
Preference Shares, Series F3		$0.29306
Preference Shares, Series H4		$0.27350
Preference Shares, Series J	US$0.30540
Preference Shares, Series L	US$0.30993
Preference Shares, Series N		$0.25000
Preference Shares, Series P		$0.25000
Preference Shares, Series R		$0.25000
Preference Shares, Series 15	US$0.37182
Preference Shares, Series 3		$0.25000
Preference Shares, Series 5	US$0.27500
Preference Shares, Series 7		$0.27500
Preference Shares, Series 9		$0.27500
Preference Shares, Series 11		$0.27500
Preference Shares, Series 13		$0.27500
Preference Shares, Series 15		$0.27500
Preference Shares, Series 17		$0.32188
Preference Shares, Series 196		$0.30625

 

1	The quarterly dividend per share paid on Series C was increased to $0.22685 from $0.20342 on March 1, 2018, was increased to $0.22748 from $0.22685 on June 1, 2018, and was increased to $0.23934 from $0.22748 on September 1, 2018, due to reset on a quarterly basis following the date of issuance of the Series C Preference Shares.

2	The quarterly dividend per share paid on Series D was increased to $0.27875 from $0.25000 on March 1, 2018, due to reset of the annual dividend on March 1, 2018, under the dividend rate reset provisions applicable to this series.

3	The quarterly dividend per share paid on Series F was increased to $0.29306 from $0.25000 on June 1, 2018, due to reset of the annual dividend on June 1, 2018, under the dividend rate reset provisions applicable to this series.

4	The quarterly dividend per share paid on Series H was increased to $0.27350 from $0.25000 on September 1, 2018, due to reset of the annual dividend on September 1, 2018, and every five years thereafter.

5	The quarterly dividend per share paid on Series 1 was increased to US$0.37182 from US$0.25000 on June 1, 2018, due to reset of the annual dividend on June 1, 2018, under the dividend rate reset provisions applicable to this series.

6	The dividend per share on Series 19 increased from $0.26850 to the regular quarterly dividend of $0.30625, effective June 1, 2018.

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LEGAL AND OTHER UPDATES

LIQUIDS PIPELINES

Eddystone Rail Legal Matter

In February 2017, our subsidiary Eddystone Rail Company, LLC (Eddystone Rail) filed an action against several defendants in the United States District Court for the Eastern District of Pennsylvania. Eddystone Rail alleges that the defendants transferred valuable assets from Eddystone Rail’s counterparty in a maritime contract, so as to avoid outstanding obligations to Eddystone Rail. Eddystone Rail is seeking payment of compensatory and punitive damages in excess of US$140 million. On July 19, 2017, the defendants’ motions to dismiss Eddystone Rail’s claims were denied. Defendants have filed Answers and Counterclaims, which together with subsequent amendments, seek damages from Eddystone Rail in excess of US$32 million. Eddystone filed a motion to dismiss the counterclaims and defendants amended their Answer and Counterclaims on September 21, 2017. On October 12, 2017 Eddystone Rail moved to dismiss the latest version of defendants’ counterclaims. On February 6, 2018, the United States District Court for the District of Columbia (the Court) denied without prejudice Eddystone Rail's motion to dismiss the defendants' counterclaims. The defendants’ chances of success on their counterclaims cannot be predicted at this time. On September 7, 2018, the Court granted Eddystone’s motion to amend its complaint to add several affiliates of the corporate defendants as additional defendants. Motions to dismiss Eddystone’s amended complaint are pending at this time. The defendants’ chances of success in pursuing dismissal of motions to dismiss the amended complaint cannot be predicted at this time.

Dakota Access Pipeline

In February 2017, the Standing Rock Sioux Tribe and the Cheyenne River Sioux Tribe (the Tribes) filed motions with the Court contesting the validity of the process used by the Army Corps to permit the Dakota Access Pipeline (DAPL). The plaintiffs requested the Court order the operator to shut down the pipeline until the appropriate regulatory process is completed.

On June 14, 2017, the Court ruled that the Army Corps did not sufficiently weigh the degree to which the project's effects would be highly controversial and the Army Corps failed to adequately consider the impact of an oil spill on the hunting and fishing rights of the Tribes and on environmental justice (the June 2017 Order). The Court ordered the Army Corps to reconsider those components of its environmental analysis. On October 11, 2017, the Court issued an order that allows DAPL to continue operating while the Army Corps completes the additional environmental review required by the June 2017 Order. The Court additionally ordered DAPL to implement certain interim measures pending the Army Corps' supplemental analysis. The Army Corps issued its decision on August 31, 2018, and found that no supplemental environmental analysis is required. The Army Corps' decision is under review by the Tribes.

Seaway Pipeline Regulatory Matters

Seaway Crude Pipeline System (Seaway Pipeline) filed an application for market-based rates in December 2011 and refiled in December 2014. Several parties filed comments in opposition alleging that the application should be denied because Seaway Pipeline has market power in both its receipt and destination markets. On December 1, 2016, the Administrative Law Judge issued its decision which concluded that the Commission should grant the application of Seaway Pipeline for authority to charge market-based rates. By order dated May 17, 2017, the Commission affirmed the Administrative Law Judge’s finding that Seaway Pipeline lacks market power in the applicable markets and granted Seaway Pipeline’s application for market based rate authority. No requests for rehearing or petitions for review were filed. The order is therefore now final.

GAS TRANSMISSION AND MIDSTREAM

Sabal Trail FERC Certificate Review

Sierra Club and two other non-governmental organizations filed a Petition for Review of Sabal Trail’s FERC certificate on September 20, 2016 in the D.C. Circuit Court of Appeals. On August 22, 2017, the D.C. Circuit issued an opinion denying one of the petitions, and granting the other petition in part, vacating the certificates, and remanding the case to FERC to supplement the environmental impact

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statement for the project to estimate the quantity of green-house gases to be released into the environment by the gas-fired generation plants in Florida that will consume the gas transported by Sabal Trail. The court withheld issuance of the mandate requiring vacatur of the certificate until seven days after the disposition of any timely petition for rehearing. On October 6, 2017, Sabal Trail and FERC each filed timely petitions for rehearing. On January 31, 2018, the court denied FERC’s and Sabal Trail’s petitions for rehearing. On February 5, 2018, FERC issued its final supplemental environmental impact statement in compliance with the D.C. Circuit decision. In addition, on February 6, 2018, FERC filed a motion with the court requesting a 45-day stay of the mandate. On March 7, 2018, the court granted FERC’s 45-day request for stay, and directed that issuance of the mandate be withheld through March 26, 2018. On March 14, 2018 FERC issued its Order on Remand Reinstating Certificate and Abandonment Authorizations which addressed the court’s ruling in the August 22, 2017 decision, and on March 30, 2018 the court issued its mandate.

Sierra Club and two other non-governmental organizations, as well as the two landowners, timely requested rehearing from the FERC of the March 14, 2018 Order. On August 10, 2018, the FERC issued an order denying the requests of Sierra Club and others seeking Rehearing of FERC's order on remand. No appeals related to the FERC's March 14, 2018 Order were timely filed and FERC's March 14, 2018 Order is now final and non-appealable.

GAS DISTRIBUTION

On July 3, 2018, the government of Ontario issued Ontario Regulation 386/18 which revoked the Cap and Trade program regulation and prohibits registered participants from purchasing, selling, trading or otherwise dealing with emission allowances and credits. Subsequently, on July 6, 2018, the OEB suspended its review of EGD and Union Gas' 2018 Cap and Trade Compliance Plans. On July 25, 2018, the government of Ontario introduced Bill 4 to wind down the Cap and Trade program. Subsequently, by letter dated August 30, 2018, the OEB instructed EGD and Union Gas to request the elimination of Cap and Trade charges as part of their October 2018 Quarterly Rate Adjustment Mechanism (QRAM) application, thereby removing Cap and Trade charges from customer bills effective October 1, 2018. The letter also instructed EGD and Union Gas to request the disposition of any projected aggregate net credit balance in their Cap and Trade related deferral and variance accounts as at September 30, 2018.

In accordance with the OEB’s direction, on September 11, 2018, EGD and Union Gas filed their October 2018 QRAM applications which included the requests to remove Cap and Trade charges from rates, and to refund Cap and Trade related deferral and variance account balances to customers, effective October 1, 2018.  The OEB approved EGD's and Union Gas' QRAM applications on September 27, 2018.

On October 31, 2018, Bill 4 received royal assent from the government of Ontario, providing for the wind down of the Cap and Trade program.

OTHER LITIGATION

We and our subsidiaries are involved in 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.

CAPITAL EXPENDITURE COMMITMENTS

We have signed contracts for the purchase of services, pipe and other materials totaling $3,301 million which are expected to be paid over the next five years.

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.

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CHANGES IN ACCOUNTING POLICIES

 

Refer to Item 1. Financial Statements - Note 2. Changes in Accounting Policies.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Our exposure to market risk is described in Part II. Item 7A. Quantitative and Qualitative Disclosures About Market Risk of our Annual Report on Form 10-K for the fiscal year ended December 31, 2017, filed with the SEC on February 16, 2018. We believe our exposure to market risk has not changed materially since then.

ITEM 4. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

Disclosure controls and procedures are controls and other procedures that are designed to ensure that information required to be disclosed by us in the reports we file or submit under the Securities Exchange Act of 1934 (Exchange Act) is recorded, processed, summarized and reported within the time periods specified by the SEC’s rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to provide reasonable assurance that information required to be disclosed by us in the reports we file or submit under the Exchange Act is accumulated and communicated to management, including the Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure.

Under the supervision and with the participation of management, including the Chief Executive Officer and Chief Financial Officer, we have evaluated the effectiveness of our disclosure controls and procedures (as such term is defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of September 30, 2018, and based upon this evaluation, the Chief Executive Officer and Chief Financial Officer have concluded that these controls and procedures are effective in ensuring that information required to be disclosed by us in reports that we file with or submit to the SEC and the Canadian Securities Administrators is recorded, processed, summarized and reported within the time periods required.

Changes in Internal Control over Financial Reporting

Under the supervision and with the participation of management, including the Chief Executive Officer and Chief Financial Officer, we have evaluated changes in internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) that occurred during the fiscal quarter ended September 30, 2018 and found no change that has materially affected, or is reasonably likely to materially affect, internal control over financial reporting.

PART II - OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

We are involved in various legal and regulatory actions and proceedings which arise in the ordinary course of business. 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. Refer to Part I. Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations - Legal and Other Updates for discussion of other legal proceedings.

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ITEM 1A. RISK FACTORS

In addition to the other information set forth in this report, careful consideration should be given to the factors discussed in Part I. Item 1A. Risk Factors of our Annual Report on Form 10-K for the year ended December 31, 2017, which could materially affect our financial condition or future results. Other than as set out below, there have been no modifications to those risk factors.

Our operations are subject to pipeline safety laws and regulations, compliance with which may require significant capital expenditures, increase our cost of operations and affect or limit our business plans.

Many of our operations are regulated. The nature and degree of regulation and legislation affecting energy companies in Canada and the United States have changed significantly in past years and further substantial changes may occur.

On February 8, 2018, the Government of Canada introduced legislation to revise the process for assessing major resource projects. If the legislation is passed in its current form, we believe it would have adverse impacts on pipeline companies, particularly in relation to the regulatory review process for proposed new projects that are “designated projects”, by making overall timelines for the development and execution of these projects longer and significantly increasing uncertainty.

Compliance with legislative changes may impose additional costs on new pipeline projects as well as on existing operations. Failure to comply with applicable regulations could result in a number of consequences which may have an adverse effect on our operations, earnings, financial condition and cash flows.

There can be no assurance that the proposed combination transactions between us and our sponsored vehicles will be approved and ultimately consummated or that the anticipated benefits of any such transactions will be realized.

During the interim period, we entered into separate merger or arrangement agreements with our sponsored vehicles, SEP, EEP, EEQ and ENF, to acquire, in separate combination transactions, all of the outstanding equity securities of those sponsored vehicles not beneficially owned by us. Under the agreements:

•	SEP unitholders would receive 1.111 common shares of Enbridge per SEP unit;

•	EEP unitholders would receive 0.335 common shares of Enbridge per EEP unit;

•	EEQ shareholders would receive 0.335 common shares of Enbridge per EEQ share; and

•	ENF shareholders would receive 0.7350 common shares of Enbridge per ENF share and a cash payment of no less than $0.45 per ENF share.

The agreements contain certain termination rights and customary closing conditions, including unitholder or shareholder approvals, as applicable, standard regulatory notifications and approvals and other third party approvals.

We cannot predict whether or when any such transactions will be approved by the requisite votes of securityholders of the respective sponsored vehicles or other conditions precedent will be satisfied. Any changes in the market prices of our common shares or the units or shares, as applicable, of the sponsored vehicles could affect whether the securityholders of the applicable sponsored vehicle ultimately approve the proposed transactions.

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Uncertainties about the timing and effect of the proposed transactions may have an adverse effect on us. These uncertainties may have negative impacts on the market price of our common shares, our businesses and financial results.

ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

None.

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

None.

ITEM 4. MINE SAFETY DISCLOSURES

Not applicable.

ITEM 5. OTHER INFORMATION

On October 30, 2018, Michael McShane announced his retirement from the Board of Directors, effective October 31, 2018. Mr. McShane has served on the Board of Directors since February 27, 2017, prior to which he was a director of Spectra Energy Corp. His decision to retire from the Board of Directors was based on the demands of his time from other professional and personal commitments, and was not the result of any disagreement relating to our operations, policies or practices.

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ITEM 6. EXHIBITS

Each exhibit identified below is included as a part of this quarterly report. Exhibits included in this filing are designated by an asterisk (“*”); all exhibits not so designated are incorporated by reference to a prior filing as indicated.

Exhibit No.		Description
2.1		Agreement and Plan of Merger, dated as of September 5, 2016, by and among Spectra Energy Corp, Enbridge Inc. and Sand Merger Sub, Inc. (incorporated by reference to Exhibit 2.1 to Enbridge’s Registration Statement on Form F-4 filed September 23, 2017)
2.2		Agreement and Plan of Merger, dated as of August 24, 2018, by and among Spectra Energy Partners, LP, Spectra Energy Partners (DE) GP, LP, Enbridge Inc., Enbridge (U.S.) Inc., Autumn Acquisition Sub, LLC, and solely for the purposes of Articles I, II and XI, Enbridge US Holdings Inc., Spectra Energy Corp, Spectra Energy Capital, LLC and Spectra Energy Transmission, LLC. (incorporated by reference to Exhibit 2.1 to Enbridge’s Form 8-K filed August 24, 2018)
2.3		Agreement and Plan of Merger, dated as of September 17, 2018, by and among Enbridge Energy Partners, L.P., Enbridge Energy Company, Inc., Enbridge Energy Management, L.L.C., Enbridge Inc., Enbridge (U.S.) Inc., Winter Acquisition Sub II, LLC, and solely for the purposes of Articles I, II and XI, Enbridge US Holdings Inc. (incorporated by reference to Exhibit 2.1 to Enbridge’s Form 8-K filed September 18, 2018)
2.4		Agreement and Plan of Merger, dated as of September 17, 2018, by and among Enbridge Energy Management, L.L.C., Enbridge Inc., Winter Acquisition Sub I, Inc., and solely for the purposes of Article I, Section 2.4 and Article X, Enbridge Energy Company, Inc. (incorporated by reference to Exhibit 2.2 to Enbridge’s Form 8-K filed September 18, 2018)
2.5		Arrangement Agreement, dated as of September 17, 2018, by and between Enbridge Inc. and Enbridge Income Fund Holdings Inc. (incorporated by reference to Exhibit 2.3 to Enbridge’s Form 8-K filed September 18, 2018)
10.1		Executive Employment Agreement between Enbridge Employee Services, Inc. and William T. Yardley, dated July 25, 2018 (incorporated by reference to Exhibit 10.1 to Enbridge’s Form 8-K filed July 27, 2018)
31.1*		Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2*		Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1*		Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2*		Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101.INS*		XBRL Instance Document.
101.SCH*		XBRL Taxonomy Extension Schema Document.
101.CAL*		XBRL Taxonomy Extension Calculation Linkbase Document.
101.DEF*		XBRL Taxonomy Extension Definition Linkbase Document.
101.LAB*		XBRL Taxonomy Extension Label Linkbase Document.
101.PRE*		XBRL Taxonomy Extension Presentation Linkbase Document.

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SIGNATURES

 

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

 

 

			ENBRIDGE INC.
			(Registrant)
Date:	November 2, 2018	By:	/s/ Al Monaco
			Al Monaco President and Chief Executive Officer
Date:	November 2, 2018	By:	/s/ John K. Whelen
			John K. Whelen Executive Vice President and Chief Financial Officer (Principal Financial Officer)

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