Edgar Filing: ENBRIDGE INC

Receivables

Contract Assets

Contract Liabilities

(millions of Canadian dollars)

Balance as at January 1, 2018

Balance as at June 30, 2018

Document

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 June 30, 2018



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 and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted 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 and post 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 (Do not check if a smaller reporting company)		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 1,715,483,875 common shares outstanding as of July 27, 2018.



		Page
	PART I
Item 1.	Financial Statements	6
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	41
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	63
Item 4.	Controls and Procedures	63
	PART II
Item 1.	Legal Proceedings	64
Item 1A.	Risk Factors	64
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	65
Item 3.	Defaults Upon Senior Securities	65
Item 4.	Mine Safety Disclosures	65
Item 5.	Other Information	65
Item 6.	Exhibits	66
	Signatures	66

GLOSSARY



ALJ	Administrative Law Judge
AOCI	Accumulated other comprehensive income/(loss)
Army Corps	United States Army Corps of Engineers
ASU	Accounting Standards Update
Certificate	Certificate of Need
DRIP	Dividend Reinvestment and Share Purchase Plan
EBITDA	Earnings before interest, income taxes and depreciation and amortization
Eddystone Rail	Eddystone Rail Company, LLC
EEP	Enbridge Energy Partners, L.P.
EGD	Enbridge Gas Distribution Inc.
Enbridge	Enbridge Inc.
FERC	Federal Energy Regulatory Commission
IDRs	Incentive distribution rights
kbpd	thousands of barrels per day
Line 10	Line 10 crude oil pipeline
MNPUC	Minnesota Public Utilities Commission
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

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; impact of the Canadian L3R Program on existing integrity programs; 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 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 impact 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.

PART I - FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

ENBRIDGE INC.

CONSOLIDATED STATEMENTS OF EARNINGS



	Three months ended June 30,				Six months ended June 30,
	2018		2017		2018		2017
(unaudited; millions of Canadian dollars, except per share amounts)
Operating revenues
Commodity sales	6,451		6,620		13,719		13,486
Gas distribution sales	856		847		2,782		2,210
Transportation and other services	3,438		3,649		6,970		6,566
Total operating revenues (Note 3)	10,745		11,116		23,471		22,262
Operating expenses
Commodity costs	6,278		6,489		13,275		13,039
Gas distribution costs	421		429		1,745		1,444
Operating and administrative	1,636		1,646		3,277		3,197
Depreciation and amortization	829		868		1,653		1,540
Asset impairment (Note 6)	10		—		1,072		—
Total operating expenses	9,174		9,432		21,022		19,220
Operating income	1,571		1,684		2,449		3,042
Income from equity investments	363		236		698		472
Other income/(expense)
Net foreign currency gain/(loss)	(43	)	112		(228	)	107
Other	29		67		94		107
Interest expense	(690	)	(565	)	(1,346	)	(1,051	)
Earnings before income taxes	1,230		1,534		1,667		2,677
Income tax recovery/(expense) (Note 12)	97		(293	)	170		(491	)
Earnings	1,327		1,241		1,837		2,186
Earnings attributable to noncontrolling interests and redeemable noncontrolling interests	(167	)	(241	)	(143	)	(465	)
Earnings attributable to controlling interests	1,160		1,000		1,694		1,721
Preference share dividends	(89	)	(81	)	(178	)	(164	)
Earnings attributable to common shareholders	1,071		919		1,516		1,557
Earnings per common share attributable to common shareholders (Note 5)	0.63		0.56		0.90		1.11
Diluted earnings per common share attributable to common shareholders (Note 5)	0.63		0.56		0.90		1.10

See accompanying notes to the interim consolidated financial statements.

ENBRIDGE INC.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME



	Three months ended June 30,				Six months ended June 30,
	2018		2017		2018		2017
(unaudited; millions of Canadian dollars)
Earnings	1,327		1,241		1,837		2,186
Other comprehensive income/(loss), net of tax
Change in unrealized gain/(loss) on cash flow hedges	27		(85	)	93		(87	)
Change in unrealized gain/(loss) on net investment hedges	(99	)	171		(283	)	220
Other comprehensive income from equity investees	5		2		19		8
Reclassification to earnings of loss on cash flow hedges	36		66		73		107
Reclassification to earnings of pension and other postretirement benefits (OPEB) amounts	62		3		23		7
Foreign currency translation adjustments	1,047		(1,443	)	2,626		(1,011	)
Other comprehensive income/(loss), net of tax	1,078		(1,286	)	2,551		(756	)
Comprehensive income/(loss)	2,405		(45	)	4,388		1,430
Comprehensive (income)/loss attributable to noncontrolling interests and redeemable noncontrolling interests	(297	)	15		(444	)	(359	)
Comprehensive income/(loss) attributable to controlling interests	2,108		(30	)	3,944		1,071
Preference share dividends	(89	)	(81	)	(178	)	(164	)
Comprehensive income/(loss) attributable to common shareholders	2,019		(111	)	3,766		907

See accompanying notes to the interim consolidated financial statements.

ENBRIDGE INC.

CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY



	Six months ended June 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	790		538
Shares issued on exercise of stock options	21		45
Balance at end of period	51,548		48,504
Additional paid-in capital
Balance at beginning of period	3,194		3,399
Stock-based compensation	34		51
Fair value of outstanding earned stock-based compensation from Merger Transaction	—		77
Options exercised	(10	)	(53	)
Enbridge Energy Company, Inc. common control transaction	—		118
Dilution loss on Enbridge Energy Partners, L.P. issuance of Class A units	—		(870	)
Dilution gain on Spectra Energy Partners, LP restructuring (Note 10)	1,136		—
Dilution gains/(losses) and other	(43	)	357
Balance at end of period	4,311		3,079
Deficit
Balance at beginning of period	(2,468	)	(716	)
Earnings attributable to controlling interests	1,694		1,721
Preference share dividends	(178	)	(164	)
Common share dividends declared	(1,145	)	(1,551	)
Dividends paid to reciprocal shareholder	17		15
Modified retrospective adoption of accounting standard (Note 2)	(86	)	—
Redemption value adjustment attributable to redeemable noncontrolling interests	(483	)	189
Adjustment for the recognition of unutilized tax deductions for stock-based compensation expense	—		41
Balance at end of period	(2,649	)	(465	)
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	2,250		(650	)
Balance at end of period	1,277		408
Reciprocal shareholding
Balance at beginning and end of period	(102	)	(102	)
Total Enbridge Inc. shareholders’ equity	62,132		58,679
Noncontrolling interests
Balance at beginning of period	7,597		577
Earnings attributable to noncontrolling interests	129		371
Other comprehensive income/(loss) attributable to noncontrolling interests, net of tax
Change in unrealized gain/(loss) on cash flow hedges	6		(19	)
Foreign currency translation adjustments	229		(112	)
Reclassification to earnings of loss on cash flow hedges	15		23
	250		(108	)
Comprehensive income attributable to noncontrolling interests	379		263
Noncontrolling interests resulting from Merger Transaction	—		8,792
Enbridge Energy Company, Inc. common control transaction	—		(331	)
Dilution gain on Enbridge Energy Partners, L.P. issuance of Class A units	—		870
Spectra Energy Partners, LP restructuring (Note 10)	(1,486	)	—
Distributions	(425	)	(386	)
Contributions	21		453
Other	14		13
Balance at end of period	6,100		10,251
Total equity	68,232		68,930
Dividends paid per common share	1.342		1.193

See accompanying notes to the interim consolidated financial statements.

ENBRIDGE INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS



	Six months ended June 30,
	2018		2017
(unaudited; millions of Canadian dollars)
Operating activities
Earnings	1,837		2,186
Adjustments to reconcile earnings to net cash provided by operating activities:
Depreciation and amortization	1,653		1,540
Deferred income tax (recovery)/expense	(328	)	416
Changes in unrealized (gain)/loss on derivative instruments, net (Note 11)	549		(898	)
Earnings from equity investments	(698	)	(472	)
Distributions from equity investments	732		513
Asset impairment	1,072		—
(Gain)/loss on dispositions	11		(83	)
Other	110		48
Changes in operating assets and liabilities	1,600		497
Net cash provided by operating activities	6,538		3,747
Investing activities
Capital expenditures	(3,243	)	(3,922	)
Long-term investments	(592	)	(2,778	)
Distributions from equity investments in excess of cumulative earnings (Note 7)	1,140		39
Additions to intangible assets	(425	)	(463	)
Cash acquired in Merger Transaction	—		681
Proceeds from dispositions	4		442
Reimbursement of capital expenditures	—		212
Other	(23	)	(40	)
Net cash used in investing activities	(3,139	)	(5,829	)
Financing activities
Net change in short-term borrowings	(433	)	253
Net change in commercial paper and credit facility draws	(2,166	)	1,773
Debenture and term note issues, net of issue costs	3,537		3,175
Debenture and term note repayments	(2,147	)	(2,184	)
Purchase of interest in consolidated subsidiary	—		(227	)
Contributions from noncontrolling interests	21		453
Distributions to noncontrolling interests	(425	)	(466	)
Contributions from redeemable noncontrolling interests	41		600
Distributions to redeemable noncontrolling interests	(174	)	(117	)
Common shares issued	14		9
Preference share dividends	(174	)	(164	)
Common share dividends	(1,493	)	(1,427	)
Net cash provided by/(used in) financing activities	(3,399	)	1,678
Effect of translation of foreign denominated cash and cash equivalents and restricted cash	35		(32	)
Net increase/(decrease) in cash and cash equivalents and restricted cash	35		(436	)
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	622		1,126

See accompanying notes to the interim consolidated financial statements.

ENBRIDGE INC.

CONSOLIDATED STATEMENTS OF FINANCIAL POSITION



	June 30, 2018		December 31, 2017
(unaudited; millions of Canadian dollars; number of shares in millions)
Assets
Current assets
Cash and cash equivalents	457		480
Restricted cash	165		107
Accounts receivable and other	6,100		7,053
Accounts receivable from affiliates	57		47
Inventory	1,205		1,528
	7,984		9,215
Property, plant and equipment, net	94,058		90,711
Long-term investments	16,391		16,644
Restricted long-term investments	286		267
Deferred amounts and other assets	6,498		6,442
Intangible assets, net	3,556		3,267
Goodwill	35,436		34,457
Deferred income taxes	1,227		1,090
Total assets	165,436		162,093

Liabilities and equity
Current liabilities
Short-term borrowings	1,014		1,444
Accounts payable and other	7,615		9,478
Accounts payable to affiliates	177		157
Interest payable	696		634
Environmental liabilities	32		40
Current portion of long-term debt	4,779		2,871
	14,313		14,624
Long-term debt	59,940		60,865
Other long-term liabilities	8,589		7,510
Deferred income taxes	9,929		9,295
	92,771		92,294
Contingencies (Note 14)
Redeemable noncontrolling interests	4,433		4,067
Equity
Share capital
Preference shares	7,747		7,747
Common shares (1,715 and 1,695 outstanding at June 30, 2018 and December 31, 2017, respectively)	51,548		50,737
Additional paid-in capital	4,311		3,194
Deficit	(2,649	)	(2,468	)
Accumulated other comprehensive income/(loss) (Note 9)	1,277		(973	)
Reciprocal shareholding	(102	)	(102	)
Total Enbridge Inc. shareholders’ equity	62,132		58,135
Noncontrolling interests	6,100		7,597
	68,232		65,732
Total liabilities and equity	165,436		162,093

See accompanying notes to the interim consolidated financial statements.

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.

Effective September 30, 2017, we combined Cash and cash equivalents and amounts previously presented as Bank indebtedness where the corresponding bank accounts are subject to cash pooling arrangements. As at December 31, 2017, $0.6 billion of Bank indebtedness has been combined within Cash and cash equivalents in our Consolidated Statements of Financial Position. Net cash provided by financing activities in our Consolidated Statements of Cash Flows for the six months ended June 30, 2017 has been reduced by $0.4 billion to reflect this change.

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 six months ended June 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. Further, a subsidiary's debt repayment in the amount of $941 million during the three months ended June 30, 2017 has been reclassified within financing activities to conform to our current classification of such payments.

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 allow a reclassification from accumulated other comprehensive income to retained earnings for stranded tax effects resulting from the TCJA. The amendments will eliminate the stranded tax effects as a result of the reduction of the historical United States federal corporate income tax rate to the newly enacted United States federal corporate income tax rate. The adoption of this accounting update did not have a material impact on our consolidated financial statements.

Clarifying Guidance on the Application of Modification Accounting on Stock Compensation

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

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

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

Clarifying Guidance on Derecognition and Partial Sales of Nonfinancial Assets

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

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

Effective January 1, 2018, we adopted ASU 2016-18 on a retrospective basis. The new standard clarifies guidance on the classification and presentation of changes in restricted cash and restricted cash equivalents within the statement of cash flows. The amendments require that changes in restricted cash and restricted cash equivalents be included within cash and cash equivalents when reconciling the opening and closing period amounts shown on the statement of cash flows. For current and comparative periods, we amended the presentation in the Consolidated Statements of Cash Flows to include restricted cash and restricted cash equivalents with cash and cash equivalents.

Simplifying Cash Flow Classification

Effective January 1, 2018, we adopted ASU 2016-15 on a retrospective basis. The new standard reduces diversity in practice of how certain cash receipts and cash payments are classified in the Consolidated Statements of Cash Flows. The new guidance addresses eight specific presentation issues. We assessed each of the eight specific presentation issues and the adoption of this ASU did not have a material impact on our consolidated financial statements.

Recognition and Measurement of Financial Assets and Liabilities

Effective January 1, 2018, we adopted ASU 2016-01 on a prospective basis. The new standard addresses certain aspects of recognition, measurement, presentation and disclosure of financial assets and liabilities. Investments in equity securities, excluding equity method and consolidated investments, are no longer classified as trading or available-for-sale securities. All investments in equity securities with readily determinable fair values are classified as investments at fair value through net income. Investments in equity securities without readily determinable fair values are measured using the fair value measurement alternative and are recorded at cost minus impairment, if any, plus or minus changes resulting from observable price changes in orderly transactions for an identical or similar investment of the same issuer. Investments in equity securities measured using the fair value measurement alternative are reviewed for indicators of impairment each reporting period. Fair value of financial assets and liabilities is

measured using the exit price notion. The adoption of this accounting update did not have a material impact on our consolidated financial statements.

Revenue from Contracts with Customers

Effective January 1, 2018, we adopted ASU 2014-09 on a modified retrospective basis to contracts that were not complete at the date of initial application. The new standard was issued with the intent of significantly enhancing consistency and comparability of revenue recognition practices across entities and industries. The new standard establishes a single, principles-based five-step model to be applied to all contracts with customers and introduces new and enhanced disclosure requirements. It also requires the use of more estimates and judgments than the previous standards.

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

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

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

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.

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 permits entities not to reassess whether any expired or existing contracts contain leases, their lease classification, as well as any related initial direct costs.

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.

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 changes to our financial statements relate to the recognition of a lease liability and offsetting right-of-use asset in our consolidated balance sheet 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.

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 June 30, 2018	Liquids Pipelines		Gas Transmission and Midstream		Gas Distribution	Green Power and Transmission	Energy Services	Eliminations and Other		Consolidated
(millions of Canadian dollars)
Transportation revenue	2,079		958		151	—	—	—		3,188
Storage and other revenue	42		51		52	—	—	—		145
Gas gathering and processing revenue	—		231		—	—	—	—		231
Gas distribution revenue	—		—		856	—	—	—		856
Electricity and transmission revenue	—		—		—	148	—	—		148
Commodity sales	—		639		—	—	—	—		639
Total revenue from contracts with customers	2,121		1,879		1,059	148	—	—		5,207
Commodity sales	—		—		—	—	5,812	—		5,812
Other revenue¹	(261	)	(17	)	9	1	—	(6	)	(274	)
Intersegment revenue	90		2		2	—	24	(118	)	—
Total revenue	1,950		1,864		1,070	149	5,836	(124	)	10,745



	Liquids Pipelines		Gas Transmission and Midstream	Gas Distribution	Green Power and Transmission	Energy Services	Eliminations and Other		Consolidated
Six months ended June 30, 2018	Liquids Pipelines		Gas Transmission and Midstream	Gas Distribution	Green Power and Transmission	Energy Services	Eliminations and Other		Consolidated
(millions of Canadian dollars)
Transportation revenue	4,137		1,910	390	—	—	—		6,437
Storage and other revenue	82		111	118	—	—	—		311
Gas gathering and processing revenue	—		436	—	—	—	—		436
Gas distribution revenue	—		—	2,782	—	—	—		2,782
Electricity and transmission revenue	—		—	—	302	—	—		302
Commodity sales	—		1,332	—	—	—	—		1,332
Total revenue from contracts with customers	4,219		3,789	3,290	302	—	—		11,600
Commodity sales	—		—	—	—	12,387	—		12,387
Other revenue¹	(530	)	8	11	4	—	(9	)	(516	)
Intersegment revenue	170		4	6	—	81	(261	)	—
Total revenue	3,859		3,801	3,307	306	12,468	(270	)	23,471


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

Contract assets represent the amount of revenue which has been recognized in advance of payments received for performance obligations we have fulfilled (or partially fulfilled) and prior to the point in time at

which our right to the payment is unconditional. Amounts included in contract assets are transferred to accounts receivable when our right to the consideration becomes unconditional.

Contract liabilities represent payments received for performance obligations which have not been fulfilled. Contract liabilities primarily relate to make-up rights and deferred revenue. Revenue recognized during the three and six months ended June 30, 2018 included in contract liabilities at the beginning of the period is $29 million and $124 million, respectively. Increases in contract liabilities from cash received, net of amounts recognized as revenue during the three and six months ended June 30, 2018 were $103 million and $198 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
Green Power and Transmission	• Delivery of electricity from renewable energy generation facilities

There was no material revenue recognized in the three and six months ended June 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 $65.7 billion, of which $3.5 billion and $6.0 billion is expected to be recognized during the six months ending December 31, 2018 and 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

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 June 30, 2018	Liquids Pipelines	Gas Transmission and Midstream	Gas Distribution	Green Power and Transmission	Energy Services	Consolidated
(millions of Canadian dollars)
Revenue from products transferred at a point in time¹	—	639	20	—	—	659
Revenue from products and services transferred over time²	2,121	1,240	1,039	148	—	4,548
Total revenue from contracts with customers	2,121	1,879	1,059	148	—	5,207



	Liquids Pipelines	Gas Transmission and Midstream	Gas Distribution	Green Power and Transmission	Energy Services	Consolidated
Six months ended June 30, 2018	Liquids Pipelines	Gas Transmission and Midstream	Gas Distribution	Green Power and Transmission	Energy Services	Consolidated
(millions of Canadian dollars)
Revenue from products transferred at a point in time¹	—	1,332	45	—	—	1,377
Revenue from products and services transferred over time²	4,219	2,457	3,245	302	—	10,223
Total revenue from contracts with customers	4,219	3,789	3,290	302	—	11,600


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

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 June 30, 2018	Liquids Pipelines		Gas Transmission and Midstream		Gas Distribution		Green Power and Transmission		Energy Services		Eliminations and Other		Consolidated
(millions of Canadian dollars)
Revenues	1,950		1,864		1,070		149		5,836		(124	)	10,745
Commodity and gas distribution costs	(5	)	(591	)	(444	)	—		(5,784	)	125		(6,699	)
Operating and administrative	(714	)	(534	)	(271	)	(36	)	(21	)	(60	)	(1,636	)
Asset impairment	(10	)	—		—		—		—		—		(10	)
Income/(loss) from equity investments	137		229		(10	)	4		3		—		363
Other income/(expense)	(36	)	46		25		9		1		(59	)	(14	)
Earnings/(loss) before interest, income taxes, and depreciation and amortization	1,322		1,014		370		126		35		(118	)	2,749
Depreciation and amortization													(829	)
Interest expense													(690	)
Income tax recovery													97
Earnings													1,327
Capital expenditures¹	510		867		239		10		—		2		1,628



	Liquids Pipelines		Gas Transmission and Midstream		Gas Distribution		Green Power and Transmission		Energy Services		Eliminations and Other		Consolidated
Three months ended June 30, 2017	Liquids Pipelines		Gas Transmission and Midstream		Gas Distribution		Green Power and Transmission		Energy Services		Eliminations and Other		Consolidated
(millions of Canadian dollars)
Revenues	2,243		1,954		1,022		140		5,855		(98	)	11,116
Commodity and gas distribution costs	(5	)	(703	)	(452	)	2		(5,862	)	102		(6,918	)
Operating and administrative	(684	)	(553	)	(241	)	(41	)	(11	)	(116	)	(1,646	)
Income/(loss) from equity investments	108		155		(23	)	—		—		(4	)	236
Other income/(expense)	(5	)	79		4		—		1		100		179
Earnings/(loss) before interest, income taxes, and depreciation and amortization	1,657		932		310		101		(17	)	(16	)	2,967
Depreciation and amortization													(868	)
Interest expense													(565	)
Income tax expense													(293	)
Earnings													1,241
Capital expenditures¹	540		1,374		309		115		1		9		2,348



	Liquids Pipelines		Gas Transmission and Midstream		Gas Distribution		Green Power and Transmission		Energy Services		Eliminations and Other		Consolidated
Six months ended June 30, 2018	Liquids Pipelines		Gas Transmission and Midstream		Gas Distribution		Green Power and Transmission		Energy Services		Eliminations and Other		Consolidated
(millions of Canadian dollars)
Revenues	3,859		3,801		3,307		306		12,468		(270	)	23,471
Commodity and gas distribution costs	(9	)	(1,211	)	(1,832	)	—		(12,239	)	271		(15,020	)
Operating and administrative	(1,461	)	(1,041	)	(519	)	(66	)	(33	)	(157	)	(3,277	)
Asset impairment	(154	)	(913	)	—		—		—		(5	)	(1,072	)
Income/(loss) from equity investments	268		437		7		(21	)	7		—		698
Other income/(expense)	(25	)	67		43		16		1		(236	)	(134	)
Earnings/(loss) before interest, income taxes, and depreciation and amortization	2,478		1,140		1,006		235		204		(397	)	4,666
Depreciation and amortization													(1,653	)
Interest expense													(1,346	)
Income tax recovery													170
Earnings													1,837
Capital expenditures¹	1,125		1,692		422		24		—		8		3,271



	Liquids Pipelines		Gas Transmission and Midstream		Gas Distribution		Green Power and Transmission		Energy Services		Eliminations and Other		Consolidated
Six months ended June 30, 2017	Liquids Pipelines		Gas Transmission and Midstream		Gas Distribution		Green Power and Transmission		Energy Services		Eliminations and Other		Consolidated
(millions of Canadian dollars)
Revenues	4,398		3,189		2,606		277		11,988		(196	)	22,262
Commodity and gas distribution costs	(8	)	(1,350	)	(1,498	)	3		(11,830	)	200		(14,483	)
Operating and administrative	(1,444	)	(807	)	(430	)	(81	)	(23	)	(412	)	(3,197	)
Income from equity investments	194		265		13		2		2		(4	)	472
Other income/(expense)	(3	)	110		6		1		2		98		214
Earnings/(loss) before interest, income taxes, and depreciation and amortization	3,137		1,407		697		202		139		(314	)	5,268
Depreciation and amortization													(1,540	)
Interest expense													(1,051	)
Income tax expense													(491	)
Earnings													2,186
Capital expenditures¹	1,194		2,029		492		229		1		68		4,013


1	Includes allowance for equity funds used during construction.

TOTAL ASSETS



	June 30, 2018	December 31, 2017
(millions of Canadian dollars)
Liquids Pipelines	65,740	63,881
Gas Transmission and Midstream	62,693	60,745
Gas Distribution	25,581	25,956
Green Power and Transmission	6,239	6,289
Energy Services	1,993	2,514
Eliminations and Other	3,190	2,708
	165,436	162,093


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 six months ended June 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 June 30,		Six months ended June 30,
	2018	2017	2018	2017
(number of common shares in millions)
Weighted average shares outstanding	1,695	1,628	1,690	1,404
Effect of dilutive options	3	8	3	9
Diluted weighted average shares outstanding	1,698	1,636	1,693	1,413

For the three months ended June 30, 2018 and 2017, 30,245,645 and 13,416,763, respectively, of anti-dilutive stock options with a weighted average exercise price of $49.67 and $57.98, respectively, were excluded from the diluted earnings per common share calculation.

For the six months ended June 30, 2018 and 2017, 30,063,894 and 13,480,978, respectively, of anti-dilutive stock options with a weighted average exercise price of $49.73 and $57.84, respectively, were excluded from the diluted earnings per common share calculation.


6.	DISPOSITIONS

ASSETS HELD FOR SALE

Midcoast Operating, L.P.

On May 9, 2018, our indirect subsidiary, Enbridge (U.S.) Inc. entered into a definitive agreement to sell Midcoast Operating, L.P. and its subsidiaries (collectively, MOLP) to AL Midcoast Holdings, LLC (an affiliate of ArcLight Capital Partners, LLC) for a cash purchase price of approximately US$1.1 billion, subject to customary closing adjustments.

On August 1, 2018, Enbridge (U.S.) Inc. closed the sale of MOLP for total cash proceeds of approximately US$1.1 billion less deposits and other customary closing items. 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.

As at December 31, 2017, the MOLP assets, excluding our equity method investment in the Texas Express NGL pipeline system, were classified as held for sale and were measured at the lower of their carrying value or fair value less costs to sell.

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 six months ended June 30, 2018.

In the second quarter of 2018, our equity method investment in the Texas Express NGL pipeline system, together with the MOLP assets, 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.

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., 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 six months ended June 30, 2018.

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



	June 30, 2018		December 31, 2017
(millions of Canadian dollars)
Accounts receivable and other (current assets held for sale)	363		424
Deferred amounts and other assets (long-term assets held for sale)	1,186		1,190
Accounts payable and other (current liabilities held for sale)	(348	)	(315	)
Other long-term liabilities (long-term liabilities held for sale)	(43	)	(34	)
Net assets held for sale	1,158		1,265

OTHER

Canadian Natural Gas Gathering and Processing Businesses

On July 4, 2018, we entered into agreements with Brookfield Infrastructure Partners L.P. and its institutional partners to sell our Canadian natural gas gathering and processing businesses for a cash purchase price of approximately $4.31 billion, subject to customary closing adjustments and receipt of regulatory approvals. Separate agreements were entered into for those facilities currently governed by provincial regulations and those governed by federal regulations. The sale of the provincially regulated

facilities is expected to close in 2018 for proceeds of approximately $2.5 billion and the sale of the federally regulated facilities is expected to close in mid-2019 for proceeds of approximately $1.8 billion.

Renewable Energy Generation Assets

On May 9, 2018, we entered into agreements with the Canadian Pension Plan Investment Board (CPPIB) to sell a 49% interest in all of our Canadian renewable energy generation assets, 49% of two large 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). Proceeds from the transaction are approximately $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 continue to manage, operate and provide administrative services for these assets.

On August 1, 2018, we closed the sale of the Renewable Assets for total cash proceeds of $1.75 billion less customary closing items. These assets were a part of our Green Power and Transmission segment.

Also during the second quarter of 2018, a deferred income tax recovery of $258 million ($190 million attributable to us) was recorded in the three and six months ended June 30, 2018 as a result of the agreement entered into for the Renewable Assets (Note 12).


7.	VARIABLE INTEREST ENTITIES

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 partners as a partial reimbursement of construction and development costs incurred by the partners. 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 six months ended June 30, 2018.

As at June 30, 2018, Sabal Trail is no longer a variable interest entity due to sufficient equity at risk to finance its activities based on reconsideration events related to Sabal Trail's debt issuance and the distributions made to its partners.


8.	DEBT

CREDIT FACILITIES

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



		June 30, 2018
	Maturity	Total Facilities	Draws¹	Available
(millions of Canadian dollars)
Enbridge Inc.²	2019-2022	6,537	1,761	4,776
Enbridge (U.S.) Inc.	2019	1,861	456	1,405
Enbridge Energy Partners, L.P.³	2019-2022	3,453	2,261	1,192
Enbridge Gas Distribution Inc. (EGD)	2019	1,017	794	223
Enbridge Income Fund	2020	1,500	351	1,149
Enbridge Pipelines Inc.	2019	3,000	1,906	1,094
Spectra Energy Partners, LP⁴	2022	3,289	1,528	1,761
Union Gas Limited (Union Gas)	2021	700	230	470
Total committed credit facilities		21,357	9,287	12,070


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


2	Includes $135 million, $164 million (US$125 million) and $150 million of commitments that expire in 2018, 2018 and 2020, respectively.


3	Includes $230 million (US$175 million) and $243 million (US$185 million) of commitments that expire in 2018 and 2020, respectively.


4	Includes $443 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 set 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 set to mature in 2019, and repaid drawn amounts. In addition, Enbridge (U.S.) Inc. terminated an unutilized US$950 million credit facility, which was set 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 set to mature in 2021.

In addition to the committed credit facilities noted above, we maintain $796 million of uncommitted demand credit facilities, of which $517 million were unutilized as at June 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 set to mature from 2019 to 2022.

As at June 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 $7,862 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 six months ended June 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 notes due 2078¹	US$850
	April 2018	Fixed-to-floating rate notes due 2078²	$750
	April 2018	Fixed-to-floating rate 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.

LONG-TERM DEBT REPAYMENTS

During the six months ended June 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
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
Union Gas Limited
	April 2018	5.35% medium-term notes	$200
Westcoast Energy Inc.
	May 2018	6.90% senior secured notes	$13
	May 2018	4.34% senior secured notes	$4


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


2	The loss on debt extinguishment of $37 million (US$29 million), net of the fair value adjustment recorded upon completion of the Merger Transaction, was reported within Interest expense in the Consolidated Statements of Earnings.

FAIR VALUE ADJUSTMENT

As at June 30, 2018, the net fair value adjustment for total debt assumed in the Merger Transaction was $1,015 million. During the three and six months ended June 30, 2018, the amortization of the fair value adjustment, recorded as a reduction to Interest expense in the Consolidated Statements of Earnings, was $26 million and $88 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 June 30, 2018, we were in compliance with all debt covenants.


9.	COMPONENTS OF ACCUMULATED OTHER COMPREHENSIVE INCOME

Changes in Accumulated other comprehensive income (AOCI) attributable to our common shareholders for the six months ended June 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	100		(328	)	2,354	3	—		2,129
Other comprehensive (income)/loss reclassified to earnings
Interest rate contracts¹	67		—		—	—	—		67
Commodity contracts²	(1	)	—		—	—	—		(1	)
Foreign exchange contracts³	5		—		—	—	—		5
Other contracts⁴	3		—		—	—	—		3
Amortization of pension and OPEB actuarial loss and prior service costs⁵	—		—		—	—	31		31
	174		(328	)	2,354	3	31		2,234
Tax impact
Income tax on amounts retained in AOCI	(13	)	45		—	10	—		42
Income tax on amounts reclassified to earnings	(18	)	—		—	—	(8	)	(26	)
	(31	)	45		—	10	(8	)	16
Balance as at June 30, 2018	(501	)	(422	)	2,431	23	(254	)	1,277



	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	(44	)	222		(899	)	3	—		(718	)
Other comprehensive (income)/loss reclassified to earnings
Interest rate contracts¹	71		—		—		—	—		71
Commodity contracts²	(4	)	—		—		—	—		(4	)
Foreign exchange contracts³	2		—		—		—	—		2
Amortization of pension and OPEB actuarial loss and prior service costs⁵	—		—		—		—	10		10
	25		222		(899	)	3	10		(639	)
Tax impact
Income tax on amounts retained in AOCI	12		(2	)	—		5	—		15
Income tax on amounts reclassified to earnings	(23	)	—		—		—	(3	)	(26	)
	(11	)	(2	)	—		5	(3	)	(11	)
Balance as at June 30, 2017	(732	)	(409	)	1,801		45	(297	)	408


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.

10. NONCONTROLLING INTERESTS

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 taxes of $1.1 billion and $333 million, respectively, for the six months ended June 30, 2018.

11. RISK MANAGEMENT AND FINANCIAL INSTRUMENTS

MARKET RISK

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

The following summarizes the types of market risks to which 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%.

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 is 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 in the event of these specific circumstances. All amounts are presented gross in the Consolidated Statements of Financial Position.



June 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	—		2		—		72		74		(48	)	26
Interest rate contracts	37		—		—		—		37		(5	)	32
Commodity contracts	—		—		—		112		112		(74	)	38
	37		2		—		184		223		(127	)	96
Deferred amounts and other assets
Foreign exchange contracts	13		—		—		39		52		(34	)	18
Interest rate contracts	19		—		—		—		19		—		19
Commodity contracts	16		—		—		15		31		(29	)	2
Other contracts	1		—		—		—		1		(1	)	—
	49		—		—		54		103		(64	)	39
Accounts payable and other
Foreign exchange contracts	(5	)	(25	)	—		(396	)	(426	)	48		(378	)
Interest rate contracts	(87	)	—		(4	)	(185	)	(276	)	5		(271	)
Commodity contracts	(1	)	—		—		(289	)	(290	)	74		(216	)
Other contracts	(1	)	—		—		(3	)	(4	)	—		(4	)
	(94	)	(25	)	(4	)	(873	)	(996	)	127		(869	)
Other long-term liabilities
Foreign exchange contracts	—		(12	)	—		(1,746	)	(1,758	)	34		(1,724	)
Interest rate contracts	(10	)	—		(9	)	—		(19	)	—		(19	)
Commodity contracts	—		—		—		(158	)	(158	)	29		(129	)
Other contracts	(1	)	—		—		(1	)	(2	)	1		(1	)
	(11	)	(12	)	(9	)	(1,905	)	(1,937	)	64		(1,873	)
Total net derivative asset/(liability)
Foreign exchange contracts	8		(35	)	—		(2,031	)	(2,058	)	—		(2,058	)
Interest rate contracts	(41	)	—		(13	)	(185	)	(239	)	—		(239	)
Commodity contracts	15		—		—		(320	)	(305	)	—		(305	)
Other contracts	(1	)	—		—		(4	)	(5	)	—		(5	)
	(19	)	(35	)	(13	)	(2,540	)	(2,607	)	—		(2,607	)

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