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ENBRIDGE INC - Quarter Report: 2019 June (Form 10-Q)


 

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM
10-Q
 
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended June 30, 2019
OR
 
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
 
enblogocoloura80.jpg
 
ENBRIDGE INC
(Exact Name of Registrant as Specified in Its Charter)
Canada
 
98-0377957
(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)
_______________________________
Securities registered pursuant to Section 12(b) of the Act:
Title of each class
 
Trading Symbol(s)
 
Name of each exchange on which registered
Common Shares
 
ENB
 
New York Stock Exchange
6.375% Fixed-to-Floating Rate Subordinated Notes Series 2018-B due 2078
 
ENBA
 
New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act: None
 
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 
Non-accelerated filer 
 
Smaller reporting company
Emerging growth company 
 
  
 
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 No x
The registrant had 2,023,832,187 common shares outstanding as at July 26, 2019.
 


1


 
 
Page
 
PART I
  
Item 1.
Item 2.
Item 3.
Item 4.
 
PART II
 
Item 1.
Item 1A.
Item 2.
Item 3.
Item 4.
Item 5.
Item 6.
 



2


GLOSSARY
 
 
 
AOCI
Accumulated other comprehensive income/(loss)
Army Corps
United States Army Corps of Engineers
ASC
Accounting Standards Codification
ASU
Accounting Standards Update
EBITDA
Earnings before interest, income taxes and depreciation and amortization
EEP
Enbridge Energy Partners, L.P.
Enbridge
Enbridge Inc.
Merger Transaction
Combination of Enbridge and Spectra Energy through a stock-for-stock merger transaction which closed on February 27, 2017
MNPUC
Minnesota Public Utilities Commission
MOLP
Midcoast Operating, L.P. and its subsidiaries
NGL
Natural gas liquids
OCI
Other comprehensive income/(loss)
SEP
Spectra Energy Partners, LP
VIE
Variable Interest Entity


3


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 our 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, Renewable Power Generation 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 completed 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 transactions undertaken to simplify our corporate structure; our dividend payout policy; dividend growth and dividend payout expectation; expectations on impact of our 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


4


respect to the impact of the Merger Transaction on us, expected EBITDA, expected earnings/(loss), expected earnings/(loss) per share, or estimated future dividends. The most relevant assumptions associated with forward-looking statements regarding 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, changes in regulations applicable to our business, dispositions, the transactions undertaken to simplify our corporate structure, our 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 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.



5


PART I - FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

ENBRIDGE INC.
CONSOLIDATED STATEMENTS OF EARNINGS

 
Three months ended
June 30,
 
Six months ended
June 30,
 
2019

2018

 
2019

2018

(unaudited; millions of Canadian dollars, except per share amounts)
 

 

 
 

 

Operating revenues
 

 

 
 

 

Commodity sales
8,416

6,451

 
15,048

13,719

Gas distribution sales
755

856

 
2,631

2,782

Transportation and other services
4,092

3,438

 
8,440

6,970

Total operating revenues (Note 3)
13,263

10,745

 
26,119

23,471

Operating expenses
 
 
 
 
 
Commodity costs
8,129

6,278

 
14,694

13,275

Gas distribution costs
312

421

 
1,519

1,745

Operating and administrative
1,695

1,636

 
3,320

3,277

Depreciation and amortization
842

829


1,682

1,653

Impairment of long-lived assets

10

 

1,072

Total operating expenses
10,978

9,174

 
21,215

21,022

Operating income
2,285

1,571

 
4,904

2,449

Income from equity investments
413

363

 
826

698

Other income/(expense)
 
 
 
 
 
Net foreign currency gain/(loss)
140

(43
)
 
354

(228
)
Other
65

29

 
111

94

Interest expense
(637
)
(690
)

(1,322
)
(1,346
)
Earnings before income taxes
2,266

1,230

 
4,873

1,667

Income tax (expense)/recovery (Note 12)
(436
)
97


(1,020
)
170

Earnings
1,830

1,327

 
3,853

1,837

(Earnings)/loss attributable to noncontrolling interests and redeemable noncontrolling interests
2

(167
)

(35
)
(143
)
Earnings attributable to controlling interests
1,832

1,160

 
3,818

1,694

Preference share dividends
(96
)
(89
)

(191
)
(178
)
Earnings attributable to common shareholders
1,736

1,071


3,627

1,516

Earnings per common share attributable to common shareholders (Note 5)
0.86

0.63


1.80

0.90

Diluted earnings per common share attributable to common shareholders (Note 5)
0.86

0.63

 
1.80

0.90

See accompanying notes to the interim consolidated financial statements.




6


ENBRIDGE INC.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

 
Three months ended
June 30,
 
Six months ended
June 30,
 
2019

2018

 
2019

2018

(unaudited; millions of Canadian dollars)
 

 

 
 

 

Earnings
1,830

1,327

 
3,853

1,837

Other comprehensive income/(loss), net of tax
 
 
 
 
 
Change in unrealized gain/(loss) on cash flow hedges
(235
)
27

 
(427
)
93

Change in unrealized gain/(loss) on net investment hedges
127

(99
)
 
221

(283
)
Other comprehensive income from equity investees
5

5

 
17

19

Reclassification to earnings of loss on cash flow hedges
35

36

 
46

73

Reclassification to earnings of pension and other postretirement benefits (OPEB) amounts
5

62

 
43

23

Foreign currency translation adjustments
(1,311
)
1,047

 
(2,602
)
2,626

Other comprehensive income/(loss), net of tax
(1,374
)
1,078


(2,702
)
2,551

Comprehensive income
456

2,405

 
1,151

4,388

Comprehensive (income)/loss attributable to noncontrolling interests and redeemable noncontrolling interests
51

(297
)
 
64

(444
)
Comprehensive income attributable to controlling interests
507

2,108

 
1,215

3,944

Preference share dividends
(96
)
(89
)
 
(191
)
(178
)
Comprehensive income attributable to common shareholders
411

2,019

 
1,024

3,766

See accompanying notes to the interim consolidated financial statements.


7


ENBRIDGE INC.
CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
 
Three months ended
June 30,
Six months ended
June 30,
 
2019

2018

2019

2018

(unaudited; millions of Canadian dollars, except per share amounts)
 
 
 

 

Preference shares (Note 5)
 
 
 
 
Balance at beginning and end of period
7,747

7,747

7,747

7,747

Common shares (Note 5)
 
 
 

 

Balance at beginning of period
64,728

51,127

64,677

50,737

Dividend Reinvestment and Share Purchase Plan

416


790

Shares issued on exercise of stock options
4

5

55

21

Balance at end of period
64,732

51,548

64,732

51,548

Additional paid-in capital
 
 
 

 

Balance at beginning of period
72

4,313


3,194

Stock-based compensation
17

17

21

34

Options exercised
(6
)
(4
)
(49
)
(10
)
Dilution gain on Spectra Energy Partners, LP restructuring



1,136

Change in reciprocal interest


109


Repurchase of noncontrolling interest
65


65


Other
46

(15
)
48

(43
)
Balance at end of period
194

4,311

194

4,311

Deficit
 
 
 

 

Balance at beginning of period
(3,640
)
(1,982
)
(5,538
)
(2,468
)
Earnings attributable to controlling interests
1,832

1,160

3,818

1,694

Preference share dividends
(96
)
(89
)
(191
)
(178
)
Dividends paid to reciprocal shareholder
4

10

9

17

Common share dividends declared
(1,500
)
(1,145
)
(1,500
)
(1,145
)
Modified retrospective adoption of ASC 606 Revenue from Contracts with Customers



(86
)
Redemption value adjustment attributable to redeemable noncontrolling interests

(603
)

(483
)
Other
8


10


Balance at end of period
(3,392
)
(2,649
)
(3,392
)
(2,649
)
Accumulated other comprehensive income/(loss) (Note 9)
 
 
 

 

Balance at beginning of period
1,449

329

2,672

(973
)
Other comprehensive income/(loss) attributable to common shareholders, net of tax
(1,325
)
948

(2,603
)
2,250

Other


55


Balance at end of period
124

1,277

124

1,277

Reciprocal shareholding
 
 
 

 

Balance at beginning of period
(51
)
(102
)
(88
)
(102
)
Change in reciprocal interest


37


Balance at end of period
(51
)
(102
)
(51
)
(102
)
Total Enbridge Inc. shareholders’ equity
69,354

62,132

69,354

62,132

Noncontrolling interests
 
 
 

 

Balance at beginning of period
3,614

6,082

3,965

7,597

Earnings/(loss) attributable to noncontrolling interests
(2
)
106

35

129

Other comprehensive income/(loss) attributable to noncontrolling interests, net of tax




 
 
Change in unrealized gain/(loss) on cash flow hedges
(4
)
2

(5
)
6

Foreign currency translation adjustments
(45
)
77

(94
)
229

Reclassification to earnings of loss on cash flow hedges

7


15

 
(49
)
86

(99
)
250

Comprehensive income/(loss) attributable to noncontrolling interests
(51
)
192

(64
)
379

Spectra Energy Partners, LP restructuring



(1,486
)
Contributions
6

13

9

21

Distributions
(54
)
(216
)
(100
)
(425
)
Repurchase of noncontrolling interest
(65
)

(65
)

Redemption of preferred shares held by subsidiary (Note 10)


(300
)

Other
1

29

6

14

Balance at end of period
3,451

6,100

3,451

6,100

Total equity
72,805

68,232

72,805

68,232

Dividends paid per common share
0.738

0.671

1.476

1.342

Earnings per common share attributable to common shareholders (Note 5)
0.86

0.63

1.80

0.90

Diluted earnings per common share attributable to common shareholders (Note 5)
0.86

0.63

1.80

0.90

See accompanying notes to the interim consolidated financial statements.


8


ENBRIDGE INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS

 
Six months ended
June 30,
 
2019

2018

(unaudited; millions of Canadian dollars)
 
 
Operating activities
 
 
Earnings
3,853

1,837

Adjustments to reconcile earnings to net cash provided by operating activities:
 

 

Depreciation and amortization
1,682

1,653

Deferred income tax (recovery)/expense
809

(328
)
Changes in unrealized (gain)/loss on derivative instruments, net (Note 11)
(1,112
)
549

Earnings from equity investments
(826
)
(698
)
Distributions from equity investments
907

732

Impairment of long-lived assets

1,072

Loss on dispositions

11

Other
36

110

Changes in operating assets and liabilities
(679
)
1,600

Net cash provided by operating activities
4,670

6,538

Investing activities
 

 

Capital expenditures
(2,785
)
(3,243
)
Long-term investments and restricted long-term investments
(700
)
(611
)
Distributions from equity investments in excess of cumulative earnings
268

1,140

Additions to intangible assets
(100
)
(425
)
Proceeds from dispositions

4

Other

(4
)
Affiliate loans, net
(140
)

Net cash used in investing activities
(3,457
)
(3,139
)
Financing activities
 

 

Net change in short-term borrowings
(108
)
(433
)
Net change in commercial paper and credit facility draws
4,015

(2,166
)
Debenture and term note issues, net of issue costs
1,195

3,537

Debenture and term note repayments
(2,584
)
(2,147
)
Contributions from noncontrolling interests
9

21

Distributions to noncontrolling interests
(100
)
(425
)
Contributions from redeemable noncontrolling interests

41

Distributions to redeemable noncontrolling interests

(174
)
Common shares issued
18

14

Preference share dividends
(191
)
(174
)
Common share dividends
(2,976
)
(1,493
)
Redemption of preferred shares held by subsidiary (Note 10)
(300
)

Other
(36
)

Net cash used in financing activities
(1,058
)
(3,399
)
Effect of translation of foreign denominated cash and cash equivalents and restricted cash
(25
)
35

Net increase in cash and cash equivalents and restricted cash
130

35

Cash and cash equivalents and restricted cash at beginning of period
637

587

Cash and cash equivalents and restricted cash at end of period
767

622

See accompanying notes to the interim consolidated financial statements.




9


ENBRIDGE INC.
CONSOLIDATED STATEMENTS OF FINANCIAL POSITION

 
June 30,
2019

December 31,
2018

(unaudited; millions of Canadian dollars; number of shares in millions)
 

 

Assets
 

 

Current assets
 

 

Cash and cash equivalents
708

518

Restricted cash
59

119

Accounts receivable and other
6,257

6,517

Accounts receivable from affiliates
85

79

Inventory
1,284

1,339

 
8,393

8,572

Property, plant and equipment, net
93,202

94,540

Long-term investments
16,531

16,707

Restricted long-term investments
389

323

Deferred amounts and other assets
9,552

8,558

Intangible assets, net
2,215

2,372

Goodwill
33,342

34,459

Deferred income taxes
1,204

1,374

Total assets
164,828

166,905

 
 
 
Liabilities and equity
 

 

Current liabilities
 

 

Short-term borrowings
916

1,024

Accounts payable and other
7,156

9,863

Accounts payable to affiliates
26

40

Interest payable
626

669

Current portion of long-term debt
4,644

3,259

 
13,368

14,855

Long-term debt
60,017

60,327

Other long-term liabilities
8,871

8,834

Deferred income taxes
9,767

9,454

 
92,023

93,470

Contingencies (Note 15)




Equity
 

 

Share capital
 

 

Preference shares
7,747

7,747

Common shares (2,024 and 2,022 outstanding at June 30, 2019 and December 31, 2018, respectively)
64,732

64,677

Additional paid-in capital
194


Deficit
(3,392
)
(5,538
)
Accumulated other comprehensive income (Note 9)
124

2,672

Reciprocal shareholding
(51
)
(88
)
Total Enbridge Inc. shareholders’ equity
69,354

69,470

Noncontrolling interests
3,451

3,965

 
72,805

73,435

Total liabilities and equity
164,828

166,905

See accompanying notes to the interim consolidated financial statements.



10


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 updated consolidated financial statements and notes for the year ended December 31, 2018. 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 audited updated consolidated financial statements for the year ended December 31, 2018, 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.

2. CHANGES IN ACCOUNTING POLICIES
 
ADOPTION OF NEW STANDARDS
Cloud Computing Arrangements
Effective January 1, 2019, we adopted Accounting Standards Update (ASU) 2018-15 on a prospective basis. The new standard was issued to provide guidance on the accounting for implementation costs incurred in a cloud computing arrangement that is a service contract. The ASU specifies that an entity would apply Accounting Standards Codification (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. The amendments in the update also require that the 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, in addition to specifying that the capitalized costs must be presented on the same balance sheet line as the prepayment of fees related to the hosting arrangement. The ASU requires similar consistency in classifications from a cash flow statement perspective. The adoption of this ASU did not have a material impact on our consolidated financial statements.

Improvements to Accounting for Hedging Activities
Effective January 1, 2019, we adopted ASU 2017-12 on a modified retrospective basis. The new standard was issued 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. As a result of the new standard, hedge ineffectiveness will no longer be measured or recorded, and hedging instruments’ fair value changes will be recorded in the same income statement line as the hedged item. The adoption of this accounting update did not have a material impact on our consolidated financial statements.



11


Amending the Amortization Period for Certain Callable Debt Securities Purchased at a Premium
Effective January 1, 2019, we adopted ASU 2017-08 on a modified retrospective basis. The new standard was issued with the intent of shortening the amortization period to the earliest call date for certain callable debt securities held at a premium. The adoption of this accounting update did not have a material impact on our consolidated financial statements.

Recognition of Leases
Effective January 1, 2019 we adopted ASU 2016-02 Leases (Topic 842) using the modified retrospective approach.

We recognize an arrangement 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 recognize right-of-use (ROU) assets and the related lease liabilities on the statement of financial position for operating lease arrangements with a term of 12 months or longer. We do not separate non-lease components from the associated lease components of our lessee contracts and account for both components as a single lease component. We combine lease and non-lease components within a contract for operating lessor leases when certain conditions are met. ROU assets are assessed for impairment using the same approach as is applied for other long-lived assets, as described under the Impairment section of the Significant Accounting Policies Note 2 in the annual consolidated financial statements.

Lease liabilities and ROU assets require the use of judgment and estimates, which are applied in determining the term of a lease, appropriate discount rates, whether an arrangement contains a lease, whether there are any indicators of impairment for ROU assets and whether any ROU assets should be grouped with other long-lived assets for impairment testing.

In adopting Topic 842, we elected the package of practical expedients permitted under the transition guidance. 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. The application of the package of practical expedients also permits entities not to reassess whether any expired or existing contracts contain leases in accordance with the new guidance, lease classifications, and whether initial direct costs capitalized under current guidance continue to meet the definition of initial direct costs under the new guidance. We also elected the practical expedient related to land easements, allowing us to carry forward our accounting treatment for land easements on existing agreements that had commenced prior to January 1, 2019.

On January 1, 2019, ROU assets and corresponding lease liabilities of $771 million were recorded in connection with the adoption of Topic 842. When added to the $85 million of pre-existing liabilities relating to operating leases for which we no longer utilize the leased assets, total lease liabilities at January 1, 2019 were $856 million. All lease liabilities were measured using a weighted average discount rate of 4.32%. The adoption of this standard had no impact to the Consolidated Statements of Earnings, Comprehensive Income, Changes in Equity or Cash Flows during the period.



12


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

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

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.

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 delay 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.

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



13


3. REVENUES

Effective January 1, 2019, we renamed the Green Power and Transmission segment to Renewable Power Generation and Transmission. The presentation of the prior years' tables has been revised in order to align with the current presentation.

REVENUE FROM CONTRACTS WITH CUSTOMERS
Major Products and Services
 
Liquids Pipelines

Gas Transmission and Midstream

Gas Distribution

Renewable Power Generation and Transmission

Energy Services

Eliminations and Other

Consolidated

Three months ended
June 30, 2019
(millions of Canadian dollars)
 

 

 

 

 

 

 

Transportation revenues
2,230

1,113

171




3,514

Storage and other revenues
25

46

52




123

Gas gathering and processing revenues

115





115

Gas distribution revenue


754




754

Electricity and transmission revenues



43



43

Commodity sales

3





3

Total revenue from contracts with customers
2,255

1,277

977

43



4,552

Commodity sales




8,413


8,413

Other revenues1,2
199

10

(3
)
94

(7
)
5

298

Intersegment revenues
115

1

3


12

(131
)

Total revenues
2,569

1,288

977

137

8,418

(126
)
13,263


 
Liquids Pipelines

Gas Transmission and Midstream

Gas Distribution

Renewable Power Generation and Transmission

Energy Services

Eliminations and Other

Consolidated

Three months ended
June 30, 2018
(millions of Canadian dollars)
 

 
 

 

 

 

 

Transportation revenues
2,079

958

151




3,188

Storage and other revenues
42

51

52




145

Gas gathering and processing revenues

231





231

Gas distribution revenues


856




856

Electricity and transmission revenues



53



53

Commodity sales

639





639

Total revenue from contracts with customers
2,121

1,879

1,059

53



5,112

Commodity sales




5,812


5,812

Other revenues1, 2
(261
)
(17
)
9

96


(6
)
(179
)
Intersegment revenues
90

2

2


24

(118
)

Total revenues
1,950

1,864

1,070

149

5,836

(124
)
10,745




14


 
Liquids Pipelines

Gas Transmission and Midstream

Gas Distribution

Renewable Power Generation and Transmission

Energy Services

Eliminations and Other

Consolidated

Six months ended
June 30, 2019
(millions of Canadian dollars)
 

 

 

 

 

 

 

Transportation revenues
4,444

2,250

420




7,114

Storage and other revenues
52

99

106




257

Gas gathering and processing revenues

231





231

Gas distribution revenue


2,610




2,610

Electricity and transmission revenues



93



93

Commodity sales

3





3

Total revenue from contracts with customers
4,496

2,583

3,136

93



10,308

Commodity sales




15,045


15,045

Other revenues1,2
539

20

26

196

(1
)
(14
)
766

Intersegment revenues
192

3

6


47

(248
)

Total revenues
5,227

2,606

3,168

289

15,091

(262
)
26,119


 
Liquids Pipelines

Gas Transmission and Midstream

Gas Distribution

Renewable Power Generation and Transmission

Energy Services

Eliminations and Other

Consolidated

Six months ended
June 30, 2018
(millions of Canadian dollars)
 

 
 

 

 

 

 

Transportation revenues
4,137

1,910

390




6,437

Storage and other revenues
82

111

118




311

Gas gathering and processing revenues

436





436

Gas distribution revenues


2,782




2,782

Electricity and transmission revenues



110



110

Commodity sales

1,332





1,332

Total revenue from contracts with customers
4,219

3,789

3,290

110



11,408

Commodity sales




12,387


12,387

Other revenues1, 2
(530
)
8

11

196


(9
)
(324
)
Intersegment revenues
170

4

6


81

(261
)

Total revenues
3,859

3,801

3,307

306

12,468

(270
)
23,471

1 Includes mark-to-market gains/(losses) from our hedging program.
2 Includes revenues from lease contracts. Refer to Note 14 Leases.

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

Contract Assets

Contract Liabilities

(millions of Canadian dollars)
 
 
 
Balance as at December 31, 2018
1,929

191

1,297

Balance as at June 30, 2019
1,845

191

1,275





15


Contract receivables represent the amount of receivables derived from contracts with customers. Contract assets represent the amount of revenues 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 revenues. Revenue recognized during the three and six months ended June 30, 2019 included in contract liabilities at the beginning of the period was $38 million and $130 million, respectively. Increases in contract liabilities from cash received, net of amounts recognized as revenues during the three and six months ended June 30, 2019 were $69 million and $143 million, respectively.
Performance Obligations
There were no material revenues recognized in the three and six months ended June 30, 2019 from performance obligations satisfied in previous periods.

Revenues to be Recognized from Unfulfilled Performance Obligations
Total revenues from performance obligations expected to be fulfilled in future periods is $65.2 billion, of which $3.6 billion and $6.0 billion is expected to be recognized during the six months ending December 31, 2019, and the year ending December 31, 2020, 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 revenue 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 revenues 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, revenue from contracts with customers which have an original expected duration of one year or less are excluded from the amounts above.
Recognition and Measurement of Revenues

Liquids Pipelines

Gas Transmission and Midstream

Gas Distribution

Renewable Power Generation and Transmission

Energy Services

Consolidated

Three months ended
June 30, 2019
(millions of Canadian dollars)
 

 

 

 

 



Revenues from products transferred at a point in time1

3

17



20

Revenues from products and services transferred over time2
2,255

1,274

960

43


4,532

Total revenue from contracts with customers
2,255

1,277

977

43


4,552




16



Liquids Pipelines

Gas Transmission and Midstream

Gas Distribution

Renewable Power Generation and Transmission

Energy Services

Consolidated

Three months ended
June 30, 2018
(millions of Canadian dollars)
 
 
 
 
 
 
Revenues from products transferred at a point in time1

639

20



659

Revenues from products and services transferred over time2
2,121

1,240

1,039

53


4,453

Total revenue from contracts with customers
2,121

1,879

1,059

53


5,112



Liquids Pipelines

Gas Transmission and Midstream

Gas Distribution

Renewable Power Generation and Transmission

Energy Services

Consolidated

Six months ended
June 30, 2019
(millions of Canadian dollars)
 

 

 

 

 

 
Revenues from products transferred at a point in time1

3

34



37

Revenues from products and services transferred over time2
4,496

2,580

3,102

93


10,271

Total revenue from contracts with customers
4,496

2,583

3,136

93


10,308



Liquids Pipelines

Gas Transmission and Midstream

Gas Distribution

Renewable Power Generation and Transmission

Energy Services

Consolidated

Six months ended
June 30, 2018
(millions of Canadian dollars)
 
 
 
 
 
 
Revenues from products transferred at a point in time1

1,332

45



1,377

Revenues from products and services transferred over time2
4,219

2,457

3,245

110


10,031

Total revenue from contracts with customers
4,219

3,789

3,290

110


11,408

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

4. SEGMENTED INFORMATION
 
Liquids Pipelines

Gas Transmission and Midstream

Gas Distribution

Renewable Power Generation and Transmission

Energy Services

Eliminations and Other

Consolidated

Three months ended
June 30, 2019
(millions of Canadian dollars)
 

 
 

 

 

 

 

Revenues
2,569

1,288

977

137

8,418

(126
)
13,263

Commodity and gas distribution costs
(7
)

(344
)
(1
)
(8,209
)
120

(8,441
)
Operating and administrative
(776
)
(563
)
(268
)
(40
)
(1
)
(47
)
(1,695
)
Income from equity investments
204

193

2

4

10


413

Other income/(expense)
2

23

23

(6
)
3

160

205

Earnings before interest, income taxes, and depreciation and amortization
1,992

941

390

94

221

107

3,745

Depreciation and amortization
 
 
 
 
 
 
(842
)
Interest expense
 

 

 

 

 

 

(637
)
Income tax expense
 

 

 

 

 

 

(436
)
Earnings
 
 

 

 

 

 

1,830

Capital expenditures1
522

424

223

2

1

14

1,186



17


 
Liquids Pipelines

Gas Transmission and Midstream

Gas Distribution

Renewable Power Generation and Transmission

Energy Services

Eliminations and Other

Consolidated

Three months ended
June 30, 2018
(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
)
Impairment of long-lived assets
(10
)





(10
)
Income/(loss) from equity investments
137

229

(10
)
4

3


363

Other (expense)/income
(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

Renewable Power Generation and Transmission

Energy Services

Eliminations and Other

Consolidated

Six months ended
June 30, 2019
(millions of Canadian dollars)
 

 
 

 

 

 

 

Revenues
5,227

2,606

3,168

289

15,091

(262
)
26,119

Commodity and gas distribution costs
(13
)

(1,608
)
(2
)
(14,838
)
248

(16,213
)
Operating and administrative
(1,577
)
(1,076
)
(562
)
(82
)
(34
)
11

(3,320
)
Income from equity investments
401

390

13

18

3

1

826

Other income/(expense)
26

41

41

(5
)
5

357

465

Earnings before interest, income taxes, and depreciation and amortization
4,064

1,961

1,052

218

227

355

7,877

Depreciation and amortization
 
 
 
 
 
 
(1,682
)
Interest expense
 

 

 

 

 

 

(1,322
)
Income tax expense
 

 

 

 

 

 

(1,020
)
Earnings
 
 

 

 

 

 

3,853

Capital expenditures1
1,542

818

396

16

2

39

2,813



18


 
Liquids Pipelines

Gas Transmission and Midstream

Gas Distribution

Renewable Power Generation and Transmission

Energy Services

Eliminations and Other

Consolidated

Six months ended
June 30, 2018
(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
)
Impairment of long-lived assets
(154
)
(913
)



(5
)
(1,072
)
Income/(loss) from equity investments
268

437

7

(21
)
7


698

Other (expense)/income
(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

 
1 Includes allowance for equity funds used during construction.

5. EARNINGS PER COMMON SHARE AND DIVIDENDS PER 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 6 million and 13 million for the three and six months ended June 30, 2019 and 2018, respectively, 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,
 
2019

2018

 
2019

2018

(number of common shares in millions)
 

 

 
 

 

Weighted average shares outstanding
2,018

1,695

 
2,017

1,690

Effect of dilutive options
3

3

 
3

3

Diluted weighted average shares outstanding
2,021

1,698


2,020

1,693



For the three months ended June 30, 2019 and 2018, 21.3 million and 30.2 million, respectively, anti-dilutive stock options with a weighted average exercise price of $53.33 and $49.67, respectively, were excluded from the diluted earnings per common share calculation.

For the six months ended June 30, 2019 and 2018, 15.9 million and 30.1 million, respectively, anti-dilutive stock options with a weighted average exercise price of $53.99 and $49.73, respectively, were excluded from the diluted earnings per common share calculation.



19


DIVIDENDS PER SHARE
On August 1, 2019, our Board of Directors declared the following quarterly dividends. All dividends are payable on September 1, 2019, to shareholders of record on August 15, 2019.
 
Dividend per share

Common Shares

$0.73800

Preference Shares, Series A

$0.34375

Preference Shares, Series B

$0.21340

Preference Shares, Series C1

$0.25647

Preference Shares, Series D

$0.27875

Preference Shares, Series F

$0.29306

Preference Shares, Series H

$0.27350

Preference Shares, Series J

US$0.30540

Preference Shares, Series L

US$0.30993

Preference Shares, Series N

$0.31788

Preference Shares, Series P2

$0.27369

Preference Shares, Series R3

$0.25456

Preference Shares, Series 1

US$0.37182

Preference Shares, Series 3

$0.25000

Preference Shares, Series 54

US$0.33596

Preference Shares, Series 75

$0.27806

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 19

$0.30625

1 The quarterly dividend per share paid on Series C was decreased to $0.25395 from $0.25459 on March 1, 2019 and was increased to $0.25647 from $0.25395 on June 1, 2019, 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 P was increased to $0.27369 from $0.25000 on March 1, 2019, due to reset of the annual dividend on March 1, 2019, and every five years thereafter.
3
The quarterly dividend per share paid on Series R was increased to $0.25456 from $0.25000 on June 1, 2019, due to the reset of the annual dividend on June 1, 2019, and every five years thereafter.
4
The quarterly dividend per share paid on Series 5 was increased to US$0.33596 from US$0.27500 on March 1, 2019, due to reset of the annual dividend on March 1, 2019, and every five years thereafter.
5
The quarterly dividend per share paid on Series 7 was increased to $0.27806 from $0.27500 on March 1, 2019, due to reset of the annual dividend on March 1, 2019, and every five years thereafter.

6. ACQUISITIONS AND DISPOSITIONS

ACQUISITIONS
In January 2019, through our wholly-owned subsidiary Enbridge Pipelines (Athabasca) Inc., we acquired 75 kilometers of existing pipeline and tankage infrastructure (collectively, the Cheecham Assets) from Athabasca Oil Corporation for cash consideration of approximately $265 million, all of which was allocated to property, plant and equipment. The Cheecham Assets are a part of our Liquids Pipelines segment. The cash consideration is included in capital expenditures on our Consolidated Statements of Cash Flows for the six months ended June 30, 2019.



20


ASSETS HELD FOR SALE

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

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. On October 1, 2018, we closed the sale of the provincially regulated facilities for proceeds of approximately $2.5 billion. Subject to certain regulatory approvals and customary closing conditions, the sale of the federally regulated facilities is expected to close in 2019 for proceeds of approximately $1.8 billion.

Line 10 Crude Oil Pipeline
In the first quarter of 2018, we satisfied the conditions 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 wholly-owned subsidiaries, Enbridge Pipelines Inc. and Enbridge Energy Partners, L.P. (EEP), own the Canadian and United States portions of Line 10. Subject to certain regulatory approvals and customary closing conditions, the transaction is expected to close in 2019.

St. Lawrence Gas Company, Inc.
In August 2017, we entered into an agreement to sell the issued and outstanding shares of St. Lawrence Gas Company, Inc. Expected cash proceeds for the transaction are approximately $76 million (US$58 million). Subject to regulatory approval and certain pre-closing conditions, the transaction is expected to close in 2019.

The table below summarizes the presentation of net assets held for sale in our Consolidated Statements of Financial Position:
 
June 30, 2019

December 31, 2018

(millions of Canadian dollars)
 

 
Accounts receivable and other (current assets held for sale)
100

117

Deferred amounts and other assets (long-term assets held for sale)1
2,440

2,383

Accounts payable and other (current liabilities held for sale)
(48
)
(63
)
Other long-term liabilities (long-term liabilities held for sale)
(97
)
(96
)
Net assets held for sale
2,395

2,341

1
Included within Deferred amounts and other assets at June 30, 2019 and December 31, 2018 respectively is property, plant and equipment of $2.2 billion and $2.1 billion.




21


7. VARIABLE INTEREST ENTITIES

Gray Oak Holdings LLC
In December 2018, Enbridge acquired an effective 22.8% interest in the Gray Oak crude oil pipeline through acquisition of a 35% membership interest in Gray Oak Holdings LLC (Gray Oak Holdings), which will construct and operate the Gray Oak crude oil pipeline from Texas to the Gulf coast of the United States.

Gray Oak Holdings is a variable interest entity (VIE) as it does not have sufficient equity at risk to finance its activities and requires subordinated financial support from Enbridge and other partners. We have determined that we do not have the power to direct the activities of Gray Oak Holdings that most significantly impact the VIE’s economic performance. Specifically, the power to direct the activities of the VIE is shared amongst the partners. Each partner has representatives that make up an executive committee that makes the significant decisions for the VIE and none of the partners may make major decisions unilaterally. Therefore, the VIE is accounted for as an unconsolidated VIE.

As at June 30, 2019 and December 31, 2018, the carrying amount of the investment in Gray Oak Holdings was $455 million and nil, respectively. Enbridge's maximum exposure to loss as at June 30, 2019 was approximately $911 million and primarily consists of our portion of the project construction costs.

On June 4, 2019, the partners of Gray Oak executed a term loan facility with a syndicate of banks with a borrowing capacity of US$1,230 million to finance the construction of the Gray Oak crude oil pipeline. An Equity Contribution Agreement was executed by the partners of Gray Oak Holdings to backstop the term loan facility until certain release conditions are met. At June 30, 2019 Gray Oak had US$551 million outstanding, and the guarantee associated with our effective interest was US$125 million. On July 2, 2019, the partners exercised an option on the term loan facility for an additional US$87 million, bringing the total borrowing capacity under the facility to US$1,317 million. The maximum amount committed by Enbridge under the Equity Contribution Agreement is US$300 million, which is proportionate to our effective ownership interest.

8.
DEBT

On January 22, 2019, Enbridge entered into supplemental indentures with its wholly-owned subsidiaries, Spectra Energy Partners, LP (SEP) and EEP (together, the Partnerships), pursuant to which Enbridge fully and unconditionally guaranteed, on a senior unsecured basis, the payment obligations of the Partnerships with respect to the outstanding series of notes issued under the respective indentures of the Partnerships. Concurrently, the Partnerships entered into a subsidiary guarantee agreement pursuant to which they guaranteed, on a senior unsecured basis, the outstanding series of senior notes of Enbridge. See Note 16 - Condensed Consolidating Financial Information for further discussion.

CREDIT FACILITIES
The following table provides details of our committed credit facilities as at June 30, 2019:
 
 
 
Maturity
Total
Facilities

Draws1

Available

(millions of Canadian dollars)
 
 
 
 
Enbridge Inc.
2021-2024
6,511

4,850

1,661

Enbridge (U.S.) Inc.
2021-2024
7,187

5,017

2,170

Enbridge Pipelines Inc.
2020
3,000

2,314

686

Enbridge Gas Inc.
2019-2021
2,017

926

1,091

Total committed credit facilities
 
18,715

13,107

5,608

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


22


On February 7, 2019 and February 8, 2019, we terminated certain Canadian and United States dollar credit facilities, including facilities held by Enbridge, Enbridge Gas Inc. (EGI), EEP and SEP. We also increased existing facilities or obtained new facilities to replace the terminated ones under Enbridge, Enbridge (U.S.) Inc. and EGI. As a result, our total credit facility availability increased by approximately $444 million.

On May 16, 2019, Enbridge entered into a three year, extendible credit facility for $641 million (¥52.5 billion) with a syndicate of Japanese banks.

In addition to the committed credit facilities noted above, we maintain $887 million of uncommitted demand credit facilities, of which $571 million were unutilized as at June 30, 2019. As at December 31, 2018, we had $807 million of uncommitted credit facilities, of which $548 million were unutilized.

Our credit facilities carry a weighted average standby fee of 0.1% 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 2020 to 2024.

As at June 30, 2019 and December 31, 2018, commercial paper and credit facility draws, net of short-term borrowings and non-revolving credit facilities that mature within one year, of $12,181 million and $7,967 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, 2019, we completed the following long-term debt issuances:
Company
Issue Date
 
 
Principal Amount
(millions of Canadian dollars)
 
 
Enbridge Pipelines Inc.
 
 
 
 
February 2019
3.52% medium-term notes due February 2029
$600
 
February 2019
4.33% medium-term notes due February 2049
$600




23


LONG-TERM DEBT REPAYMENTS
During the six months ended June 30, 2019, we completed the following long-term debt repayments:
Company
Retirement/
Repayment Date
 
 
Principal Amount
(millions of Canadian dollars, unless otherwise stated)
 
 
Enbridge Inc.
 
 
Repayment
 
 
 
February 2019
4.10% medium-term notes
$300
 
May 2019
Floating rate notes
$750
Enbridge Energy Partners, L.P.
 
 
Redemption
 
 
 
 
February 2019
8.05% fixed/floating rate junior subordinated notes due 2067
US$400
Repayment
 
 
 
 
March 2019
9.88% senior notes
 
US$500
Enbridge Pipelines (Southern Lights) L.L.C.
 
 
Repayment
 
 
 
 
June 2019
3.98% medium-term notes due 2040
 
US$23
Westcoast Energy Inc.
 
 
 
Repayment
 
 
 
 
January 2019
5.60% medium-term notes
$250
 
January 2019
5.60% medium-term notes
 
$50
 
May 2019
6.90% senior secured notes due 2019
 
$13
 
May 2019
4.34% senior secured notes due 2019
 
$2


SUBORDINATED TERM NOTES
As at June 30, 2019 and December 31, 2018, our fixed-to-floating subordinated term notes had a principal value of $6,582 million and $7,317 million, respectively.

FAIR VALUE ADJUSTMENT
As at June 30, 2019, the net fair value adjustment for total debt assumed in the Merger Transaction was $898 million. During the three and six months ended June 30, 2019, the amortization of the fair value adjustment, recorded as a reduction to Interest expense in the Consolidated Statements of Earnings, was $17 million and $34 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, 2019, we were in compliance with all debt covenants.



24


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, 2019 and 2018 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, 2019
(770
)
(598
)
4,323

34

(317
)
2,672

Other comprehensive income/(loss) retained in AOCI
(618
)
252

(2,508
)
22


(2,852
)
Other comprehensive (income)/loss reclassified to earnings
 
 
 
 
 


Interest rate contracts1
72





72

Foreign exchange contracts3
2





2

Other contracts4
(3
)




(3
)
Amortization of pension and OPEB actuarial loss and prior service costs5




57

57

 
(547
)
252

(2,508
)
22

57

(2,724
)
Tax impact
 

 

 

 

 

 

Income tax on amounts retained in AOCI
196

(31
)

(5
)

160

Income tax on amounts reclassified to earnings
(25
)



(14
)
(39
)
 
171

(31
)

(5
)
(14
)
121

Other




55

55

Balance as at June 30, 2019
(1,146
)
(377
)
1,815

51

(219
)
124

 
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

 
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.



25


10. NONCONTROLLING INTERESTS
 
Preferred Shares Redemption
On March 20, 2019, Westcoast Energy Inc. exercised its right to redeem all of its outstanding 5.5% Cumulative Redeemable First Preferred Shares, Series 7 (Series 7 Shares) and all of its outstanding 5.6% Cumulative Redeemable First Preferred Shares, Series 8 (Series 8 Shares) at a price of $25.00 per Series 7 Share and $25.00 per Series 8 Share, respectively, for a total payment of $300 million. In addition, payment of $4 million was made for all accrued and unpaid dividends. As a result, we recorded a $300 million decrease in Noncontrolling interests.

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 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 is used to hedge anticipated foreign currency denominated revenues and expenses, and to manage variability in cash flows. We hedge certain net investments in United States dollar denominated investments and subsidiaries using foreign currency derivatives and United States dollar denominated debt.
 
Interest Rate Risk
Our earnings and cash flows are exposed to short-term interest rate variability due to the regular repricing of our variable rate debt, primarily commercial paper. Pay fixed-receive floating interest rate swaps may be used to hedge against the effect of future interest rate movements. We have implemented a program to significantly mitigate the impact of short-term interest rate volatility on interest expense via execution of floating to fixed interest rate swaps with an average swap rate of 2.8%.

We are exposed to changes in the fair value of fixed rate debt that arise as a result of the changes in market interest rates. Pay floating-receive fixed interest rate swaps are used, when applicable, to hedge against future changes to the fair value of fixed rate debt which mitigates the impact of fluctuations in the fair value of fixed rate debt via execution of fixed to floating interest rate swaps. As at June 30, 2019, we do not have any pay floating-receive fixed interest rate swaps outstanding.
 
Our earnings and cash flows are also exposed to variability in longer term interest rates ahead of anticipated fixed rate term debt issuances. Forward starting interest rate swaps are used to hedge against the effect of future interest rate movements. We have established a program within some of our subsidiaries to mitigate our exposure to long-term interest rate variability on select forecast term debt issuances via execution of floating to fixed interest rate swaps with an average swap rate of 3.0%.
 


26


We also monitor our debt portfolio mix of fixed and variable rate debt instruments to manage a consolidated portfolio of floating rate debt within the Board of Directors approved policy limit of a maximum of 30% of floating rate debt as a percentage of total debt outstanding. We primarily use qualifying derivative instruments to manage interest rate risk.
 
Commodity Price Risk
Our earnings and cash flows are exposed to changes in commodity prices as a result of our ownership interests in certain assets and investments, as well as through the activities of our energy services subsidiaries. These commodities include natural gas, crude oil, power and NGL. We employ financial and physical derivative instruments to fix a portion of the variable price exposures that arise from physical transactions involving these commodities. We use primarily non-qualifying derivative instruments to manage commodity price risk.
 
Equity Price Risk
Equity price risk is the risk of earnings fluctuations due to changes in our share price. We have exposure to our own common share price through the issuance of various forms of stock-based compensation, which affect earnings through revaluation of the outstanding units every period. We use equity derivatives to manage the earnings volatility derived from one form of stock-based compensation, restricted share units. We use a combination of qualifying and non-qualifying derivative instruments to manage equity price risk.
 
TOTAL DERIVATIVE INSTRUMENTS
The following table summarizes the Consolidated Statements of Financial Position location and carrying value of our derivative instruments.
 
We generally have a policy of entering into individual International Swaps and Derivatives Association, Inc. agreements, or other similar derivative agreements, with the majority of our financial derivative counterparties. These agreements provide for the net settlement of derivative instruments outstanding with specific counterparties in the event of bankruptcy or other significant credit events, and reduce 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.



27


June 30, 2019
Derivative
Instruments
Used as
Cash Flow Hedges

Derivative
Instruments
Used as Net
Investment 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


37

37

(21
)
16

Interest rate contracts
2



2


2

Commodity contracts


196

196

(54
)
142

 
2


233

235

(75
)
160

Deferred amounts and other assets
 
 
 
 
 
 
Foreign exchange contracts
14


99

113

(40
)
73

Commodity contracts
1


23

24

(7
)
17

Other contracts
1


1

2

(1
)
1

 
16


123

139

(48
)
91

Accounts payable and other
 
 
 
 
 
 
Foreign exchange contracts
(5
)

(447
)
(452
)
21

(431
)
Interest rate contracts
(258
)


(258
)

(258
)
Commodity contracts
(1
)

(183
)
(184
)
54

(130
)
 
(264
)

(630
)
(894
)
75

(819
)
Other long-term liabilities
 
 
 
 
 
 
Foreign exchange contracts

(13
)
(1,381
)
(1,394
)
40

(1,354
)
Interest rate contracts
(540
)


(540
)

(540
)
Commodity contracts


(126
)
(126
)
7

(119
)
Other contracts
(1
)

(1
)
(2
)
1

(1
)
 
(541
)
(13
)
(1,508
)
(2,062
)
48

(2,014
)
Total net derivative asset/(liability)
 
 
 
 
 
 
Foreign exchange contracts
9

(13
)
(1,692
)
(1,696
)

(1,696
)
Interest rate contracts
(796
)


(796
)

(796
)
Commodity contracts


(90
)
(90
)

(90
)
Other contracts






 
(787
)
(13
)
(1,782
)
(2,582
)

(2,582
)
 


28


December 31, 2018
Derivative
Instruments
Used as
Cash Flow Hedges

Derivative
Instruments
Used as Net
Investment Hedges

Non-
Qualifying
Derivative Instruments

Total Gross
Derivative
Instruments as Presented

Amounts
Available for Offset

Total Net
Derivative Instruments

(millions of Canadian dollars)
 
 
 
 
 
 
Accounts receivable and other
 
 
 
 
 
 
Foreign exchange contracts


47

47

(37
)
10

Interest rate contracts
22



22

(2
)
20

Commodity contracts
2


427

429

(114
)
315

 
24


474

498

(153
)
345

Deferred amounts and other assets
 
 
 
 
 
 
Foreign exchange contracts
23


39

62

(39
)
23

Interest rate contracts
5



5


5

Commodity contracts
19


33

52

(21
)
31

 
47


72

119

(60
)
59

Accounts payable and other
 
 
 
 
 
 
Foreign exchange contracts
(5
)

(610
)
(615
)
37

(578
)
Interest rate contracts
(163
)

(178
)
(341
)
2

(339
)
Commodity contracts


(273
)
(273
)
114

(159
)
Other contracts
(1
)

(4
)
(5
)

(5
)
 
(169
)

(1,065
)
(1,234
)
153

(1,081
)
Other long-term liabilities
 
 
 
 
 
 
Foreign exchange contracts
(1
)
(15
)
(2,196
)
(2,212
)
39

(2,173
)
Interest rate contracts
(201
)


(201
)

(201
)
Commodity contracts


(178
)
(178
)
21

(157
)
Other contracts
(1
)

(1
)
(2
)

(2
)
 
(203
)
(15
)
(2,375
)
(2,593
)
60

(2,533
)
Total net derivative asset/(liability)
 
 
 
 
 
 
Foreign exchange contracts
17

(15
)
(2,720
)
(2,718
)

(2,718
)
Interest rate contracts
(337
)

(178
)
(515
)

(515
)
Commodity contracts
21


9

30


30

Other contracts
(2
)

(5
)
(7
)

(7
)
 
(301
)
(15
)
(2,894
)
(3,210
)

(3,210
)


The following table summarizes the maturity and notional principal or quantity outstanding related to our derivative instruments.
June 30, 2019
2019

2020

2021

2022

2023

Thereafter1

Foreign exchange contracts - United States dollar forwards - purchase (millions of United States dollars)
878

1





Foreign exchange contracts - United States dollar forwards - sell (millions of United States dollars)
2,422

4,893

3,608

2,422

1,804

1,856

Foreign exchange contracts - British pound (GBP) forwards - sell (millions of GBP)
12

94

27

28

29

120

Foreign exchange contracts - Euro forwards - purchase (millions of Euro)
133






Foreign exchange contracts - Euro forwards - sell (millions of Euro)

23

94

94

92

606

Foreign exchange contracts - Japanese yen forwards - purchase (millions of yen)



72,500



Interest rate contracts - short-term pay fixed rate (millions of Canadian dollars)
4,371

6,115

4,098

402

48

156

Interest rate contracts - long-term debt pay fixed rate (millions of Canadian dollars)
2,497

3,100

1,573




Equity contracts (millions of Canadian dollars)
29

20

34




Commodity contracts - natural gas (billions of cubic feet)
(44
)
(14
)
8

14

3


Commodity contracts - crude oil (millions of barrels)
10

3





Commodity contracts - power (megawatt per hour) (MW/H))
98

80

(3
)
(43
)
(43
)
(43
)

1 As at June 30, 2019, thereafter includes an average net purchase/(sell) of power of (43) MW/H for 2024 through 2025.


29



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
June 30,
Six months ended
June 30,
 
2019

2018

2019

2018

(millions of Canadian dollars)
 
 
 
 
Amount of unrealized gain/(loss) recognized in OCI
 
 
 
 
Cash flow hedges
 
 
 
 
Foreign exchange contracts
(3
)
(3
)
(13
)
18

Interest rate contracts
(285
)
17

(581
)
117

Commodity contracts
(18
)
(1
)
(21
)
(3
)
Other contracts
2

12

5

(2
)
Net investment hedges
 
 
 
 
Foreign exchange contracts
1

(5
)
2

11

 
(303
)
20

(608
)
141

Amount of (gain)/loss reclassified from AOCI to earnings
 
 
 
 
Foreign exchange contracts1

(2
)
2

(3
)
Interest rate contracts2
40

54

72

94

Commodity contracts3



(1
)
Other contracts4
6

(6
)
(3
)
3

 
46

46

71

93

1
Reported within Transportation and other services revenues and Net foreign currency gain/(loss) in the Consolidated Statements of Earnings.
2
Reported within Interest expense in the Consolidated Statements of Earnings. Effective January 1, 2019 hedge ineffectiveness will no longer be measured or recorded. See Note 2 Changes in Accounting Policies.
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 $70 million of AOCI related to unrealized 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 30 months as at June 30, 2019.
 
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.

 
Three months ended
June 30,
 
Six months ended
June 30,
 
20191

2018

 
20191

2018

(millions of Canadian dollars)
 
 
 
 
 
Unrealized gain/(loss) on derivative

(4
)
 

3

Unrealized gain/(loss) on hedged item

3

 

(3
)
Realized gain/(loss) on derivative

2

 

(1
)
Realized gain/(loss) on hedged item

(2
)
 

1


1    For the three and six months ended June 30, 2019, there are no outstanding fair value hedges.


30


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
June 30,
 
Six months ended
June 30,
 
2019

2018

 
2019

2018

(millions of Canadian dollars)
 
 
 
 
 
Foreign exchange contracts1
412

(277
)
 
1,028

(701
)
Interest rate contracts2


 
178

(2
)
Commodity contracts3
162

(19
)
 
(99
)
156

Other contracts4

7

 
5

(2
)
Total unrealized derivative fair value gain/(loss), net
574

(289
)
 
1,112

(549
)
1
For the respective six months ended periods, reported within Transportation and other services revenues (2019 - $550 million gain; 2018 - $555 million loss) and Net foreign currency gain/(loss) (2019 - $478 million gain; 2018 - $146 million loss) 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 six months ended periods, reported within Transportation and other services revenues (2019 - $25 million loss; 2018 - $3 million gain), Commodity sales (2019 - $490 million loss; 2018 - $10 million gain), Commodity costs (2019 - $392 million gain; 2018 - $127 million gain) and Operating and administrative expense (2019 - $24 million gain; 2018 - $16 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 June 30, 2019. As a result, all credit facilities are available to us and the banks are obligated to fund and have been funding us under the terms of the facilities.
 
CREDIT RISK
 
Entering into derivative instruments may result in exposure to credit risk from the possibility that a counterparty will default on its contractual obligations. In order to mitigate this risk, we enter into risk management transactions primarily with institutions that possess strong investment grade credit ratings. Credit risk relating to derivative counterparties is mitigated through maintenance and monitoring of credit exposure limits and contractual requirements, netting arrangements, and ongoing monitoring of counterparty credit exposure using external credit rating services and other analytical tools.



31


We have credit concentrations and credit exposure, with respect to derivative instruments, in the following counterparty segments:
 
June 30,
2019

December 31,
2018

(millions of Canadian dollars)
 
 
Canadian financial institutions
44

28

United States financial institutions
31

107

European financial institutions
80

84

Asian financial institutions
11

6

Other1
151

337

 
317

562

 
1
Other is comprised of commodity clearing house and physical natural gas and crude oil counterparties.
 
As at June 30, 2019, we provided letters of credit totaling nil in lieu of providing cash collateral to our counterparties pursuant to the terms of the relevant International Swaps and Derivatives Association (ISDA) agreements. We held no cash collateral on derivative asset exposures as at June 30, 2019 and December 31, 2018.
 
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 EGI, 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.
 


32


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.



33


We have categorized our derivative assets and liabilities measured at fair value as follows:
June 30, 2019
Level 1

Level 2

Level 3

Total Gross
Derivative
Instruments

(millions of Canadian dollars)
 

 

 

 

Financial assets
 

 

 

 

Current derivative assets
 

 

 

 

Foreign exchange contracts

37


37

Interest rate contracts

2


2

Commodity contracts
6

27

163

196

 
6

66

163

235

Long-term derivative assets
 

 

 

 

Foreign exchange contracts

113


113

Commodity contracts

14

10

24

Other contracts

2


2

 

129

10

139

Financial liabilities
 

 

 

 

Current derivative liabilities
 

 

 

 

Foreign exchange contracts

(452
)

(452
)
Interest rate contracts

(258
)

(258
)
Commodity contracts
(10
)
(16
)
(158
)
(184
)
Other contracts




 
(10
)
(726
)
(158
)
(894
)
Long-term derivative liabilities
 

 

 

 

Foreign exchange contracts

(1,394
)

(1,394
)
Interest rate contracts

(540
)

(540
)
Commodity contracts

(9
)
(117
)
(126
)
Other contracts

(2
)

(2
)
 

(1,945
)
(117
)
(2,062
)
Total net financial liabilities
 

 

 

 

Foreign exchange contracts

(1,696
)

(1,696
)
Interest rate contracts

(796
)

(796
)
Commodity contracts
(4
)
16

(102
)
(90
)
Other contracts




 
(4
)
(2,476
)
(102
)
(2,582
)


34


December 31, 2018
Level 1

Level 2

Level 3

Total Gross
Derivative
Instruments

(millions of Canadian dollars)
 

 

 

 

Financial assets
 

 

 

 

Current derivative assets
 

 

 

 

Foreign exchange contracts

47


47

Interest rate contracts

22


22

Commodity contracts
24

45

360

429

 
24

114

360

498

Long-term derivative assets
 

 

 

 

Foreign exchange contracts

62


62

Interest rate contracts

5


5

Commodity contracts

30

22

52

 

97

22

119

Financial liabilities
 

 

 

 

Current derivative liabilities
 

 

 

 

Foreign exchange contracts

(615
)

(615
)
Interest rate contracts

(341
)

(341
)
Commodity contracts
(7
)
(28
)
(238
)
(273
)
Other contracts

(5
)

(5
)
 
(7
)
(989
)
(238
)
(1,234
)
Long-term derivative liabilities
 

 

 

 

Foreign exchange contracts

(2,212
)

(2,212
)
Interest rate contracts

(201
)

(201
)
Commodity contracts

(23
)
(155
)
(178
)
Other contracts

(2
)

(2
)
 

(2,438
)
(155
)
(2,593
)
Total net financial liabilities
 

 

 

 

Foreign exchange contracts

(2,718
)

(2,718
)
Interest rate contracts

(515
)

(515
)
Commodity contracts
17

24

(11
)
30

Other contracts

(7
)

(7
)
 
17

(3,216
)
(11
)
(3,210
)

 
The significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments were as follows:
June 30, 2019
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
(20
)
Forward gas price
2.11

4.60

3.16

$/mmbtu2
Crude
7

Forward crude price
42.18

76.47

57.08

$/barrel
Power
(82
)
Forward power price
27.63

78.91

56.83

$/MW/H
Commodity contracts - physical1
 
 
 
 
 
 
Natural gas
(58
)
Forward gas price
1.04

6.95

1.36

$/mmbtu2
Crude
49

Forward crude price
38.74

91.45

69.70

$/barrel
NGL
2

Forward NGL price
0.15

1.67

0.45

$/gallon
 
(102
)
 
 
 
 
 
1
Financial and physical forward commodity contracts are valued using a market approach valuation technique.
2
One million British thermal units (mmbtu).
 



35


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:
 
Six months ended
June 30,
 
2019

2018

(millions of Canadian dollars)
 

 

Level 3 net derivative liability at beginning of period
(11
)
(387
)
Total gain/(loss)
 

 

Included in earnings1
103

(7
)
Included in OCI
(20
)
(2
)
Settlements
(174
)
162

Level 3 net derivative liability at end of period
(102
)
(234
)
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 June 30, 2019 or December 31, 2018.
 
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 (if any), plus or minus changes resulting from observable price changes in orderly transactions for an identical or similar investment of the same issuer. The carrying value of FVMA other long-term investments totaled $93 million and $102 million as at June 30, 2019 and December 31, 2018, respectively.
 
We have Restricted long-term investments held in trust totaling $389 million and $323 million as at June 30, 2019 and December 31, 2018, respectively, which are recognized at fair value.
 
We have a held to maturity preferred share investment carried at its amortized cost of $593 million and $478 million as at June 30, 2019 and December 31, 2018, respectively. These preferred shares are entitled to a cumulative preferred dividend based on the yield of 10-year Government of Canada bonds plus a margin of 4.38%. The fair value of this preferred share investment approximates its face value of $580 million as at June 30, 2019 and December 31, 2018.
 
As at June 30, 2019 and December 31, 2018, our long-term debt had a carrying value of $64.9 billion and $63.9 billion, respectively, before debt issuance costs and a fair value of $70.0 billion and $64.4 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 June 30, 2019 and December 31, 2018, the noncurrent notes receivable had a carrying value of $93 million and $97 million, respectively, and a fair value of $93 million and $97 million, respectively.

The fair value of other financial assets and liabilities other than derivative instruments, other long-term investments, restricted long-term investments, long-term debt and non-current notes receivable described above approximate their carrying value due to the short period to maturity.
 


36


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 six months ended June 30, 2019 and 2018, we recognized an unrealized foreign exchange gain of $250 million and an unrealized foreign exchange loss of $301 million, respectively, on the translation of United States dollar denominated debt and unrealized gains of $3 million and $10 million, respectively, on the change in fair value of our outstanding foreign exchange forward contracts in OCI. During the six months ended June 30, 2019 and 2018, we recognized realized losses of nil and $23 million, respectively, in OCI associated with the settlement of foreign exchange forward contracts and recognized realized losses of nil and $14 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 six months ended June 30, 2019 and 2018.

12. INCOME TAXES

The effective income tax rates for the three months ended June 30, 2019 and 2018 were 19.2% and (7.9)%, respectively, and for the six months ended June 30, 2019 and 2018 were 20.9% and (10.2)%, respectively. The period-over-period increase in the effective income tax rates is due to the buy-in of our sponsored vehicles which results in Enbridge being taxed on all of our sponsored vehicle earnings rather than on just our proportionate share, lower 2019 foreign tax rate differentials, 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.

13. PENSION AND OTHER POSTRETIREMENT BENEFITS
 
Three months ended
June 30,
 
Six months ended
June 30,
 
2019

2018

 
2019

2018

(millions of Canadian dollars)
 
 
 
 
 
Service cost
51

51

 
102

116

Interest cost
50

42

 
101

87

Expected return on plan assets
(84
)
(80
)
 
(168
)
(162
)
Amortization of actuarial loss
8

8

 
16

15

Plan curtailments

2

 

2

Amortization of prior service costs



(1
)
(1
)
Net periodic benefit costs
25

23

 
50

57



14. LEASES

We incur operating lease expenses related primarily to real estate, pipelines, storage and equipment. Our operating leases have remaining lease terms of 6 months to 29 years.

For the three and six months ended June 30, 2019, we incurred operating lease expenses of $28 million and $56 million, respectively. Operating lease expenses are reported under Operating and administrative expenses on the Consolidated Statements of Earnings.

For the three and six months ended June 30, 2019, operating lease payments to settle lease liabilities were $30 million and $61 million, respectively. Operating lease payments are reported under operating activities in the Consolidated Statements of Cash Flows.



37


Supplemental Statements of Financial Position Information
 
June 30,
2019

January 1,
2019

(millions of Canadian dollars, except lease term and discount rate)

 
 
Operating leases
 
 
Operating lease right-of-use assets, net1
738

771

 
 
 
Operating lease liabilities - current2
99

86

Operating lease liabilities - long-term3
714

770

Total operating lease liabilities
813

856

 
 
 
Weighted average remaining lease term
 
 
Operating leases
14 years

14 years

 
 
 
Weighted average discount rate
 
 
Operating leases
4.3
%
4.3
%
1
Right-of-use assets are reported under Deferred amounts and other assets in the Consolidated Statements of Financial Position.
2
Current lease liabilities are reported under Accounts payable and other in the Consolidated Statements of Financial Position.
3
Long-term lease liabilities are reported under Other long-term liabilities in the Consolidated Statements of Financial Position.

As at June 30, 2019, we have operating lease commitments as detailed below:
 
Operating leases

(millions of Canadian dollars)
 
20191
60

2020
124

2021
96

2022
91

2023
81

Thereafter
665

Total undiscounted lease payments
1,117

Less imputed interest
(304
)
Total operating lease commitments
813

1
For the six months remaining in the 2019 fiscal year.

LESSOR

We have operating leases primarily related to natural gas and crude oil storage and processing facilities, rail cars, and wind power generation assets. Our leases have remaining lease terms of 1 month to 24 years.
 
Three months ended
June 30, 2019

Six months ended
June 30, 2019

(millions of Canadian dollars)
 
 
Operating lease income
66

130

Variable lease income
85

185

Total lease income
151

315





38


The following table sets out future minimum lease payments expected to be received under lease contracts where we are the lessor:
 
Operating leases

(millions of Canadian dollars)
 
20191
131

2020
229

2021
196

2022
186

2023
178

Thereafter
2,391

Total undiscounted lease payments
3,311

1
For the six months remaining in the 2019 fiscal year.

15. CONTINGENCIES
 
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. 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 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.

16. CONDENSED CONSOLIDATING FINANCIAL INFORMATION

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



39


Consenting SEP notes and EEP notes under Guarantee
SEP Notes1
EEP Notes2
Floating Rate Senior Notes due 2020
5.200% Notes due 2020
4.600% Senior Notes due 2021
4.375% Notes due 2020
4.750% Senior Notes due 2024
4.200% Notes due 2021
3.500% Senior Notes due 2025
5.875% Notes due 2025
3.375% Senior Notes due 2026
5.950% Notes due 2033
5.950% Senior Notes due 2043
6.300% Notes due 2034
4.500% Senior Notes due 2045
7.500% Notes due 2038
 
5.500% Notes due 2040
 
7.375% Notes due 2045
1
As at June 30, 2019, the aggregate outstanding principal amount of SEP notes was approximately US$3.9 billion.
2
As at June 30, 2019, the aggregate outstanding principal amount of EEP notes was approximately US$4.0 billion.

Enbridge Notes under Guarantees
USD Denominated1
CAD Denominated2
Senior Floating Rate Notes due 2020
4.770% Senior Notes due 2019
Senior Floating Rate Notes due 2020
4.530% Senior Notes due 2020
2.900% Senior Notes due 2022
4.850% Senior Notes due 2020
4.000% Senior Notes due 2023
4.260% Senior Notes due 2021
3.500% Senior Notes due 2024
3.160% Senior Notes due 2021
4.250% Senior Notes due 2026
4.850% Senior Notes due 2022
3.700% Senior Notes due 2027
3.190% Senior Notes due 2022
4.500% Senior Notes due 2044
3.940% Senior Notes due 2023
5.500% Senior Notes due 2046
3.940% Senior Notes due 2023
 
3.950% Senior Notes due 2024
 
3.200% Senior Notes due 2027
 
6.100% Senior Notes due 2028
 
7.220% Senior Notes due 2030
 
7.200% Senior Notes due 2032
 
5.570% Senior Notes due 2035
 
5.750% Senior Notes due 2039
 
5.120% Senior Notes due 2040
 
4.240% Senior Notes due 2042
 
4.570% Senior Notes due 2044
 
4.870% Senior Notes due 2044
 
4.560% Senior Notes due 2064
1
As at June 30, 2019, the aggregate outstanding principal amount of the Enbridge United States dollar denominated notes was approximately US$5.9 billion.
2
As at June 30, 2019, the aggregate outstanding principal amount of the Enbridge Canadian dollar denominated notes was approximately $7.0 billion.



40


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

1.
Enbridge Inc., the Parent Issuer and Guarantor;
2.
SEP, a Subsidiary Issuer and Guarantor;
3.
EEP, a Subsidiary Issuer and Guarantor;
4.
Subsidiary Non-Guarantors, as defined herein;
5.
Consolidating and elimination entries required to consolidate the Parent Issuer and Guarantor and its subsidiaries, including the Subsidiary Issuers and Guarantors, and
6.
Enbridge Inc. and subsidiaries on a consolidated basis.

For the purposes of the condensed consolidating financial information only, investments in subsidiaries are accounted for under the equity method. In addition, the Condensed Consolidating Statements of Cash Flows present the intercompany loan and distribution activity, as well as cash collection and payments made on behalf of our subsidiaries, as cash activities. These intercompany investments and related activities eliminate on consolidation and are presented separately only for the purpose of the accompanying Condensed Consolidating Statements.


41


Condensed Consolidating Statements of Earnings and Comprehensive Income for the three months ended June 30, 2019
 
Parent Issuer and Guarantor
Subsidiary Issuer and Guarantor - SEP
Subsidiary Issuer and Guarantor - EEP
Subsidiary Non-Guarantors
Consolidating and elimination adjustments
 Consolidated - Enbridge
(millions of Canadian dollars)
 
 
 
 
 
 
Operating revenues
 
 
 
 
 
 
Commodity sales



8,416


8,416

Gas distribution sales



755


755

Transportation and other services



4,092


4,092

Total operating revenues



13,263


13,263

Operating Expenses
 
 
 
 
 
 
Commodity costs



8,129


8,129

Gas distribution costs



312


312

Operating and administrative
69

1

(2
)
1,627


1,695

Depreciation and amortization
18



824


842

Total operating expenses
87

1

(2
)
10,892


10,978

Operating income/(loss)
(87
)
(1
)
2

2,371


2,285

Income from equity investments
8

31


380

(6
)
413

Equity earnings from consolidated subsidiaries
1,624

344

251

473

(2,692
)

Other
 
 
 
 
 
 
Net foreign currency gain
256



27

(143
)
140

Other, including other income from affiliates
464

1

53

112

(565
)
65

Interest expense
(322
)
(84
)
(136
)
(690
)
595

(637
)
Earnings before income taxes
1,943

291

170

2,673

(2,811
)
2,266

Income tax (expense)/recovery
(111
)
12


(443
)
106

(436
)
Earnings
1,832

303

170

2,230

(2,705
)
1,830

Earnings attributable to noncontrolling interests and redeemable noncontrolling interests




2

2

Earnings attributable to controlling interests
1,832

303

170

2,230

(2,703
)
1,832

Preference share dividends
(96
)




(96
)
Earnings attributable to common shareholders
1,736

303

170

2,230

(2,703
)
1,736

Earnings
1,832

303

170

2,230

(2,705
)
1,830

Total other comprehensive income/(loss)
(1,325
)
(28
)
14

(148
)
113

(1,374
)
Comprehensive income
507

275

184

2,082

(2,592
)
456

Comprehensive loss attributable to noncontrolling interests




51

51

Comprehensive income attributable to controlling interests
507

275

184

2,082

(2,541
)
507







42


Condensed Consolidating Statements of Earnings and Comprehensive Income for the three months ended June 30, 2018
 
Parent Issuer and Guarantor
Subsidiary Issuer and Guarantor - SEP
Subsidiary Issuer and Guarantor - EEP
Subsidiary Non-Guarantors
Consolidating and elimination adjustments
 Consolidated - Enbridge
(millions of Canadian dollars)
 
 
 
 
 
 
Operating revenues
 
 
 
 
 
 
Commodity sales



6,451


6,451

Gas distribution sales



856


856

Transportation and other services



3,438


3,438

Total operating revenues



10,745


10,745

Operating Expenses
 
 
 
 
 
 
Commodity costs



6,278


6,278

Gas distribution costs



421


421

Operating and administrative
33

3

5

1,595


1,636

Depreciation and amortization
15



814


829

Impairment of long-lived assets



10


10

Total operating expenses
48

3

5

9,118


9,174

Operating income/(loss)
(48
)
(3
)
(5
)
1,627


1,571

Income from equity investments
59

36


323

(55
)
363

Equity earnings from consolidated subsidiaries
1,287

529

229

615

(2,660
)

Other
 
 
 
 
 
 
Net foreign currency gain/(loss)
(171
)
2


65

61

(43
)
Other, including other income/(expense) from affiliates
272

1

35

(3
)
(276
)
29

Interest expense
(286
)
(72
)
(137
)
(477
)
282

(690
)
Earnings before income taxes
1,113

493

122

2,150

(2,648
)
1,230

Income tax recovery
47



41

9

97

Earnings
1,160

493

122

2,191

(2,639
)
1,327

Earnings attributable to noncontrolling interests and redeemable noncontrolling interests




(167
)
(167
)
Earnings attributable to controlling interests
1,160

493

122

2,191

(2,806
)
1,160

Preference share dividends
(89
)




(89
)
Earnings attributable to common shareholders
1,071

493

122

2,191

(2,806
)
1,071

Earnings
1,160

493

122

2,191

(2,639
)
1,327

Total other comprehensive income
948

11

6

162

(49
)
1,078

Comprehensive income
2,108

504

128

2,353

(2,688
)
2,405

Comprehensive income attributable to noncontrolling interests




(297
)
(297
)
Comprehensive income attributable to controlling interests
2,108

504

128

2,353

(2,985
)
2,108





43


Condensed Consolidating Statements of Earnings and Comprehensive Income for the six months ended June 30, 2019
 
Parent Issuer and Guarantor
Subsidiary Issuer and Guarantor - SEP
Subsidiary Issuer and Guarantor - EEP
Subsidiary Non-Guarantors
Consolidating and elimination adjustments
 Consolidated - Enbridge
(millions of Canadian dollars)
 
 
 
 
 
 
Operating revenues
 
 
 
 
 
 
Commodity sales



15,048


15,048

Gas distribution sales



2,631


2,631

Transportation and other services



8,440


8,440

Total operating revenues



26,119


26,119

Operating Expenses
 
 
 
 
 
 
Commodity costs



14,694


14,694

Gas distribution costs



1,519


1,519

Operating and administrative
35

3

(1
)
3,283


3,320

Depreciation and amortization
33



1,649


1,682

Total operating expenses
68

3

(1
)
21,145


21,215

Operating income/(loss)
(68
)
(3
)
1

4,974


4,904

Income from equity investments
67

62


762

(65
)
826

Equity earnings from consolidated subsidiaries
2,398

742

514

966

(4,620
)

Other
 
 
 
 
 
 
Net foreign currency gain/(loss)
1,477



(76
)
(1,047
)
354

Other, including other income from affiliates
794

1

94

235

(1,013
)
111

Interest expense
(630
)
(178
)
(294
)
(1,273
)
1,053

(1,322
)
Earnings before income taxes
4,038

624

315

5,588

(5,692
)
4,873

Income tax (expense)/recovery
(220
)
27


(1,039
)
212

(1,020
)
Earnings
3,818

651

315

4,549

(5,480
)
3,853

Earnings attributable to noncontrolling interests and redeemable noncontrolling interests




(35
)
(35
)
Earnings attributable to controlling interests
3,818

651

315

4,549

(5,515
)
3,818

Preference share dividends
(191
)




(191
)
Earnings attributable to common shareholders
3,627

651

315

4,549

(5,515
)
3,627

Earnings
3,818

651

315

4,549

(5,480
)
3,853

Total other comprehensive income/(loss)
(2,603
)
(44
)
29

(868
)
784

(2,702
)
Comprehensive income
1,215

607

344

3,681

(4,696
)
1,151

Comprehensive loss attributable to noncontrolling interests




64

64

Comprehensive income attributable to controlling interests
1,215

607

344

3,681

(4,632
)
1,215




44


Condensed Consolidating Statements of Earnings and Comprehensive Income for the six months ended June 30, 2018
 
Parent Issuer and Guarantor
Subsidiary Issuer and Guarantor - SEP
Subsidiary Issuer and Guarantor - EEP
Subsidiary Non-Guarantors
Consolidating and elimination adjustments
 Consolidated - Enbridge
(millions of Canadian dollars)
 
 
 
 
 
 
Operating revenues
 
 
 
 
 
 
Commodity sales



13,719


13,719

Gas distribution sales



2,782


2,782

Transportation and other services



6,970


6,970

Total operating revenues



23,471


23,471

Operating Expenses
 
 
 
 
 
 
Commodity costs



13,275


13,275

Gas distribution costs



1,745


1,745

Operating and administrative
100

4

9

3,164


3,277

Depreciation and amortization
29



1,624


1,653

   Impairment of long lived assets



1,072


1,072

Total operating expenses
129

4

9

20,880


21,022

Operating income/(loss)
(129
)
(4
)
(9
)
2,591


2,449

Income from equity investments
76

70


623

(71
)
698

Equity earnings from consolidated subsidiaries
1,994

1,080

432

1,223

(4,729
)

Other
 
 
 
 
 
 
Net foreign currency gain/(loss)
(370
)
4


7

131

(228
)
Other, including other income from affiliates
518

2

65

36

(527
)
94

Interest expense
(529
)
(144
)
(273
)
(956
)
556

(1,346
)
Earnings before income taxes
1,560

1,008

215

3,524

(4,640
)
1,667

Income tax recovery
134



18

18

170

Earnings
1,694

1,008

215

3,542

(4,622
)
1,837

Earnings attributable to noncontrolling interests and redeemable noncontrolling interests




(143
)
(143
)
Earnings attributable to controlling interests
1,694

1,008

215

3,542

(4,765
)
1,694

Preference share dividends
(178
)




(178
)
Earnings attributable to common shareholders
1,516

1,008

215

3,542

(4,765
)
1,516

Earnings
1,694

1,008

215

3,542

(4,622
)
1,837

Total other comprehensive income
2,250

30

14

415

(158
)
2,551

Comprehensive income
3,944

1,038

229

3,957

(4,780
)
4,388

Comprehensive loss attributable to noncontrolling interests




(444
)
(444
)
Comprehensive income attributable to controlling interests
3,944

1,038

229

3,957

(5,224
)
3,944







45


Condensed Consolidating Statements of Financial Position as at June 30, 2019
 
Parent Issuer and Guarantor
Subsidiary Issuer and Guarantor - SEP
Subsidiary Issuer and Guarantor - EEP
Subsidiary Non-Guarantors
Consolidating and elimination adjustments
 Consolidated - Enbridge
(millions of Canadian dollars)
 
 
 
 
 
 
Assets
 
 
 
 
 
 
Current assets
 
 
 
 
 
 
Cash and cash equivalents

14

27

667


708

Restricted cash
9



50


59

Accounts receivable and other
153

2

2

6,100


6,257

Accounts receivable from affiliates
786


13

334

(1,048
)
85

Short-term loans receivable from affiliates
3,417


4,523

6,225

(14,165
)

Inventory



1,284


1,284

 
4,365

16

4,565

14,660

(15,213
)
8,393

Property, plant and equipment, net
161



93,041


93,202

Long-term loans receivable from affiliates
38,335

73

2,418

25,830

(66,656
)

Investments in subsidiaries
78,955

19,932

6,009

14,762

(119,658
)

Long-term investments
1,735

927


14,517

(648
)
16,531

Restricted long-term investments



389


389

Deferred amounts and other assets
1,384


4

9,421

(1,257
)
9,552

Intangible assets, net
227



1,988


2,215

Goodwill



33,342


33,342

Deferred income taxes
672



532


1,204

Total assets
125,834

20,948

12,996

208,482

(203,432
)
164,828

 
 
 
 
 
 
 
Liabilities and equity
 
 
 
 
 
 
Current liabilities
 
 
 
 
 
 
Short-term borrowings



916


916

Accounts payable and other
718

52

5

6,240

141

7,156

Accounts payable to affiliates
1,158

819

524

(1,427
)
(1,048
)
26

Interest payable
273

53

68

232


626

Short-term loans payable to affiliates
430

3,113

2,681

7,941

(14,165
)

Current portion of long-term debt
2,466

522

653

1,003


4,644

 
5,045

4,559

3,931

14,905

(15,072
)
13,368

Long-term debt
23,545

4,465

4,467

27,540


60,017

Other long-term liabilities
2,063

20

21

8,024

(1,257
)
8,871

Long-term loans payable to affiliates
25,776


1,437

39,443

(66,656
)

Deferred income taxes

282


5,120

4,365

9,767

 
56,429

9,326

9,856

95,032

(78,620
)
92,023

Equity
 
 
 
 
 
 
Controlling interests1
69,405

11,622

3,140

113,450

(128,263
)
69,354

Noncontrolling interests




3,451

3,451

 
69,405

11,622

3,140

113,450

(124,812
)
72,805

Total liabilities and equity
125,834

20,948

12,996

208,482

(203,432
)
164,828

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










46


Condensed Consolidating Statements of Financial Position as at December 31, 2018
 
Parent Issuer and Guarantor
Subsidiary Issuer and Guarantor - SEP
Subsidiary Issuer and Guarantor - EEP
Subsidiary Non-Guarantors
Consolidating and elimination adjustments
 Consolidated - Enbridge
(millions of Canadian dollars)
 
 
 
 
 
 
Assets
 
 
 
 
 
 
Current assets
 
 
 
 
 
 
Cash and cash equivalents

16


502


518

Restricted cash
9



110


119

Accounts receivable and other
283

15

8

6,211


6,517

Accounts receivable from affiliates
726


13

(142
)
(518
)
79

Short-term loans receivable from affiliates
3,943


3,689

653

(8,285
)

Inventory



1,339


1,339

 
4,961

31

3,710

8,673

(8,803
)
8,572

Property, plant and equipment, net
140



94,400


94,540

Long-term loans receivable from affiliates
10,318

73

2,539

1,344

(14,274
)

Investments in subsidiaries
78,474

19,777

6,363

15,567

(120,181
)

Long-term investments
4,561

987


14,841

(3,682
)
16,707

Restricted long-term investments



323


323

Deferred amounts and other assets
1,700

9

17

8,558

(1,726
)
8,558

Intangible assets, net
234



2,138


2,372

Goodwill



34,459


34,459

Deferred income taxes
817



229

328

1,374

Total assets
101,205

20,877

12,629

180,532

(148,338
)
166,905

 
 
 
 
 
 
 
Liabilities and equity
 
 
 
 
 
 
Current liabilities
 
 
 
 
 
 
Short-term borrowings



1,024


1,024

Accounts payable and other
2,742

7

34

7,086

(6
)
9,863

Accounts payable to affiliates
946

233

56

(677
)
(518
)
40

Interest payable
283

56

105

225


669

Short-term loans payable to affiliates
426

682


7,177

(8,285
)

Current portion of long-term debt
1,853


683

723


3,259

 
6,250

978

878

15,558

(8,809
)
14,855

Long-term debt
22,893

7,276

6,943

23,215


60,327

Other long-term liabilities
2,428

2

30

8,100

(1,726
)
8,834

Long-term loans payable to affiliates
76


1,502

12,696

(14,274
)

Deferred income taxes

331


13,523

(4,400
)
9,454

 
31,647

8,587

9,353

73,092

(29,209
)
93,470

Equity
 
 
 
 
 
 
Controlling interests1
69,558

12,290

3,276

107,440

(123,094
)
69,470

Noncontrolling interests




3,965

3,965

 
69,558

12,290

3,276

107,440

(119,129
)
73,435

Total liabilities and equity
101,205

20,877

12,629

180,532

(148,338
)
166,905

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









47


Condensed Consolidating Statements of Cash Flows for the six months ended June 30, 2019
 
Parent Issuer and Guarantor
Subsidiary Issuer and Guarantor - SEP
Subsidiary Issuer and Guarantor - EEP
Subsidiary Non-Guarantors
Consolidating and elimination adjustments
 Consolidated - Enbridge
(millions of Canadian dollars)
 
 
 
 
 
 
Net cash provided by operating activities
560

551

252

4,723

(1,416
)
4,670

Investing activities
 
 
 
 
 
 
Capital expenditures
(31
)


(2,754
)

(2,785
)
Long-term investments and restricted long-term investments
(8
)
(4
)

(688
)

(700
)
Distributions from equity investments in excess of cumulative earnings

17

564

251

(564
)
268

Additions to intangible assets
(36
)


(64
)

(100
)
Affiliate loans, net



(140
)

(140
)
Contributions to subsidiaries
(2,336
)

(3
)

2,339


Return of share capital from subsidiary companies
4,921




(4,921
)

Advances to affiliates
(32,520
)

(1,407
)
(41,213
)
75,140


Repayment of advances to affiliates
4,748


422

9,930

(15,100
)

Net cash (used in)/provided by investing activities
(25,262
)
13

(424
)
(34,678
)
56,894

(3,457
)
Financing activities
 
 
 
 
 
 
Net change in short-term borrowings



(108
)

(108
)
Net change in commercial paper and credit facility draws
2,827

(2,017
)
(1,017
)
4,222


4,015

Debenture and term note issues, net of issue costs



1,195


1,195

Debenture and term note repayments
(1,050
)

(1,189
)
(345
)

(2,584
)
Contributions from noncontrolling interests




9

9

Distributions to noncontrolling interests




(100
)
(100
)
Contributions from redeemable noncontrolling interests






Distributions to redeemable noncontrolling interests






Contributions from parents



2,339

(2,339
)

Distributions to parents

(1,014
)
(328
)
(5,650
)
6,992


Redemption of preferred shares



(300
)

(300
)
Common shares issued
18





18

Preference share dividends
(191
)




(191
)
Common share dividends
(2,976
)




(2,976
)
Advances from affiliates
33,074

4,419

3,720

33,927

(75,140
)

Repayment of advances from affiliates
(7,000
)
(1,949
)
(981
)
(5,170
)
15,100


Other

(5
)
(6
)
(25
)

(36
)
Net cash provided by/(used in) financing activities
24,702

(566
)
199

30,085

(55,478
)
(1,058
)
Effect of translation of foreign denominated cash and cash equivalents and restricted cash



(25
)

(25
)
Net increase/(decrease) in cash and cash equivalents and restricted cash

(2
)
27

105


130

Cash and cash equivalents and restricted cash at beginning of period
9

16


612


637

Cash and cash equivalents and restricted cash at end of period
9

14

27

717


767



48


Condensed Consolidating Statements of Cash Flows for the six months ended June 30, 2018
 
Parent Issuer and Guarantor
Subsidiary Issuer and Guarantor - SEP
Subsidiary Issuer and Guarantor - EEP
Subsidiary Non-Guarantors
Consolidating and elimination adjustments
 Consolidated - Enbridge
(millions of Canadian dollars)
 
 
 
 
 
 
Net cash (used in)/provided by operating activities
(79
)
1,875

(145
)
5,639

(752
)
6,538

Investing activities
 
 
 
 
 
 
Capital expenditures
(8
)


(3,235
)

(3,243
)
Long-term investments and restricted long-term investments
(36
)
(9
)

(600
)
34

(611
)
Distributions from equity investments in excess of cumulative earnings
1,260

24

451

1,116

(1,711
)
1,140

Additions to intangible assets
(20
)


(405
)

(425
)
Affiliate loans, net






Proceeds from dispositions



4


4

Reimbursement of capital expenditures






Contributions to subsidiaries
(2,093
)
(78
)
(7
)

2,178


Return of share capital from subsidiary companies
1,916




(1,916
)

Advances to affiliates
(2,324
)

(910
)
(2,397
)
5,631


Repayment of advances to affiliates
1,094

511

960

1,890

(4,455
)

Other



(4
)

(4
)
Net cash (used in)/provided by investing activities
(211
)
448

494

(3,631
)
(239
)
(3,139
)
Financing activities
 
 
 
 
 
 
Net change in short-term borrowings



(433
)

(433
)
Net change in commercial paper and credit facility draws
(931
)
(1,397
)
312

(150
)

(2,166
)
Debenture and term note issues, net of issue costs
2,556



981


3,537

Debenture and term note repayments


(509
)
(1,638
)

(2,147
)
Contributions from noncontrolling interests




21

21

Distributions to noncontrolling interests




(425
)
(425
)
Contributions from redeemable noncontrolling interests




41

41

Distributions to redeemable noncontrolling interests




(174
)
(174
)
Contributions from parents



2,178

(2,178
)

Distributions to parents

(924
)
(331
)
(3,627
)
4,882


Common shares issued
14





14

Preference share dividends
(174
)




(174
)
Common share dividends
(1,493
)




(1,493
)
Advances from affiliates
368


2,029

3,234

(5,631
)

Repayment of advances from affiliates
(43
)

(1,847
)
(2,565
)
4,455


Other

(6
)
(3
)
9



Net cash provided by/(used in) financing activities
297

(2,327
)
(349
)
(2,011
)
991

(3,399
)
Effect of translation of foreign denominated cash and cash equivalents and restricted cash



35


35

Net increase/(decrease) in cash and cash equivalents and restricted cash
7

(4
)

32


35

Cash and cash equivalents and restricted cash at beginning of period
2

14


571


587

Cash and cash equivalents and restricted cash at end of period
9

10


603


622




49


17. SUBSEQUENT EVENTS

On August 1, 2019, a rupture occurred on a 30-inch natural gas pipeline that makes up the Texas Eastern natural gas pipeline system in Lincoln County, Kentucky. The pipeline has been shut down as we respond to the incident. There has been one confirmed fatality. The National Transportation Safety Board (NTSB) has assumed control of the site. We are continuing to support the NTSB, the community and the community members who were impacted by the rupture.



50


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, our Annual Report on Form 10-K for the year ended December 31, 2018, and our audited updated consolidated financial statements and accompanying footnotes for the year ended December 31, 2018.

RECENT DEVELOPMENTS

STATE OF MINNESOTA PERMITTING TIMELINE FOR U.S. LINE 3 REPLACEMENT PROGRAM

On June 3, 2019, the Minnesota Court of Appeals rendered a decision on the Minnesota Public Utilities Commission's (MNPUC's) adequacy determination of the Final Environmental Impact Statement (FEIS) for the U.S. L3R Program. While denying eight of the nine appealed items, the Minnesota Court of Appeals identified one issue that led them to reverse the adequacy determination. We will continue to consult with relevant state agencies about next steps.

At this time, we cannot determine when all necessary permits will be issued pending receipt of further information from the MNPUC on a timeline to complete this work. For further details refer to Growth Projects - Regulatory Matters - United States Line 3 Replacement Program.

TEXAS EASTERN PIPELINE RUPTURE

On August 1, 2019, a rupture occurred on a 30-inch natural gas pipeline that makes up the Texas Eastern natural gas pipeline system in Lincoln County, Kentucky. The pipeline has been shut down as we respond to the incident. There has been one confirmed fatality. The National Transportation Safety Board (NTSB) has assumed control of the site. We are continuing to support the NTSB, the community and the community members who were impacted by the rupture. The Texas Eastern natural gas pipeline system extends approximately 1,700 miles from producing fields in the Gulf Coast region of Texas and Louisiana to Ohio, Pennsylvania, New Jersey and New York.

SECURED GROWTH PROJECTS UPDATE

On August 2, 2019, we announced that we are proceeding with $2 billion of new growth projects across several business segments. We now have a $19 billion inventory of secured projects at various stages of execution which are scheduled to come into service between 2019 and 2023. For further details refer to Growth Projects - Commercially Secured Projects.

MAINLINE SYSTEM CONTRACTING

On August 2, 2019, we launched an open season for transportation service on our Mainline System. The open season will provide shippers with the opportunity to enter into long-term contracts for priority access on the Mainline System upon maturity of the current Competitive Tolling Settlement agreement on June 30, 2021. The open season will run through October 2, 2019.



51


TEXAS EASTERN RATE CASE

On June 1, 2019 Texas Eastern Transmission, LP (Texas Eastern) put into effect its updated motion rates. These increased recourse rates are subject to refund and interest. There is a pending rate case proceeding before the FERC. Our shippers, the FERC and Texas Eastern are currently in settlement discussions with the expectation of achieving a negotiated settlement or commencing a rate case hearing before the end of the year.

RESULTS OF OPERATIONS
 
 
Three months ended
June 30,
 
Six months ended
June 30,
 
2019

2018

 
2019

2018

(millions of Canadian dollars, except per share amounts)
 

 

 
 

 

Segment earnings/(loss) before interest, income taxes and depreciation and amortization
 
 
 
 
 
Liquids Pipelines
1,992

1,322

 
4,064

2,478

Gas Transmission and Midstream
941

1,014

 
1,961

1,140

Gas Distribution
390

370

 
1,052

1,006

Renewable Power Generation and Transmission
94

126

 
218

235

Energy Services
221

35

 
227

204

Eliminations and Other
107

(118
)
 
355

(397
)
 
 
 
 
 
 
Depreciation and amortization
(842
)
(829
)
 
(1,682
)
(1,653
)
Interest expense
(637
)
(690
)
 
(1,322
)
(1,346
)
Income tax (expense)/recovery
(436
)
97

 
(1,020
)
170

(Earnings)/loss attributable to noncontrolling interests and redeemable noncontrolling interests
2

(167
)
 
(35
)
(143
)
Preference share dividends
(96
)
(89
)
 
(191
)
(178
)
Earnings attributable to common shareholders
1,736

1,071

 
3,627

1,516

Earnings per common share
0.86

0.63

 
1.80

0.90

Diluted earnings per common share
0.86

0.63

 
1.80

0.90


EARNINGS ATTRIBUTABLE TO COMMON SHAREHOLDERS

Three months ended June 30, 2019, compared with the three months ended June 30, 2018

Earnings Attributable to Common Shareholders were net positively impacted by $410 million due to certain unusual, infrequent or other factors, primarily explained by a non-cash, unrealized derivative fair value gain of $695 million ($551 million after-tax attributable to us) in 2019, compared with a loss of $282 million ($151 million after-tax attributable to us) in 2018, 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.

The positive factor above was partially offset by the following unusual, infrequent or other factors:
a non-cash, write-down of crude oil and natural gas inventories to the lower of cost or market in our Energy Services business segment of $138 million ($105 million after-tax attributable to us) in 2019 compared with $16 million ($12 million after-tax attributable to us) in 2018; and
the absence in 2019 of a deferred income tax recovery of $258 million ($190 million attributable to us) in 2018 related to a change in the assertion for the investment in Canadian renewable energy generation assets.



52


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 $255 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 higher Flanagan South Pipeline, Seaway Crude Pipeline System and Bakken Pipeline System throughput period-over-period;
contributions from new Gas Transmission and Midstream assets placed into service in 2018;
increased earnings from our Gas Distribution segment due to higher distribution rates and customer base;
increased earnings from our Energy Services segment due to the widening of certain location differentials during the second half of 2018 and the first half of 2019, which increased opportunities to generate profitable transportation margins that were realized during 2019;
lower interest expense due to debt repayments from proceeds received on the sale of non-core assets in the second half of 2018;
lower earnings attributable to noncontrolling interests in 2019 following the completion of the buy-in of our sponsored vehicles in the fourth quarter of 2018; and
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 $1.34 in 2019 compared with $1.29 in 2018, partially offset by realized losses arising from our foreign exchange risk management program.

The positive business factors above were partially offset by the following:
the absence in 2019 of earnings from Midcoast Operating, L.P. and its subsidiaries (together, MOLP) and the provincially regulated portion of our Canadian gas gathering and processing businesses which were sold in 2018; and
higher income tax expense due to higher earnings, the buy-in of our United States sponsored vehicles in the fourth quarter of 2018 and lower foreign tax rate differentials in 2019.

Six months ended June 30, 2019, compared with the six months ended June 30, 2018

Earnings Attributable to Common Shareholders were net positively impacted by $1,591 million due to certain unusual, infrequent or other factors, primarily explained by the following:
the absence in 2019 of a loss of $913 million ($701 million after-tax attributable to us) in 2018 on MOLP resulting from a revision to the fair value of the assets held for sale based on the sale price;
the absence in 2019 of a loss of $154 million ($95 million after-tax attributable to us) in 2018 related to the Line 10 crude oil pipeline, 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 non-cash, unrealized derivative fair value gain of $1,131 million ($828 million after-tax attributable to us) in 2019, compared with a loss of $559 million ($297 million after-tax attributable to us) in 2018, 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; and
employee severance, transition and transformation costs of $65 million ($62 million after-tax attributable to us) in 2019, compared with $126 million ($123 million after-tax attributable to us) in 2018.



53


The positive factors above were partially offset by the following unusual, infrequent or other factors:
a non-cash, write-down of crude oil and natural gas inventories to the lower of cost or market in our Energy Services business segment of $144 million ($110 million after-tax attributable to us) compared to $16 million ($12 million after-tax attributable to us) in 2018;
the absence in 2019 of a gain of $63 million after-tax in 2018 that resulted from the impact of the Tax Cuts and Jobs Act on our United States Renewable Power Generation and Transmission assets; and
the absence in 2019 of a deferred income tax recovery of $258 million ($190 million attributable to us) in 2018 related to a change in the assertion for the investment in Canadian renewable energy generation assets.

After taking into consideration the factors above, the remaining $520 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 higher Flanagan South Pipeline, Seaway Crude Pipeline System and Bakken Pipeline System throughput period-over-period;
contributions from new Gas Transmission and Midstream assets placed into service in 2018;
increased earnings from our Gas Distribution segment due to colder weather experienced in our franchise areas, higher distribution rates and customer base, and the absence in 2019 of forecasted earnings sharing which was recorded in 2018;
increased earnings from our Energy Services segment due to the widening of certain location differentials during the second half of 2018 and the first half of 2019, which increased opportunities to generate profitable transportation margins that were realized during 2019;
lower earnings attributable to noncontrolling interests in 2019 following the completion of the buy-in of our sponsored vehicles in the fourth quarter of 2018; and
the net favorable effect of translating United States dollar EBITDA at a higher Average Exchange Rate of $1.33 in 2019 compared with $1.28 in 2018, partially offset by realized losses arising from our foreign exchange risk management program.

The positive business factors above were partially offset by the following:
the absence in 2019 of earnings from MOLP and the provincially regulated portion of our Canadian gas gathering and processing businesses which were sold in 2018; and
higher income tax expense due to higher earnings, the buy-in of our United States sponsored vehicles in the fourth quarter of 2018 and lower foreign tax rate differentials in 2019.

BUSINESS SEGMENTS

LIQUIDS PIPELINES
 
 
Three months ended
June 30,
 
Six months ended
June 30,
 
2019

2018

 
2019

2018

(millions of Canadian dollars)
 

 

 
 

 

Earnings before interest, income taxes and depreciation and amortization
1,992

1,322

 
4,064

2,478

 

Three months ended June 30, 2019, compared with the three months ended June 30, 2018

EBITDA was positively impacted by $533 million due to certain unusual, infrequent or other factors, primarily explained by a non-cash, unrealized gain of $227 million in 2019 compared with a loss of $275 million in 2018 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.



54


After taking into consideration the factor above, the remaining $137 million increase is primarily explained by the following significant business factors:
higher Flanagan South Pipeline and Seaway Crude Pipeline System throughput period-over-period partially driven by the redirection of throughput to the Gulf Coast resulting from refinery outages in the United States Midwest;
higher Bakken Pipeline System throughput period-over-period driven by strong production in the region;
a higher International Joint Tariff (IJT) Benchmark Toll of US$4.15 in 2019 compared with US$4.07 in 2018;
higher Mainline System ex-Gretna throughput of 2,661 thousands of barrels per day (kbpd) in 2019 compared with 2,636 kbpd in 2018 driven by an increase in supply and continuous capacity optimization; and
the net favorable effect of translating United States dollar EBITDA at a higher Average Exchange Rate of $1.34 in 2019 compared with $1.29 in 2018.

The positive business factors above were partially offset by the unfavorable effect of a lower foreign exchange hedge rate used to lock-in United States dollar denominated revenues from the Canadian portion of the Mainline System.

Six months ended June 30, 2019, compared with the six months ended June 30, 2018

EBITDA was positively impacted by $1,347 million due to certain unusual, infrequent or other factors, primarily explained by the following:
a non-cash, unrealized gain of $570 million in 2019 compared with a loss of $573 million in 2018 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 2019 of 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.

After taking into consideration the factors above, the remaining $239 million increase is primarily explained by the following significant business factors:
higher Flanagan South Pipeline and Seaway Crude Pipeline System throughput period-over-period partially driven by the redirection of throughput to the Gulf Coast resulting from refinery outages in the United States Midwest;
higher Bakken Pipeline System throughput period-over-period driven by strong production in the region;
a higher IJT Benchmark Toll of US$4.15 in 2019 compared with US$4.07 in 2018;
higher Mainline System ex-Gretna throughput of 2,689 kbpd in 2019 compared with 2,631 kbpd in 2018 driven by an increase in supply and continuous capacity optimization; and
the net favorable effect of translating United States dollar EBITDA at a higher Average Exchange Rate of $1.33 in 2019 compared with $1.28 in 2018.

The positive business factors above were partially offset by the unfavorable effect of a lower foreign exchange hedge rate used to lock-in United States dollar denominated revenues from the Canadian portion of the Mainline System.




55


GAS TRANSMISSION AND MIDSTREAM
 
 
Three months ended
June 30,
 
Six months ended
June 30,
 
2019

2018

 
2019

2018

(millions of Canadian dollars)
 
 
 
 
 
Earnings before interest, income taxes and depreciation and amortization
941

1,014

 
1,961

1,140

 
 
Three months ended June 30, 2019, compared with the three months ended June 30, 2018

EBITDA was negatively impacted by the absence of contributions in 2019 of approximately $73 million from MOLP and the provincially regulated portion of our Canadian gas gathering and processing businesses which were sold in the second half of 2018.

After taking into consideration the absence of earnings from the sold assets, EBITDA was comparable period-over-period and is primarily explained by the following significant business factors:
contributions from Valley Crossing Pipeline and certain other Offshore and US Transmission assets that were placed into service during 2018; and
the net favorable effect of translating United States dollar EBITDA at a higher Average Exchange Rate of $1.34 in 2019 compared with $1.29 in 2018.

The positive business factors above were partially offset by higher operating costs on our US Transmission assets primarily due to higher pipeline integrity costs.

Six months ended June 30, 2019, compared with the six months ended June 30, 2018

EBITDA was negatively impacted by the absence of contributions in 2019 of approximately $155 million from MOLP and the provincially regulated portion of our Canadian gas gathering and processing businesses which were sold in the second half of 2018.

After taking into consideration the absence of earnings from the sold assets, EBITDA was positively impacted by $923 million due to certain unusual, infrequent or other factors, primarily explained by the absence in 2019 of a loss of $913 million in 2018 on MOLP resulting from a revision to the fair value of the assets held for sale based on the sale price.

After taking into consideration the factor above, the remaining $53 million increase is explained by the following significant business factors:
contributions from Valley Crossing Pipeline and certain other Offshore and US Transmission assets that were placed into service during 2018; and
the net favorable effect of translating United States dollar EBITDA at a higher Average Exchange Rate of $1.33 in 2019 compared with $1.28 in 2018.

The positive business factors above were partially offset by higher operating costs on our US Transmission assets primarily due to higher pipeline integrity costs.



56


GAS DISTRIBUTION
 
Three months ended
June 30,
 
Six months ended
June 30,
 
2019

2018

 
2019

2018

(millions of Canadian dollars)
 
 
 
 
 
Earnings before interest, income taxes and depreciation and amortization
390

370

 
1,052

1,006

 

Enbridge Gas Distribution Inc. (EGD) and Union Gas Limited (Union Gas) were amalgamated on January 1, 2019. The amalgamated company has been renamed EGI. Post amalgamation the financial results of EGI reflect the combined performance of EGD and Union Gas.

Three months ended June 30, 2019, compared with the three months ended June 30, 2018

EBITDA increased by $20 million primarily explained by the following significant business factors:
increased earnings of $4 million resulting from colder weather experienced in our franchise service areas when compared to the corresponding period in 2018; and
increased earnings from higher distribution charges primarily resulting from increases in distribution rates and customer base.

Six months ended June 30, 2019, compared with the six months ended June 30, 2018

EBITDA was negatively impacted by $22 million due to certain unusual, infrequent or other factors, primarily explained by employee severance costs of $37 million in 2019 related to the amalgamation of EGD and Union Gas. This negative factor was partially offset by the absence in 2019 of a negative equity earnings adjustment of $9 million in 2018 at our equity investee, Noverco Inc., arising from the Tax Cuts and Jobs Act in the United States.

After taking into consideration the factors above, the remaining $68 million increase is primarily explained by the following significant business factors:
increased earnings of $42 million resulting from colder weather experienced in our franchise service areas when compared to the corresponding period in 2018;
increased earnings from higher distribution charges primarily resulting from increases in distribution rates and customer base; and
the absence in 2019 of forecasted earnings sharing which was recorded in 2018 under EGD's previous incentive rate structure.

RENEWABLE POWER GENERATION AND TRANSMISSION
 
 
 
Three months ended
June 30,
 
Six months ended
June 30,
 
2019

2018

 
2019

2018

(millions of Canadian dollars)
 

 

 
 

 

Earnings before interest, income taxes and depreciation and amortization
94

126

 
218

235

 
Three months ended June 30, 2019, compared with the three months ended June 30, 2018

EBITDA decreased by $32 million primarily due to weaker wind resources at United States wind facilities.



57


Six months ended June 30, 2019, compared with the six months ended June 30, 2018

EBITDA was positively impacted by $24 million due to certain unusual, infrequent and other factors, primarily explained by the following:
the absence in 2019 of 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
the absence in 2019 of a loss of $11 million in 2018 representing our share of losses incurred by our equity investee, Rampion Offshore Wind Limited, primarily due to the repair and restoration of damaged power transmission cables, for which we are seeking reimbursement.

After taking into consideration the factors above, the remaining $41 million decrease is primarily explained by the following significant business factors:
weaker wind resources at United States wind facilities; and
the absence in 2019 of $11 million in 2018 from a positive arbitration settlement related to our Canadian wind facilities.

The negative business factors above were partially offset by contributions from the Rampion Offshore Wind Project in 2019 which reached full operating capacity in the second quarter of 2018.

ENERGY SERVICES

 
Three months ended
June 30,
 
Six months ended
June 30,
 
2019

2018

 
2019

2018

(millions of Canadian dollars)
 

 

 
 

 

Earnings before interest, income taxes and depreciation and amortization
221

35

 
227

204

 
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 June 30, 2019, compared with the three months ended June 30, 2018

EBITDA was net positively impacted by $160 million due to certain unusual, infrequent or other factors, primarily explained by a non-cash, unrealized gain of $271 million in 2019 compared with a loss of $11 million in 2018 reflecting the revaluation of derivatives used to manage the profitability of transportation and storage transactions and manage the exposure to movements in commodity prices. This positive factor was partially offset by a non-cash, write-down of crude oil and natural gas inventories to the lower of cost or market of $138 million in 2019 compared with $16 million in 2018.

After taking into consideration the factors above, the remaining $26 million increase is primarily due to increased earnings from Energy Services' crude operations as a result of the widening of certain location and quality differentials during the second half of 2018 and the first quarter of 2019, which increased opportunities to generate profitable transportation margins that were realized during 2019.



58


Six months ended June 30, 2019, compared with the six months ended June 30, 2018

EBITDA was negatively impacted by $157 million due to certain unusual, infrequent and other factors, primarily explained by the following:
a non-cash, unrealized gain of $107 million in 2019 compared with a gain of $136 million in 2018 reflecting the revaluation of derivatives used to manage the profitability of transportation and storage transactions and manage the exposure to movements in commodity prices; and
a non-cash, write-down of crude oil and natural gas inventories to the lower of cost or market of $144 million in 2019 compared with $16 million in 2018.

After taking into consideration the factors above, the remaining $180 million increase is primarily due to increased earnings from Energy Services' crude operations as a result of the widening of certain location and quality differentials during the second half of 2018 and the first quarter of 2019, which increased opportunities to generate profitable transportation margins that were realized during 2019.

ELIMINATIONS AND OTHER
 
 
Three months ended
June 30,
 
Six months ended
June 30,
 
2019

2018

 
2019

2018

(millions of Canadian dollars)
 
 
 
 
 
Earnings/(loss) before interest, income taxes and depreciation and amortization
107

(118
)
 
355

(397
)
 
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 the impact of new business development activities and corporate investments.

Three months ended June 30, 2019, compared with the three months ended June 30, 2018

EBITDA was positively impacted by $245 million due to certain unusual, infrequent and other factors, primarily explained by the following:
a non-cash, unrealized gain of $192 million in 2019 compared with $5 million in 2018 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;
employee severance, transition and transformation costs of $18 million in 2019 compared with $26 million in 2018; and
the absence in 2019 of asset monetization transaction costs of $20 million in 2018.

After taking into consideration the factors above, the remaining $20 million decrease is primarily explained by the following significant business factors:
higher operating and administrative costs in the second quarter of 2019 due to the timing of the recovery of certain operating and administrative allocated to the business segments in 2018; and
a realized loss of $61 million in 2019 compared with a loss of $53 million in 2018 related to settlements under our foreign exchange risk management program, which partially offset the positive impact of a strengthening United States dollar on our United States business segments.



59


Six months ended June 30, 2019, compared with the six months ended June 30, 2018

EBITDA was positively impacted by $690 million due to certain unusual, infrequent and other factors, primarily explained by the following:
a non-cash, unrealized gain of $444 million in 2019 compared with a loss of $131 million in 2018 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;
employee severance, transition and transformation costs of $27 million in 2019 compared with $88 million in 2018; and
the absence in 2019 of asset monetization transaction costs of $20 million in 2018.

After taking into consideration the factors above, the remaining $62 million increase is primarily explained by lower operating and administrative costs in the first half of 2019 and the timing of the recovery of certain operating and administrative costs allocated to the business segments, which were more heavily weighted to the second half of 2018.

The positive business factors above were partially offset by a realized loss of $116 million in 2019 compared with a loss of $95 million in 2018 related to settlements under our foreign exchange risk management program, which partially offset the positive impact of a strengthening United States dollar on our United States business segments.



60


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 Date
2
Status
Expected
In-Service
Date
(Canadian dollars, unless stated otherwise)
 
 
 
 
LIQUIDS PIPELINES
 
 
 
 
 
1.
Other - Canada3
100
%
$0.3 billion
$0.3 billion
Complete
In-service
2.
Gray Oak Pipeline Project
22.8
%
US$0.7 billion
US$0.4 billion
Under construction
Q4 - 2019
3.
Canadian Line 3 Replacement Program
100
%
$5.3 billion
$4.6 billion
Substantially complete
2H - 2020
4.
U.S. Line 3 Replacement Program
100
%
US$2.9 billion
US$1.2 billion
Pre-construction
2H - 20204
5.
Other - United States5
100
%
US$0.5 billion
US$0.4 billion
Various stages
2020 - 2021
GAS TRANSMISSION AND MIDSTREAM
 
 
 
 
6.
Atlantic Bridge
100
%
US$0.6 billion
US$0.5 billion
Under construction
1H - 2020
7.
Spruce Ridge Project
100
%
$0.5 billion
$0.1 billion
Pre-construction
2H - 2021
8.
T-South Expansion Program
100
%
$1.0 billion
$0.3 billion
Pre-construction
2H - 2021
9.
Other - United States6
100
%
US$1.1 billion
US$0.3 billion
Various stages
2019 - 2023
GAS DISTRIBUTION
 
 
 
 
10.
Other - Canada
100%

$0.2 billion
No significant expenditures to date
Pre-construction
2H - 2020
11.
Dawn-Parkway Expansion
100
%
$0.2 billion
No significant expenditures to date
Pre-construction
2H - 2021
RENEWABLE POWER GENERATION AND TRANSMISSION
 
 
12.
Hohe See Offshore Wind Project and Expansion
25
%
$1.1 billion
$0.7 billion
Under construction
Q4 - 2019
(€0.67 billion)
(€0.5 billion)
13.
Other - Canada
25
%
$0.2 billion
No significant expenditures to date
Pre-construction
2H - 2021
14.
Saint-Nazaire France Offshore Wind Project
50
%
$1.8 billion
No significant expenditures to date
Pre-construction
2H - 2022
(€1.2 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 June 30, 2019.
3 Athabasca Oil Corporation Lateral Acquisition placed into service in the first quarter of 2019.
4 Update to in-service date pending MNPUC review of FEIS remediation.
5 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.
6 Includes the US$0.2 billion Stratton Ridge Project placed into service in the second quarter of 2019.

A full description of each of our projects is provided in our Annual Report on Form 10-K. Significant updates that have occurred since the date of filing are discussed below.


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LIQUIDS PIPELINES

Gray Oak Pipeline Project - a crude oil pipeline project connecting West Texas to destinations in the Corpus Christi and Sweeny/Freeport markets. The pipeline is a joint development with Phillips 66 and could have an ultimate capacity of approximately 900,000 barrels per day, subject to additional shipper commitments. Project execution forecasts were revised to reflect updated construction cost estimates and timing, with an expected in-service date in the fourth quarter of 2019.

GAS TRANSMISSION AND MIDSTREAM

Atlantic Bridge - expansion of the Algonquin Gas Transmission systems to transport 133 million cubic feet per day (mmcf/d) of natural gas to the New England Region. The expansion primarily consists of various meter station additions, the replacement of a natural gas pipeline in Connecticut and New York, compression additions in Connecticut, and a new compressor station in Massachusetts. The meter stations were placed into service in 2017 and 2018. The Connecticut portion of the project was placed into service in the fourth quarter of 2017. The New York portion of the project achieved partial in-service in November 2018 and the revised expected full in-service date is the fourth quarter of 2019, upon which we will begin earning incremental revenues. The final Massachusetts portion of the project is expected to be in service in the first half of 2020.

Spruce Ridge Project - a natural gas pipeline expansion of Westcoast Energy Inc.'s British Columbia (BC) Pipeline in northern BC. The project will provide additional capacity of up to 402 mmcf/d with a revised in-service date in the second half of 2021.

GAS DISTRIBUTION

Dawn-Parkway Expansion - the expansion of the existing Dawn to Parkway gas transmission system, which provides transportation service from Dawn to the Greater Toronto Area. The project will provide additional capacity of approximately 75 mmcf/d with an expected in-service date by the end of 2021.

RENEWABLE POWER GENERATION AND TRANSMISSION

Saint Nazaire France Offshore Wind Project - a wind project located off the west coast of France that will generate approximately 480 megawatts. We hold an effective 50% interest with EDF Renouvelables. Project revenues are backed by a 20-year fixed price power purchase agreement with added power production protection. Our share of the total investment in the project is $1.8 billion, with an equity contribution of $0.3 billion. The remainder of the construction will be financed through non-recourse project level debt.

GROWTH PROJECTS - REGULATORY MATTERS

United States Line 3 Replacement Program
On June 3, 2019, the Minnesota Court of Appeals rendered a decision on the MNPUC's adequacy determination of the FEIS for the U.S. L3R Program. While denying eight of the nine appealed items, the Minnesota Court of Appeals identified one issue that led them to reverse the adequacy determination. The Minnesota Court of Appeals remanded and directed the MNPUC to perform spill modeling analysis within the Lake Superior Watershed. On July 3, 2019, several parties to the original appeal of the FEIS, petitioned for Minnesota Supreme Court review of the Minnesota Court of Appeals June 3, 2019 decision. The MNPUC and we responded to those petitions on July 23, 2019 and the Minnesota Supreme Court is expected to decide whether to accept or decline further review by September 3, 2019.



62


As for environmental permits, the spill modeling required by the Court of Appeals is a prerequisite to finalizing other state permits. At this time, we cannot determine when all necessary permits will be issued pending receipt of further information from the MNPUC on a timeline to complete this work. The MNPUC’s statement on July 3, 2019 indicated that the agency will seek public comment and work expeditiously to address the FEIS deficiency. Additionally, the State permitting agencies’ have confirmed they will continue to advance their permitting work in parallel with MNPUC process. We expect to hear from the MNPUC regarding their updated process and timelines, after which we expect permitting agencies to re-align their timelines to the MNPUC process.

Construction costs for the Line 3 Replacement Program are tracking below budget in Canada and above budget in the United States due to permitting delays. Depending on the final in-service date, there is a risk that the project will exceed our total cost estimate of $9 billion.

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

Texas COLT Offshore Loading Project - the Texas COLT Offshore Loading Project will facilitate the direct loading of very large crude carriers from Freeport, Texas. The project consists of a terminal, a 42-inch offshore pipeline, platform and two single point mooring systems with connectivity to all key North American supply basins. During the first quarter of 2019 we acquired the position previously held by Kinder Morgan Inc. During the second quarter of 2019 the United States Maritime Administration and the United States Coast Guard temporarily suspended processing of Texas COLT Offshore Loading Project's deepwater port license application to assess further information regarding the addition of a marine vapor control system to the original project design. We continue to work closely with Federal and State permitting agencies and expect the project to be placed into service by 2022.

GAS TRANSMISSION AND MIDSTREAM

Texas Eastern Venice Lateral Project - a reversal and expansion of Texas Eastern’s line 40 from its existing Roads compressor station to a new delivery point with the proposed Gator Express pipeline just south of the Texas Eastern’s Larose compressor station. The project will deliver 1.5 billion cubic feet of feed gas to Venture Global’s proposed Plaquemines LNG export facility located in Plaquemine Parish, Louisiana. The project is expected to be placed into service by 2022.

We also have a large portfolio of additional projects under development that have not yet progressed to the point of public announcement.



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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. Our current financing plan does not require the use of equity funding alternatives and was the leading principle behind the suspension of our Dividend Reinvestment and Share Purchase Plan in November 2018.
 
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 June 30, 2019:
 
Maturity
Dates
Total
Facilities

Draws1

Available

(millions of Canadian dollars)
 
 
 
 
Enbridge Inc.
2021-2024
6,511

4,850

1,661

Enbridge (U.S.) Inc.
2021-2024
7,187

5,017

2,170

Enbridge Pipelines Inc.
2020
3,000

2,314

686

Enbridge Gas Inc.
2019-2021
2,017

926

1,091

Total committed credit facilities
 
18,715

13,107

5,608

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

On February 7, 2019 and February 8, 2019, we terminated certain Canadian and United States dollar credit facilities, including facilities held by Enbridge, EGI, EEP and SEP. We also increased existing facilities or obtained new facilities for Enbridge, Enbridge (U.S.) Inc. and EGI to substantially replace the terminated facilities. As a result, our total credit facility availability increased by approximately $444 million Canadian dollar equivalent.

On May 16, 2019, Enbridge Inc. entered into a three year, extendible credit facility for $641 million (¥52.5 billion) with a syndicate of Japanese banks.

In addition to the committed credit facilities noted above, we maintain $887 million of uncommitted demand credit facilities, of which $571 million were unutilized as at June 30, 2019. As at December 31, 2018, we had $807 million of uncommitted credit facilities, of which $548 million were unutilized.



64


Our net available liquidity of $6,316 million as at June 30, 2019, was inclusive of $708 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 June 30, 2019, we were in compliance with all debt covenants and we expect to continue to comply with such covenants.

LONG-TERM DEBT ISSUANCES
During the six months ended June 30, 2019, we completed the following long-term debt issuances:
Company
Issue Date
 
 
Principal Amount
(millions of Canadian dollars)

 
 
Enbridge Pipelines Inc.
 
 
 
 
February 2019
3.52% medium-term notes due February 2029
$600
 
February 2019
4.33% medium-term notes due February 2049
$600

LONG-TERM DEBT REPAYMENTS
During the six months ended June 30, 2019, we completed the following long-term debt repayments:
Company
Retirement/Repayment Date
 
 
Principal Amount
(millions of Canadian dollars, unless otherwise stated)
 
 
Enbridge Inc.
 
 
 
Repayment
 
 
 
 
February 2019
4.10% medium-term notes
$300
 
May 2019
Floating rate notes
 
$750
Enbridge Energy Partners, L.P.

 
 
Redemption
 
 
 
 
February 2019
8.05% fixed/floating rate junior subordinated notes due 2067
US$400
Repayment
 
 
 
 
March 2019
9.88% senior notes
 
US$500
Enbridge Pipelines (Southern Lights) L.L.C.
 
 
Repayment
 
 
 
 
June 2019
3.98% medium-term notes due 2040
 
US$23
Westcoast Energy Inc.
 
 
 
Repayment
 
 
 
 
January 2019
5.60% medium-term notes
$250
 
January 2019
5.60% medium-term notes
$50
 
May 2019
6.90% senior secured notes due 2019
 
$13
 
May 2019
4.34% senior secured notes due 2019
 
$2

Strong growth in internal cash flow, ready access to liquidity from diversified sources and a stable business model support our strong 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 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 June 30, 2019, our debt capitalization ratio was 47.4%, compared with 46.8% as at December 31, 2018.

There are no material restrictions on our cash. Total restricted cash of $59 million, as reported in the Consolidated Statements of Financial Position, primarily includes cash collateral and amounts received in respect of specific shipper commitments. Cash and cash equivalents held by certain 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 June 30, 2019. 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 June 30, 2019 and December 31, 2018, our net available liquidity totaled $6,316 million and $9,409 million, respectively.

SOURCES AND USES OF CASH
 
 
Six months ended
June 30,
 
2019

2018

(millions of Canadian dollars)
 

 

Operating activities
4,670

6,538

Investing activities
(3,457
)
(3,139
)
Financing activities
(1,058
)
(3,399
)
Effect of translation of foreign denominated cash and cash equivalents and restricted cash
(25
)
35

Increase in cash and cash equivalents and restricted cash
130

35

 
Significant sources and uses of cash for the six months ended June 30, 2019 and June 30, 2018 are summarized below:
 
Operating Activities
 
The decrease in cash flow provided by operations during the first half of 2019 was primarily driven by changes in operating assets and liabilities. 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 our business segments, the timing of tax payments, as well as timing of cash receipts and payments generally.
The factor above was partially offset by stronger contributions from our operating segments and contributions from new assets placed into service as discussed under Results of Operations.

Investing Activities
 
The increase in cash used in investing activities during the first half of 2019 was attributable to activity in 2018 that was not present in 2019, primarily relating to a distribution received in the second quarter of 2018 from Sabal Trail Transmission, LLC (Sabal Trail) as a partial return of capital for construction and development costs previously funded by Sabal Trail's partners.
The factor above is partially offset by lower additions to intangible assets in the first half of 2019 compared with the same period in 2018, primarily due to the wind down of the Cap and Trade program in the fourth quarter of 2018.
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
 
The decrease in cash used in financing activities during the first half of 2019 was primarily attributable to a net increase in commercial paper and credit facility draws, partially offset by higher repayments of maturing long-term debt and a decrease of long-term debt issued in 2019 when compared with the same period in 2018.


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Our common share dividend payments increased period-over-period primarily due to the increase in the common share dividend rate and an increase in the number of common shares outstanding in connection with the buy-in of our sponsored vehicles in the fourth quarter of 2018. These factors were partially offset by the suspension of our Dividend Reinvestment and Share Purchase Plan in the fourth quarter of 2018. In addition, in the first quarter of 2019, Westcoast Energy Inc. redeemed all of its outstanding Series 7 and Series 8 preference shares for a total payment of $300 million.
Distributions to noncontrolling interests and redeemable noncontrolling interests decreased as a result of the buy-in of our sponsored vehicles in the fourth quarter 2018.

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, seeking damages in excess of US$140 million. On September 7, 2018, the United States District Court for the Eastern District of Pennsylvania granted Eddystone Rail's motion to amend its complaint to add several affiliates of the corporate defendants as additional defendants (the Amended Complaint). Eddystone Rail’s chances of success on its Amended Complaint cannot be predicted at this time. Defendants have filed Answers and Counterclaims which, together with subsequent amendments, seek damages from Eddystone Rail in excess of US$32 million. The defendants’ chances of success on their counterclaims cannot be predicted at this time.

Dakota Access Pipeline
In February 2017, the Standing Rock Sioux Tribe and the Cheyenne River Sioux Tribe filed motions with the United States Court for the District of Columbia contesting the validity of the process used by the United States Army Corps of Engineers (Army Corps) to permit the Dakota Access Pipeline (DAPL). The Oglala Sioux and Yankton Sioux Tribes also filed claims in the case to challenge the Army Corps permit and environmental review process. In August 2018, in response to a Court order to reconsider components of its environmental analysis, the Army Corps issued its decision that no supplemental environmental analysis was required. All four Tribes have since amended their complaints to include claims challenging the adequacy of the Army Corps’ supplemental environmental analysis. An administrative record dispute has since been resolved and the case will now proceed to summary judgment briefing on the merits of the plaintiff's claims challenging the adequacy the Army Corps' remand process. According to the United States Court for the District of Columbia's schedule, the filing of summary judgment briefs will proceed throughout the remainder of the year.

Line 5 Dual Pipelines
In December 2018, Michigan law PA 359 was enacted which created the Mackinac Straits Corridor Authority (Corridor Authority) and authorized an agreement between us and the Corridor Authority for the construction of a tunnel under the Straits of Mackinac (Straits) to house a replacement for the Line 5 Dual Pipelines that currently cross the Straits (the Tunnel Project). On December 19, 2018, we entered into a Tunnel Project agreement with the Government of Michigan under the administration of former Governor Snyder. On March 28, 2019, the new Michigan Attorney General issued an opinion finding the Michigan law PA 359 unconstitutional. Immediately following the Attorney General’s opinion that the Michigan law was unconstitutional, the new Michigan Governor Whitmer issued a directive to Michigan agencies to cease any action implementing the statute.



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To resolve the legal uncertainty created by the Attorney General's opinion and the directive issued by Governor Whitmer, on June 6, 2019, we filed a complaint with the Michigan Court of Claims to establish the constitutional validity of Michigan law PA 359 and enforceability of various agreements entered into between us and the State of Michigan related to the construction of the Tunnel Project. On June 11, 2019, State officials confirmed that we had valid permits to conduct specified geotechnical work which is ongoing and necessary to prepare for Tunnel Project construction, but reiterated the Administration’s position that Michigan law PA 359 is unconstitutional and all agreements entered into under that statute by us and the State of Michigan are null and void.

On June 27, 2019, we received two separate court filings made by the Michigan Attorney General. In one filing the Michigan Attorney General has asked the Michigan Court of Claims to dismiss the claim we filed on June 6, 2019. We will respond in due course as part of the Michigan Court of Claims process and we are comfortable with the case we can make as described in our filing June 6, 2019. The second filing requests the Michigan Circuit Court to declare the easement that we have for the operation of the dual pipelines in the Straits to be invalid and enjoin continued operation of the dual pipelines in the Straits “as soon as possible after a reasonable notice period to allow orderly adjustments by affected parties”. We will vigorously defend this action.

Line 5 Easement
For over six years, we have been in discussions with the Bad River Band of the Lake Superior Tribe of Chippewa Indians (the Band) to resolve the Band’s concerns regarding the Line 5 pipeline within the Bad River Reservation (the Reservation). Only a small portion of the total easements across 12 miles of the Reservation are at issue. We hold an existing easement authorizing the majority of Line 5’s crossing within the Reservation issued in 1993 that remains in effect through 2043. On July 23, 2019, the Band filed a Complaint in the United States District Court of Wisconsin alleging that our continued use of Line 5 to transport crude oil and other liquids across the Reservation is a public nuisance under federal and state law, constitutes a trespass and alleging that the Band is entitled to ejectment of Line 5 from certain parcels within the Reservation. The Band seeks an order prohibiting us from using Line 5 to transport crude oil and natural gas liquids across the Reservation and removing the pipeline from the Reservation. The Band has not sought a Temporary Injunction to immediately discontinue operation of Line 5. While Line 5 continues to operate, the Band’s action could impact our ability to operate the pipeline on the Reservation. We have 60 days to respond to the Complaint and plan to continue working with the Band to find solutions to address their concerns.

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. 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 approximately $2.4 billion 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.

CHANGES IN ACCOUNTING POLICIES
 
Refer to Item 1. Financial Statements - Note 2. Changes in Accounting Policies.



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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 year ended December 31, 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 at June 30, 2019, 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 June 30, 2019 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 and Growth Projects - Regulatory Matters for discussion of other legal proceedings.

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, 2018, which could materially affect our financial condition or future results. There have been no material modifications to those risk factors.


69



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

None.



70


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
 
 
 
 
 
 
 
 
 
 
101.SCH*
 
Inline XBRL Taxonomy Extension Schema Document.
101.CAL*
 
Inline XBRL Taxonomy Extension Calculation Linkbase Document.
101.DEF*
 
Inline XBRL Taxonomy Extension Definition Linkbase Document.
101.LAB*
 
Inline XBRL Taxonomy Extension Label Linkbase Document.
101.PRE*
 
Inline XBRL Taxonomy Extension Presentation Linkbase Document.



71


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:
August 2, 2019
By:   
/s/ Al Monaco
 
 
Al Monaco
President and Chief Executive Officer
 
 
 
 
Date:
August 2, 2019
By:   
/s/ Colin K. Gruending
 
 
 
Colin K. Gruending
Executive Vice President and Chief Financial Officer
(Principal Financial Officer)


72