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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, 2020
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
 
ENBLOGOCOLOURC37.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 2,025,194,406 common shares outstanding as at July 22, 2020.
 

1


 
 
Page
 
PART I
  
Item 1.
6
Item 2.
37
Item 3.
62
Item 4.
63
 
PART II
 
Item 1.
64
Item 1A.
64
Item 2.
67
Item 3.
67
Item 4.
67
Item 5.
67
Item 6.
67
 
68


2


GLOSSARY
 
 
 
AOCI
Accumulated other comprehensive income/(loss)
Army Corps
United States Army Corps of Engineers
ASC
Accounting Standards Codification
ASU
Accounting Standards Update
Average Exchange Rate
Canadian to United States dollar average exchange rate
CER
Canada Energy Regulator
CPP Investments
Canada Pension Plan Investment Board
DCP Midstream
DCP Midstream, LLC
EBITDA
Earnings before interest, income taxes and depreciation and amortization
EEP
Enbridge Energy Partners, L.P.
EMF
Éolien Maritime France SAS
Enbridge
Enbridge Inc.
Exchange Act
United States Securities Exchange Act of 1934, as amended
FERC
Federal Energy Regulatory Commission
IJT
International Joint Tariff
kbpd
thousands of barrels per day
MATL
Montana-Alberta Tie Line
NGL
Natural gas liquids
OCI
Other comprehensive income/(loss)
SEP
Spectra Energy Partners, LP
Texas Eastern
Texas Eastern Transmission, LP

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: our corporate vision and strategy, including strategic priorities and enablers; the COVID-19 pandemic and the duration and impact thereof; the expected supply of, demand for and prices of crude oil, natural gas, natural gas liquids, liquified natural gas and renewable energy; anticipated utilization of our existing assets; expected earnings before interest, income taxes and depreciation and amortization (EBITDA); expected earnings/(loss); expected future cash flows; expected distributable cash flow; expected debt-to-EBITDA ratio; financial strength and flexibility; expectations on sources of liquidity and sufficiency of financial resources; expected strategic priorities and performance of the Liquids Pipelines, Gas Transmission and Midstream, Gas Distribution and Storage, Renewable Power Generation and Energy Services businesses; 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 the timing thereof; expected benefits of transactions, including the realization of efficiencies and synergies; expected future actions of regulators and related court proceedings and other litigation; anticipated competition; United States Line 3 Replacement Program (U.S. L3R Program); Line 5 related matters; the status of the Dakota Access Pipeline; estimated future dividends; our dividend payout policy; dividend growth and dividend payout expectation; and expectations on impact of our hedging program.

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 and risks include the following: the COVID-19 pandemic and the duration and impact thereof; 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, including the current weakness and volatility of such prices; anticipated utilization of our existing assets; 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 acquisitions and dispositions; the realization of anticipated benefits and synergies of transactions; governmental legislation; impact of our dividend policy on our future cash flows; our credit ratings; capital project funding; expected EBITDA; expected earnings/(loss); expected future cash flows; expected distributable cash flow; and estimated future dividends. Assumptions regarding the expected supply of and demand for crude oil, natural gas, NGL and renewable energy, and the prices of these commodities, are material to and underlie all forward-looking statements, as they may impact current and future levels of demand for our services. Similarly, exchange rates, inflation and interest rates impact the economies and business environments in which we operate and may impact levels of demand for our services and cost of inputs, and are therefore inherent in all forward-looking statements. Due to the interdependencies and correlation of these macroeconomic factors, the impact of any one assumption on a forward-looking statement cannot be determined with certainty, particularly with respect to expected EBITDA, expected earnings/(loss), expected future cash flows, expected distributable cash flow or estimated future dividends.

4


The most relevant assumptions associated with forward-looking statements on announced projects and projects under construction, including estimated completion dates and expected capital expenditures, include the following: the availability and price of labor and construction materials; the effects of inflation and foreign exchange rates on labor and material costs; the effects of interest rates on borrowing costs; the impact of weather and customer, government and regulatory approvals on construction and in-service schedules and cost recovery regimes; and the COVID-19 pandemic and the duration and impact thereof.

Our forward-looking statements are subject to risks and uncertainties pertaining to the successful execution of our strategic priorities, operating performance, regulatory parameters, changes in regulations applicable to our business, acquisitions, dispositions and other transactions, 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, supply of and demand for commodities, and the COVID-19 pandemic and the duration and impact thereof, 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 statement 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,
 
2020

2019

 
2020

2019

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

 

 
 

 

Operating revenues
 

 

 
 

 

Commodity sales
2,936

8,416

 
10,325

15,048

Transportation and other services
4,326

4,092

 
7,534

8,440

Gas distribution sales
694

755

 
2,110

2,631

Total operating revenues (Note 3)
7,956

13,263

 
19,969

26,119

Operating expenses
 
 
 
 
 
Commodity costs
2,858

8,129

 
10,021

14,694

Gas distribution costs
250

312

 
1,105

1,519

Operating and administrative
1,801

1,695

 
3,401

3,320

Depreciation and amortization
949

842


1,831

1,682

Total operating expenses
5,858

10,978

 
16,358

21,215

Operating income
2,098

2,285

 
3,611

4,904

Income from equity investments
327

413

 
490

826

Impairment of equity investments (Note 9)


 
(1,736
)

Other income/(expense)
 
 
 
 
 
Net foreign currency gain/(loss)
526

140

 
(430
)
354

Other
98

65

 
(93
)
111

Interest expense
(681
)
(637
)

(1,387
)
(1,322
)
Earnings before income taxes
2,368

2,266

 
455

4,873

Income tax expense (Note 11)
(591
)
(436
)

(42
)
(1,020
)
Earnings
1,777

1,830

 
413

3,853

(Earnings)/loss attributable to noncontrolling interests
(36
)
2


(5
)
(35
)
Earnings attributable to controlling interests
1,741

1,832

 
408

3,818

Preference share dividends
(94
)
(96
)

(190
)
(191
)
Earnings attributable to common shareholders
1,647

1,736


218

3,627

Earnings per common share attributable to common shareholders (Note 5)
0.82

0.86


0.11

1.80

Diluted earnings per common share attributable to common shareholders (Note 5)
0.82

0.86

 
0.11

1.80

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,
 
2020

2019

 
2020

2019

(unaudited; millions of Canadian dollars)
 

 

 
 

 

Earnings
1,777

1,830

 
413

3,853

Other comprehensive income/(loss), net of tax
 
 
 
 
 
Change in unrealized loss on cash flow hedges
(48
)
(235
)
 
(561
)
(427
)
Change in unrealized gain/(loss) on net investment hedges
340

127

 
(375
)
221

Other comprehensive income from equity investees
30

5

 
20

17

Excluded components of fair value hedges
5


 
8


Reclassification to earnings of loss on cash flow hedges
48

35

 
80

46

Reclassification to earnings of pension and other postretirement benefits (OPEB) amounts
4

5

 
7

43

Foreign currency translation adjustments
(2,701
)
(1,311
)
 
2,936

(2,602
)
Other comprehensive income/(loss), net of tax
(2,322
)
(1,374
)

2,115

(2,702
)
Comprehensive income/(loss)
(545
)
456

 
2,528

1,151

Comprehensive (income)/loss attributable to noncontrolling interests
50

51

 
(95
)
64

Comprehensive income/(loss) attributable to controlling interests
(495
)
507

 
2,433

1,215

Preference share dividends
(94
)
(96
)
 
(190
)
(191
)
Comprehensive income/(loss) attributable to common shareholders
(589
)
411

 
2,243

1,024

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,
 
2020

2019

2020

2019

(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
64,760

64,728

64,746

64,677

Shares issued on exercise of stock options
3

4

17

55

Balance at end of period
64,763

64,732

64,763

64,732

Additional paid-in capital
 
 
 

 

Balance at beginning of period
202

72

187


Stock-based compensation
5

17

19

21

Options exercised
(2
)
(6
)
(18
)
(49
)
Change in reciprocal interest


12

109

Repurchase of noncontrolling interest

65


65

Other
2

46

7

48

Balance at end of period
207

194

207

194

Deficit
 
 
 

 

Balance at beginning of period
(7,808
)
(3,640
)
(6,314
)
(5,538
)
Earnings attributable to controlling interests
1,741

1,832

408

3,818

Preference share dividends
(94
)
(96
)
(190
)
(191
)
Dividends paid to reciprocal shareholder
5

4

10

9

Common share dividends declared
(1,641
)
(1,500
)
(1,641
)
(1,500
)
Modified retrospective adoption of ASU 2016-13 Financial Instruments - Credit Losses (Note 2)


(66
)

Other

8

(4
)
10

Balance at end of period
(7,797
)
(3,392
)
(7,797
)
(3,392
)
Accumulated other comprehensive income/(loss) (Note 8)
 
 
 

 

Balance at beginning of period
3,989

1,449

(272
)
2,672

Other comprehensive income/(loss) attributable to common shareholders, net of tax
(2,236
)
(1,325
)
2,025

(2,603
)
Other



55

Balance at end of period
1,753

124

1,753

124

Reciprocal shareholding
 
 
 

 

Balance at beginning of period
(47
)
(51
)
(51
)
(88
)
Change in reciprocal interest


4

37

Balance at end of period
(47
)
(51
)
(47
)
(51
)
Total Enbridge Inc. shareholders’ equity
66,626

69,354

66,626

69,354

Noncontrolling interests
 
 
 

 

Balance at beginning of period
3,448

3,614

3,364

3,965

Earnings/(loss) attributable to noncontrolling interests
36

(2
)
5

35

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




 
 
Change in unrealized loss on cash flow hedges
(1
)
(4
)
(3
)
(5
)
Foreign currency translation adjustments
(85
)
(45
)
93

(94
)
 
(86
)
(49
)
90

(99
)
Comprehensive income/(loss) attributable to noncontrolling interests
(50
)
(51
)
95

(64
)
Contributions
5

6

20

9

Distributions
(88
)
(54
)
(164
)
(100
)
Repurchase of noncontrolling interest

(65
)

(65
)
Redemption of preferred shares held by subsidiary



(300
)
Other

1


6

Balance at end of period
3,315

3,451

3,315

3,451

Total equity
69,941

72,805

69,941

72,805

Dividends paid per common share
0.810

0.738

1.620

1.476

Earnings per common share attributable to common shareholders (Note 5)
0.82

0.86

0.11

1.80

Diluted earnings per common share attributable to common shareholders (Note 5)
0.82

0.86

0.11

1.80

See accompanying notes to the interim consolidated financial statements.

8


ENBRIDGE INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS

 
Six months ended
June 30,
 
2020

2019

(unaudited; millions of Canadian dollars)
 
 
Operating activities
 
 
Earnings
413

3,853

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

 

Depreciation and amortization
1,831

1,682

Deferred income tax (recovery)/expense
(223
)
809

Changes in unrealized (gain)/loss on derivative instruments, net (Note 10)
824

(1,112
)
Earnings from equity investments
(490
)
(826
)
Distributions from equity investments
821

907

Impairment of equity investments (Note 9)
1,736


Other
210

36

Changes in operating assets and liabilities
103

(679
)
Net cash provided by operating activities
5,225

4,670

Investing activities
 

 

Capital expenditures
(2,352
)
(2,785
)
Long-term investments and restricted long-term investments
(335
)
(700
)
Distributions from equity investments in excess of cumulative earnings
253

268

Additions to intangible assets
(104
)
(100
)
Proceeds from dispositions
245


Affiliate loans, net
27

(140
)
Net cash used in investing activities
(2,266
)
(3,457
)
Financing activities
 

 

Net change in short-term borrowings
(543
)
(108
)
Net change in commercial paper and credit facility draws
854

4,015

Debenture and term note issues, net of issue costs
3,479

1,195

Debenture and term note repayments
(3,268
)
(2,584
)
Contributions from noncontrolling interests
20

9

Distributions to noncontrolling interests
(164
)
(100
)
Common shares issued
3

18

Preference share dividends
(190
)
(191
)
Common share dividends
(3,280
)
(2,976
)
Redemption of preferred shares held by subsidiary

(300
)
Other
(35
)
(36
)
Net cash used in financing activities
(3,124
)
(1,058
)
Effect of translation of foreign denominated cash and cash equivalents and restricted cash
(14
)
(25
)
Net increase/(decrease) in cash and cash equivalents and restricted cash
(179
)
130

Cash and cash equivalents and restricted cash at beginning of period
676

637

Cash and cash equivalents and restricted cash at end of period
497

767

See accompanying notes to the interim consolidated financial statements.

9


ENBRIDGE INC.
CONSOLIDATED STATEMENTS OF FINANCIAL POSITION

 
June 30,
2020

December 31,
2019

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

 

Assets
 

 

Current assets
 

 

Cash and cash equivalents
462

648

Restricted cash
35

28

Accounts receivable and other
5,461

6,781

Accounts receivable from affiliates
38

69

Inventory
961

1,299

 
6,957

8,825

Property, plant and equipment, net
96,302

93,723

Long-term investments
15,352

16,528

Restricted long-term investments
508

434

Deferred amounts and other assets
7,925

7,433

Intangible assets, net
2,158

2,173

Goodwill
34,387

33,153

Deferred income taxes
1,105

1,000

Total assets
164,694

163,269

 
 
 
Liabilities and equity
 

 

Current liabilities
 

 

Short-term borrowings
355

898

Accounts payable and other
7,340

10,063

Accounts payable to affiliates
4

21

Interest payable
644

624

Current portion of long-term debt
3,097

4,404

 
11,440

16,010

Long-term debt
63,680

59,661

Other long-term liabilities
9,505

8,324

Deferred income taxes
10,128

9,867

 
94,753

93,862

Contingencies (Note 13)




Equity
 

 

Share capital
 

 

Preference shares
7,747

7,747

Common shares (2,025 and 2,025 outstanding at June 30, 2020 and December 31, 2019, respectively)
64,763

64,746

Additional paid-in capital
207

187

Deficit
(7,797
)
(6,314
)
Accumulated other comprehensive income/(loss) (Note 8)
1,753

(272
)
Reciprocal shareholding
(47
)
(51
)
Total Enbridge Inc. shareholders’ equity
66,626

66,043

Noncontrolling interests
3,315

3,364

 
69,941

69,407

Total liabilities and equity
164,694

163,269

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 consolidated financial statements and notes for the year ended December 31, 2019. 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 consolidated financial statements for the year ended December 31, 2019, 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 ACCOUNTING STANDARDS
Clarifying Interaction between Collaborative Arrangements and Revenue from Contracts with Customers
Effective January 1, 2020, we adopted Accounting Standards Update (ASU) 2018-18 on a retrospective basis. The new standard was issued in November 2018 to provide clarity on when transactions between entities in a collaborative arrangement should be accounted for under the new revenue standard, Accounting Standards Codification (ASC) 606. In determining whether transactions in collaborative arrangements should be accounted for 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 adoption of this ASU did not have a material impact on our consolidated financial statements.

Disclosure Effectiveness
Effective January 1, 2020, we adopted ASU 2018-13 on both a retrospective and prospective basis depending on the change. The new standard was issued to improve the disclosure requirements for fair value measurements by eliminating and modifying some disclosures, while also adding new disclosures. The adoption of this ASU did not have a material impact on our consolidated financial statements.


11


Accounting for Credit Losses
Effective January 1, 2020, we adopted ASU 2016-13 on a modified retrospective basis.

The new standard 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. The previous accounting treatment used the incurred loss methodology for recognizing credit losses that delayed the recognition until it was probable a loss had 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 recognizes as an allowance its estimate of expected credit losses, which the Financial Accounting Standards Board believes results 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.

For accounts receivable, a loss allowance matrix is utilized to measure lifetime expected credit losses. The matrix contemplates historical credit losses by age of receivables, adjusted for any forward-looking information and management expectations. Other loan receivables and off-balance sheet commitments in scope of the new standard utilize a discounted cash flow methodology which calculates the current expected credit losses based on historical default probability rates associated with the credit rating of the counterparty and the related term of the loan or commitment, adjusted for forward-looking information and management expectations.

On January 1, 2020 we recorded $66 million of additional Deficit on our Statements of Financial Position in connection with the adoption of ASU 2016-13. The adoption of this ASU did not have a material impact on the Consolidated Statements of Earnings, Comprehensive Income or Cash Flows during the period.

FUTURE ACCOUNTING POLICY CHANGES
Reference Rate Reform
ASU 2020-04 was issued in March 2020 to provide temporary optional guidance in accounting for reference rate reform. The new guidance provides optional expedients and exceptions for applying generally accepted accounting principles when accounting for contract modifications, hedging relationships and other transactions impacted by rate reform, subject to meeting certain criteria. ASU 2020-04 is effective as of March 12, 2020 through December 31, 2022. We had no transactions to which the ASU was applied since adoption and we are considering the impact of reference rate reform on our consolidated financial statements.

Clarifying Interaction between Equity Securities, Equity Method Investments and Derivatives
ASU 2020-01 was issued in January 2020 and clarifies that observable transactions should be considered for the purpose of applying the measurement alternative in accordance with ASC 321 immediately before the application or upon discontinuance of the equity method of accounting. Furthermore, the ASU clarifies that forward contracts or purchased options on equity securities are not out of scope of ASC 815 guidance only because, upon the contracts’ exercise, the equity securities could be accounted for under the equity method of accounting or fair value option. ASU 2020-01 is effective January 1, 2021 with early adoption permitted and is applied prospectively. The adoption of ASU 2020-01 is not expected to have a material impact on our consolidated financial statements.


12


Accounting for Income Taxes
ASU 2019-12 was issued in December 2019 with the intent of simplifying the accounting for income taxes. The accounting update removes certain exceptions to the general principles in ASC 740 as well as provides simplification by clarifying and amending existing guidance. ASU 2019-12 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.

Disclosure Effectiveness
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. The adoption of ASU 2018-14 is not expected to have a material impact on our consolidated financial statements.

3. REVENUES

REVENUE FROM CONTRACTS WITH CUSTOMERS
Major Products and Services
 
Liquids Pipelines

Gas Transmission and Midstream

Gas Distribution and Storage

Renewable Power Generation

Energy Services

Eliminations and Other

Consolidated

Three months ended
June 30, 2020
(millions of Canadian dollars)
 

 

 

 

 

 

 

Transportation revenues
2,141

1,126

151




3,418

Storage and other revenues
24

66

56




146

Gas gathering and processing revenues

5





5

Gas distribution revenue


686




686

Electricity and transmission revenues



54



54

Total revenue from contracts with customers
2,165

1,197

893

54



4,309

Commodity sales




2,936


2,936

Other revenues1,2
598

5

8

96

11

(7
)
711

Intersegment revenues
182

1

2


2

(187
)

Total revenues
2,945

1,203

903

150

2,949

(194
)
7,956


13


 
Liquids Pipelines

Gas Transmission and Midstream

Gas Distribution and Storage

Renewable Power Generation

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 revenues


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 and Storage

Renewable Power Generation

Energy Services

Eliminations and Other

Consolidated

Six months ended
June 30, 2020
(millions of Canadian dollars)
 

 

 

 

 

 

 

Transportation revenues
4,581

2,381

366




7,328

Storage and other revenues
50

145

103




298

Gas gathering and processing revenues

12





12

Gas distribution revenue


2,103




2,103

Electricity and transmission revenues



104



104

Total revenue from contracts with customers
4,631

2,538

2,572

104



9,845

Commodity sales




10,325


10,325

Other revenues1,2
(419
)
21

7

199

4

(13
)
(201
)
Intersegment revenues
267

1

6


18

(292
)

Total revenues
4,479

2,560

2,585

303

10,347

(305
)
19,969

 
Liquids Pipelines

Gas Transmission and Midstream

Gas Distribution and Storage

Renewable Power Generation

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 revenues


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

1 Includes mark-to-market gains/(losses) from our hedging program for the three months ended June 30, 2020 and 2019 of $531 million gain and $126 million gain, respectively and for the six months ended June 30, 2020 and 2019 of $575 million loss and $384 million gain, respectively.
2 Includes revenues from lease contracts for the three months ended June 30, 2020 and 2019 of $157 million and $151 million, respectively and for the six months ended June 30, 2020 and 2019 of $315 million and $315 million, respectively.


14


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 revenue information for management to consider in evaluating performance.
Contract Balances
 
Receivables

Contract Assets

Contract Liabilities

(millions of Canadian dollars)
 
 
 
Balance as at December 31, 2019
2,099

216

1,424

Balance as at June 30, 2020
1,642

228

1,540



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 payment is unconditional. Amounts included in contract assets are transferred to accounts receivable when our right to receive 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, 2020 included in contract liabilities at the beginning of the period was $21 million and $107 million, respectively. Increases in contract liabilities from cash received, net of amounts recognized as revenues during the three and six months ended June 30, 2020 were $104 million and $180 million, respectively.
Performance Obligations
There were no material revenues recognized in the three and six months ended June 30, 2020 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 $63.7 billion, of which $3.5 billion and $6.1 billion is expected to be recognized during the six months ending December 31, 2020, and the year ending December 31, 2021, 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.

15


Recognition and Measurement of Revenues
 
Liquids Pipelines

Gas Transmission and Midstream

Gas Distribution and Storage

Renewable Power Generation

Energy Services

Consolidated

Three months ended
June 30, 2020
(millions of Canadian dollars)
 

 

 

 

 

 
Revenues from products transferred at a point in time


15



15

Revenues from products and services transferred over time1
2,165

1,197

878

54


4,294

Total revenue from contracts with customers
2,165

1,197

893

54


4,309

 
Liquids Pipelines

Gas Transmission and Midstream

Gas Distribution and Storage

Renewable Power Generation

Energy Services

Consolidated

Three months ended
June 30, 2019
(millions of Canadian dollars)
 
 
 
 
 
 
Revenues from products transferred at a point in time

3

17



20

Revenues from products and services transferred over time1
2,255

1,274

960

43


4,532

Total revenue from contracts with customers
2,255

1,277

977

43


4,552

 
Liquids Pipelines

Gas Transmission and Midstream

Gas Distribution and Storage

Renewable Power Generation

Energy Services

Consolidated

Six months ended
June 30, 2020
(millions of Canadian dollars)
 

 

 

 

 

 
Revenues from products transferred at a point in time


30



30

Revenues from products and services transferred over time1
4,631

2,538

2,542

104


9,815

Total revenue from contracts with customers
4,631

2,538

2,572

104


9,845

 
Liquids Pipelines

Gas Transmission and Midstream

Gas Distribution and Storage

Renewable Power Generation

Energy Services

Consolidated

Six months ended
June 30, 2019
(millions of Canadian dollars)
 
 
 
 
 
 
Revenues from products transferred at a point in time

3

34



37

Revenues from products and services transferred over time1
4,496

2,580

3,102

93


10,271

Total revenue from contracts with customers
4,496

2,583

3,136

93


10,308

1  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.


16


4. SEGMENTED INFORMATION
 
Liquids Pipelines

Gas Transmission and Midstream

Gas Distribution and Storage

Renewable Power Generation

Energy Services

Eliminations and Other

Consolidated

Three months ended
June 30, 2020
(millions of Canadian dollars)
 

 
 

 

 

 

 

Revenues
2,945

1,203

903

150

2,949

(194
)
7,956

Commodity and gas distribution costs
(1
)

(254
)

(3,021
)
168

(3,108
)
Operating and administrative
(782
)
(438
)
(269
)
(37
)
(29
)
(246
)
(1,801
)
Income/(loss) from equity investments
148

168

(8
)
21

(2
)

327

Other income
30

17

11

29

4

533

624

Earnings/(loss) before interest, income taxes, and depreciation and amortization
2,340

950

383

163

(99
)
261

3,998

Depreciation and amortization
 
 
 
 
 
 
(949
)
Interest expense
 

 

 

 

 

 

(681
)
Income tax expense
 

 

 

 

 

 

(591
)
Earnings
 
 

 

 

 

 

1,777

Capital expenditures1
561

429

204

7

1

19

1,221

 
Liquids Pipelines

Gas Transmission and Midstream

Gas Distribution and Storage

Renewable Power Generation

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 and Storage

Renewable Power Generation

Energy Services

Eliminations and Other

Consolidated

Six months ended
June 30, 2020
(millions of Canadian dollars)
 

 
 

 

 

 

 

Revenues
4,479

2,560

2,585

303

10,347

(305
)
19,969

Commodity and gas distribution costs
(8
)

(1,126
)

(10,264
)
272

(11,126
)
Operating and administrative
(1,647
)
(945
)
(518
)
(87
)
(57
)
(147
)
(3,401
)
Income from equity investments
345

93

15

37



490

Impairment of equity investments

(1,736
)




(1,736
)
Other income/(expense)
21

(76
)
31

30

(4
)
(525
)
(523
)
Earnings/(loss) before interest, income taxes, and depreciation and amortization
3,190

(104
)
987

283

22

(705
)
3,673

Depreciation and amortization
 
 
 
 
 
 
(1,831
)
Interest expense
 

 

 

 

 

 

(1,387
)
Income tax expense
 

 

 

 

 

 

(42
)
Earnings
 
 

 

 

 

 

413

Capital expenditures1
1,061

820

426

30

1

41

2,379

 
Liquids Pipelines

Gas Transmission and Midstream

Gas Distribution and Storage

Renewable Power Generation

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

 
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 for the three and six months ended June 30, 2020 and 2019, resulting from our reciprocal investment in Noverco Inc. (Noverco).
 
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.


18


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,
 
2020

2019

 
2020

2019

(number of common shares in millions)
 

 

 
 

 

Weighted average shares outstanding
2,019

2,018

 
2,019

2,017

Effect of dilutive options
1

3

 
2

3

Diluted weighted average shares outstanding
2,020

2,021


2,021

2,020



For the three months ended June 30, 2020 and 2019, 34.6 million and 21.3 million, respectively, anti-dilutive stock options with a weighted average exercise price of $51.00 and $53.33, respectively, were excluded from the diluted earnings per common share calculation.

For the six months ended June 30, 2020 and 2019, 25.7 million and 15.9 million, respectively, anti-dilutive stock options with a weighted average exercise price of $52.71 and $53.99, respectively, were excluded from the diluted earnings per common share calculation.

DIVIDENDS PER SHARE
On July 22, 2020, our Board of Directors declared the following quarterly dividends. All dividends are payable on September 1, 2020 to shareholders of record on August 14, 2020.
 
Dividend per share

Common Shares1

$0.81000

Preference Shares, Series A

$0.34375

Preference Shares, Series B

$0.21340

Preference Shares, Series C2

$0.16779

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 P

$0.27369

Preference Shares, Series R

$0.25456

Preference Shares, Series 1

US$0.37182

Preference Shares, Series 3

$0.23356

Preference Shares, Series 5

US$0.33596

Preference Shares, Series 7

$0.27806

Preference Shares, Series 9

$0.25606

Preference Shares, Series 113

$0.24613

Preference Shares, Series 134

$0.19019

Preference Shares, Series 15

$0.27500

Preference Shares, Series 17

$0.32188

Preference Shares, Series 19

$0.30625

1 The quarterly dividend per common share was increased 9.8% to $0.81 from $0.738, effective March 1, 2020.
2 The quarterly dividend per share paid on Series C was decreased to $0.16779 from $0.25458 on June 1, 2020 and was increased to $0.25458 from $0.25305 on March 1, 2020, due to reset on a quarterly basis following the date of issuance of the Series C Preference Shares.
3 The quarterly dividend per share paid on Series 11 was decreased to $0.24613 from $0.275 on March 1, 2020, due to the reset of the annual dividend on March 1, 2020, and every five years thereafter.
4
The quarterly dividend per share paid on Series 13 was decreased to $0.19019 from $0.275 on June 1, 2020, due to the reset of the annual dividend on June 1, 2020, and every five years thereafter.
 

19


6. ACQUISITIONS AND DISPOSITIONS

Line 10 Crude Oil Pipeline
In the first quarter of 2018, we satisfied the condition as set out in our agreements for the sale of our Line 10 crude oil pipeline (Line 10), which originates near Hamilton, Ontario and terminates at West Seneca, New York. Our subsidiaries, Enbridge Pipelines Inc. and Enbridge Energy Partners, L.P. (EEP), owned the Canadian and United States portions of Line 10, respectively, and the related assets were included in our Liquids Pipelines segment. The transaction closed on June 1, 2020. No gain or loss on disposition was recorded.

Montana-Alberta Tie Line
In the fourth quarter of 2019, we committed to a plan to sell the Montana-Alberta Tie Line (MATL) transmission assets, a 345 kilometer transmission line from Great Falls, Montana to Lethbridge, Alberta. Its related assets were included in our Renewable Power Generation segment. The purchase and sale agreement was signed in January 2020. On May 1, 2020 we closed the sale of MATL for cash proceeds of approximately $189 million. After closing adjustments, a gain on disposal of $4 million was included in Other income/(expense) in the Consolidated Statements of Earnings for the six months ended June 30, 2020.

Ozark Gas Transmission
In the first quarter of 2020, we agreed to sell our Ozark Gas Transmission and Ozark Gas Gathering assets (Ozark assets). The Ozark assets are composed of a 367 mile transmission system that extends from southeastern Oklahoma through Arkansas to southeastern Missouri, and a fee-based 330 mile gathering system that accesses Fayetteville Shale and Arkoma production. These assets were included in our Gas Transmission and Midstream segment.

On April 1, 2020 we closed the sale of the Ozark assets for cash proceeds of approximately $63 million (US$45 million). After closing adjustments, a gain on disposal of $1 million (US$1 million) was included in Other income/(expense) in the Consolidated Statements of Earnings for the six months ended June 30, 2020.

7.
DEBT
 
CREDIT FACILITIES
The following table provides details of our committed credit facilities as at June 30, 2020:
 
 
 
Maturity
Total
Facilities

Draws1

Available

(millions of Canadian dollars)
 
 
 
 
Enbridge Inc.
2021-2024
12,013

5,531

6,482

Enbridge (U.S.) Inc.
2021-2024
7,491

2,531

4,960

Enbridge Pipelines Inc.
20212
3,000

1,985

1,015

Enbridge Gas Inc.
20212
2,000

355

1,645

Total committed credit facilities
 
24,504

10,402

14,102

 
1
Includes facility draws and commercial paper issuances that are back-stopped by credit facility.
2
Maturity date is inclusive of the one-year term out option.

On February 24, 2020, Enbridge Inc. entered into a two year, non-revolving credit facility for US$1 billion with a syndicate of lenders.

On February 25, 2020, Enbridge Inc. entered into two, one year, non-revolving, bilateral credit facilities for a total of US$500 million.


20


On March 31, 2020, Enbridge Inc. entered into a one year, revolving, syndicated credit facility for $1.7 billion. On April 9, 2020, Enbridge Inc. exercised an accordion provision and increased the facility to $3.0 billion.

On July 23 and 24, 2020, we extended approximately $10.0 billion of our 364 day extendible credit facilities to July 2021, inclusive of a one-year term out provision to July 2022.

In addition to the committed credit facilities noted above, we maintain $795 million of uncommitted demand credit facilities, of which $519 million were unutilized as at June 30, 2020. As at December 31, 2019, we had $916 million of uncommitted credit facilities, of which $476 million were unutilized.

Our credit facilities carry a weighted average standby fee of 0.2% per annum on the unused portion and draws bear interest at market rates. Certain credit facilities serve as a back-stop to the commercial paper programs and we have the option to extend such facilities, which are currently scheduled to mature from 2021 to 2024.

As at June 30, 2020 and December 31, 2019, commercial paper and credit facility draws, net of short-term borrowings and non-revolving credit facilities that mature within one year, of $9,365 million and $8,974 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, 2020, we completed the following long-term debt issuances:
Company
Issue Date
 
 
Principal Amount
(millions of Canadian dollars, unless otherwise stated)
 
 
Enbridge Inc.
 
 
 
 
February 2020
Floating rate notes
 
US$750
 
May 2020
3.20% medium-term notes
 
$750
 
May 2020
2.44% medium-term notes
 
$550
Enbridge Gas Inc.
 
 
 
 
April 2020
2.90% medium-term notes
 
$600
 
April 2020
3.65% medium-term notes
 
$600


On July 8, 2020, Enbridge Inc. issued US$1.0 billion of 60-year hybrid subordinated notes payable semi-annually in arrears. For the initial 10 years, the notes carry a fixed interest rate of 5.75%. Subsequently, the interest rate per annum will be reset to equal the 5-year United States Treasury rate plus 5.31% every five years from years 10 to 30 and the 5-year United States Treasury rate plus 6.06% every five years from years 30 to 60. The notes mature on July 15, 2080 and are redeemable on year 10 and every five years thereafter.


21


LONG-TERM DEBT REPAYMENTS
During the six months ended June 30, 2020, we completed the following long-term debt repayments:
Company
Repayment Date
 
 
Principal Amount
(millions of Canadian dollars, unless otherwise stated)
 
 
Enbridge Inc.
 
 
 
January 2020
Floating rate notes
 
US$700
 
March 2020
4.53% medium-term notes
 
$500
 
June 2020
Floating rate notes
 
US$500
Enbridge Pipelines (Southern Lights) L.L.C.
 
 
 
June 2020
3.98% senior notes due 2040
 
US$26
Enbridge Pipelines Inc.
 
 
 
 
April 2020
4.45% medium-term notes
$350
Enbridge Southern Lights LP
 
 
 
 
June 2020
4.01% senior notes due 2040
 
$7
Spectra Energy Partners, LP
 
 
 
January 2020
6.09% senior secured notes
 
US$111
 
June 2020
Floating rate notes
 
US$400
Westcoast Energy Inc.
 
 
 

January 2020
9.90% debentures
 
$100


SUBORDINATED TERM NOTES
As at June 30, 2020 and December 31, 2019, our fixed-to-floating subordinated term notes had a principal value of $6,758 million and $6,550 million, respectively.

FAIR VALUE ADJUSTMENT
As at June 30, 2020, the net fair value adjustment for total debt assumed in the acquisition of Spectra Energy was $810 million. During the three and six months ended June 30, 2020, the amortization of the fair value adjustment, recorded as a reduction to Interest expense in the Consolidated Statements of Earnings, was $14 million and $29 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, 2020, we were in compliance with all debt covenants.


22


8.
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, 2020 and 2019 are as follows:
 
Cash Flow 
Hedges

Excluded Components of Fair Value Hedges

Net
Investment
Hedges

Cumulative
Translation
Adjustment

Equity
Investees

Pension and
OPEB
Adjustment

Total

(millions of Canadian dollars)
 
 
 
 
 
 
 
Balance as at January 1, 2020
(1,073
)

(317
)
1,396

67

(345
)
(272
)
Other comprehensive income/(loss) retained in AOCI
(738
)
8

(375
)
2,843

25


1,763

Other comprehensive (income)/loss reclassified to earnings
 
 
 
 
 
 


Interest rate contracts1
103






103

Foreign exchange contracts2
2






2

Amortization of pension and OPEB actuarial loss and prior service costs4






9

9

 
(633
)
8

(375
)
2,843

25

9

1,877

Tax impact
 

 
 

 

 

 

 

Income tax on amounts retained in AOCI
180




(5
)

175

Income tax on amounts reclassified to earnings
(25
)




(2
)
(27
)
 
155




(5
)
(2
)
148

Balance as at June 30, 2020
(1,551
)
8

(692
)
4,239

87

(338
)
1,753

 
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 contracts2
2





2

Other contracts3
(3
)




(3
)
Amortization of pension and OPEB actuarial loss and prior service costs4





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

 
1 Reported within Interest expense in the Consolidated Statements of Earnings.
2
Reported within Transportation and other services revenues and Net foreign currency gain/(loss) in the Consolidated Statements of Earnings.
3 Reported within Operating and administrative expense in the Consolidated Statements of Earnings.
4 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.

23


9. IMPAIRMENT OF EQUITY INVESTMENTS
 
For the six months ended June 30, 2020, we recorded a loss of $1,736 million resulting from an other than temporary impairment to the carrying value of our equity method investment in DCP Midstream, LLC (DCP Midstream). DCP Midstream holds a limited partner interest in and is the owner of the general partner of DCP Midstream, LP. The impairment in our equity investment is related to a decline in the market price of DCP Midstream, LP publicly-traded units as at March 31, 2020. In addition, we recorded a loss of $324 million from our equity pick up of the loss recorded by DCP Midstream in relation to DCP Midstream, LP's asset and goodwill impairment. This is recorded within Income from equity investments in the Consolidated Statements of Earnings. Our investment in DCP Midstream is part of the Gas Transmission and Midstream segment and our carrying value of the investment as at June 30, 2020 and December 31, 2019 was $325 million and $2,193 million, respectively.

10. 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 cash flow, fair value 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. We 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. 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 2.9%.

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, 2020, we do not have any pay floating-receive fixed interest rate swaps outstanding.
 

24


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 3.1%.
  
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.
 
COVID-19 PANDEMIC RISK
The spread of the COVID-19 pandemic has caused significant volatility in Canada, the United States and international markets. While we have taken proactive measures to deliver energy safely and reliably during this pandemic, given the ongoing dynamic nature of the circumstances surrounding COVID-19, the impact of this pandemic on our business remains uncertain.

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.


25


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.

June 30, 2020
Derivative
Instruments
Used as
Cash Flow Hedges

Derivative
Instruments
Used as Net
Investment Hedges

Derivative Instruments Used as Fair Value Hedges

Non-
Qualifying
Derivative Instruments

Total Gross
Derivative
Instruments as Presented

 
Amounts
Available for Offset

Total Net
Derivative Instruments

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


18

55

73

 
(36
)
37

Commodity contracts
1



276

277

 
(152
)
125

 
1


18

331

350

1 
(188
)
162

Deferred amounts and other assets
 
 
 
 
 
 
 
 
Foreign exchange contracts
18


69

158

245

 
(112
)
133

Commodity contracts
1



62

63

 
(23
)
40

 
19


69

220

308

 
(135
)
173

Accounts payable and other
 
 
 
 
 
 
 
 
Foreign exchange contracts
(5
)
(17
)
(2
)
(540
)
(564
)
 
36

(528
)
Interest rate contracts
(832
)


(15
)
(847
)
 

(847
)
Commodity contracts



(344
)
(344
)
 
152

(192
)
Other Contracts



(1
)
(1
)
 

(1
)
 
(837
)
(17
)
(2
)
(900
)
(1,756
)
2 
188

(1,568
)
Other long-term liabilities
 
 
 
 
 
 
 
 
Foreign exchange contracts



(1,524
)
(1,524
)
 
112

(1,412
)
Interest rate contracts
(390
)



(390
)
 

(390
)
Commodity contracts



(80
)
(80
)
 
23

(57
)
Other contracts
(3
)


(3
)
(6
)
 

(6
)
 
(393
)


(1,607
)
(2,000
)
 
135

(1,865
)
Total net derivative assets/(liabilities)
 
 
 
 
 
 
 
 
Foreign exchange contracts
13

(17
)
85

(1,851
)
(1,770
)
 

(1,770
)
Interest rate contracts
(1,222
)


(15
)
(1,237
)
 

(1,237
)
Commodity contracts
2



(86
)
(84
)
 

(84
)
Other contracts
(3
)


(4
)
(7
)
 

(7
)
 
(1,210
)
(17
)
85

(1,956
)
(3,098
)
 

(3,098
)
1
As at June 30, 2020, $349 million was reported within Accounts receivable and other and $1 million within Accounts receivable from affiliates on the Consolidated Statements of Financial Position.
2
As at June 30, 2020, $1,745 million was reported within Accounts payable and other and $11 million within Accounts payable to affiliates on the Consolidated Statements of Financial Position.

26


 
December 31, 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


161

161

 
(78
)
83

Commodity contracts


163

163

 
(47
)
116

Other contracts
1


3

4

 

4

 
1


327

328

1 
(125
)
203

Deferred amounts and other assets
 
 
 
 
 
 
 
Foreign exchange contracts
10


71

81

 
(42
)
39

Commodity contracts


17

17

 
(2
)
15

Other contracts
2


1

3

 

3

 
12


89

101

 
(44
)
57

Accounts payable and other
 
 
 
 
 
 
 
Foreign exchange contracts
(5
)
(13
)
(392
)
(410
)
 
78

(332
)
Interest rate contracts
(353
)


(353
)
 

(353
)
Commodity contracts


(173
)
(173
)
 
47

(126
)
 
(358
)
(13
)
(565
)
(936
)
2 
125

(811
)
Other long-term liabilities
 
 
 
 
 
 
 
Foreign exchange contracts


(934
)
(934
)
 
42

(892
)
Interest rate contracts
(181
)


(181
)
 

(181
)
Commodity contracts
(5
)

(60
)
(65
)
 
2

(63
)
 
(186
)

(994
)
(1,180
)
 
44

(1,136
)
Total net derivative assets/(liabilities)
 
 
 
 
 
 
 
Foreign exchange contracts
5

(13
)
(1,094
)
(1,102
)
 

(1,102
)
Interest rate contracts
(534
)


(534
)
 

(534
)
Commodity contracts
(5
)

(53
)
(58
)
 

(58
)
Other contracts
3


4

7

 

7

 
(531
)
(13
)
(1,143
)
(1,687
)
 

(1,687
)
1
As at December 31, 2019, $327 million was reported within Accounts receivable and other and $1 million within Accounts receivable from affiliates on the Consolidated Statements of Financial Position.
2
As at December 31, 2019, $920 million was reported within Accounts payable and other and $16 million within Accounts payable to affiliates on the Consolidated Statements of Financial Position.

27


The following table summarizes the maturity and notional principal or quantity outstanding related to our derivative instruments.
 
 
 
 
 
 
 
 
 
 
June 30, 2020
2020

2021

2022

2023

2024

Thereafter

 
Total

 
Foreign exchange contracts - United States dollar forwards - purchase (millions of United States dollars)
973

500

1,750




 
3,223

 
Foreign exchange contracts - United States dollar forwards - sell (millions of United States dollars)
3,027

5,631

5,703

3,784

1,856


 
20,001

 
Foreign exchange contracts - British pound (GBP) forwards - sell (millions of GBP)
76

27

28

29

30

90

 
280

 
Foreign exchange contracts - Euro forwards - sell (millions of Euro)
23

94

94

92

90

515

 
908

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


72,500




 
72,500

 
Interest rate contracts - short-term pay fixed rate (millions of Canadian dollars)
2,984

4,190

411

49

35

121

 
7,790

 
Interest rate contracts - long-term debt pay fixed rate (millions of Canadian dollars)
3,452

1,595





 
5,047

 
Equity contracts (millions of Canadian dollars)
16

34





 
50

 
Commodity contracts - natural gas (billions of cubic feet)3
45

55

22

17

10

11

 
160

 
Commodity contracts - crude oil (millions of barrels)3
8

9

1




 
18

 
Commodity contracts - power (megawatt per hour) (MW/H)
70

(3
)
(43
)
(43
)
(43
)
(43
)
1 
(18
)
2 
1
As at June 30, 2020, thereafter includes an average net purchase/(sell) of power of (43) MW/H for 2025.
2
Total is an average net purchase/(sell) of power.
3 Total is a net purchase/(sell) of underlying commodity.

Fair Value Derivatives
For foreign exchange 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 Net foreign currency gain/(loss) in the Consolidated Statements of Earnings. Any excluded components are included in the Statements of Comprehensive Income.

 
Three months ended
June 30,
 
Six months ended
June 30,
 
2020

2019

 
2020

2019

(millions of Canadian dollars)
 
 
 
 
 
Unrealized gain/(loss) on derivative
(133
)

 
85


Unrealized gain/(loss) on hedged item
138


 
(65
)

Realized loss on derivative


 
(12
)




28


The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income
 
The following table presents the effect of cash flow hedges, fair value 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,
 
2020

2019

 
2020

2019

(millions of Canadian dollars)
 
 
 
 
 
Amount of unrealized gain/(loss) recognized in OCI
 
 
 
 
 
Cash flow hedges
 
 
 
 
 
Foreign exchange contracts
(13
)
(3
)
 
6

(13
)
Interest rate contracts
(35
)
(285
)
 
(750
)
(581
)
Commodity contracts

(18
)
 
9

(21
)
Other contracts
1

2

 
(6
)
5

Fair value hedges
 
 
 
 
 
Foreign exchange contracts
5


 
8


Net investment hedges
 
 
 
 
 
Foreign exchange contracts
3

1

 
(4
)
2

 
(39
)
(303
)
 
(737
)
(608
)
Amount of (gain)/loss reclassified from AOCI to earnings
 
 
 
 
 
Foreign exchange contracts1
1


 
2

2

Interest rate contracts2
59

40

 
103

72

Other contracts3

6

 

(3
)
 
60

46

 
105

71

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.
3
Reported within Operating and administrative expense in the Consolidated Statements of Earnings.

We estimate that a loss of $170 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 18 months as at June 30, 2020.
 

29


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,
 
2020

2019

 
2020

2019

(millions of Canadian dollars)
 
 
 
 
 
Foreign exchange contracts1
1,246

412

 
(757
)
1,028

Interest rate contracts2
3


 
(15
)
178

Commodity contracts3
(517
)
162

 
(44
)
(99
)
Other contracts4


 
(8
)
5

Total unrealized derivative fair value gain/(loss), net
732

574

 
(824
)
1,112


1
For the respective six months ended periods, reported within Transportation and other services revenues (2020 - $437 million loss; 2019 - $550 million gain) and Net foreign currency gain/(loss) (2020 - $320 million loss; 2019 - $478 million gain) in the Consolidated Statements of Earnings.
2
Reported as an (increase)/decrease within Interest expense in the Consolidated Statements of Earnings.
3
For the respective six months ended periods, reported within Transportation and other services revenues (2020 - $17 million gain; 2019 - $25 million loss), Commodity sales (2020 - $403 million loss; 2019 - $490 million loss), Commodity costs (2020 - $348 million gain; 2019 - $392 million gain) and Operating and administrative expense (2020 - $6 million loss; 2019 - $24 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 ready access to either the Canadian or United States public capital markets, subject to market conditions. 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, 2020. 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.


30


We have credit concentrations and credit exposure, with respect to derivative instruments, in the following counterparty segments:
 
June 30,
2020

December 31,
2019

(millions of Canadian dollars)
 
 
Canadian financial institutions
125

146

United States financial institutions
127

40

European financial institutions
34

3

Asian financial institutions
135

92

Other1
218

113

 
639

394


 
1
Other is comprised of commodity clearing house and physical natural gas and crude oil counterparties.
 
As at June 30, 2020, 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 agreements. We held no cash collateral on derivative asset exposures as at June 30, 2020 and December 31, 2019.
 
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 Enbridge Gas, credit risk is mitigated by the utilities' large and diversified customer base and the ability to recover an estimate for doubtful accounts through the ratemaking process. We actively monitor the financial strength of large industrial customers, and in select cases, have obtained additional security to minimize the risk of default on receivables. Generally, we classify and provide for receivables older than 30 days as past due. The maximum exposure to credit risk related to non-derivative financial assets is their carrying value.
 
FAIR VALUE MEASUREMENTS
Our financial assets and liabilities measured at fair value on a recurring basis include derivative instruments. We also disclose the fair value of other financial instruments not measured at fair value. The fair value of financial instruments reflects our best estimates of market value based on generally accepted valuation techniques or models and is supported by observable market prices and rates. When such values are not available, we use discounted cash flow analysis from applicable yield curves based on observable market inputs to estimate fair value.
 
FAIR VALUE OF FINANCIAL INSTRUMENTS
We categorize our derivative instruments measured at fair value into one of three different levels depending on the observability of the inputs employed in the measurement.

Level 1
Level 1 includes derivatives measured at fair value based on unadjusted quoted prices for identical assets and liabilities in active markets that are accessible at the measurement date. An active market for a derivative is considered to be a market where transactions occur with sufficient frequency and volume to provide pricing information on an ongoing basis. Our Level 1 instruments consist primarily of exchange-traded derivatives used to mitigate the risk of crude oil price fluctuations.
 

31


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, crude, NGL and natural gas contracts, basis swaps, commodity swaps and energy swaps. 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. Depending on the type of derivative and nature of the underlying risk, we use observable market prices (interest, foreign exchange, commodity and share price) 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.


32


We have categorized our derivative assets and liabilities measured at fair value as follows:
June 30, 2020
Level 1

Level 2

Level 3

Total Gross
Derivative
Instruments

(millions of Canadian dollars)
 

 

 

 

Financial assets
 

 

 

 

Current derivative assets
 

 

 

 

Foreign exchange contracts

73


73

Commodity contracts
15

47

215

277

 
15

120

215

350

Long-term derivative assets
 

 

 

 

Foreign exchange contracts

245


245

Commodity contracts
21

27

15

63

 
21

272

15

308

Financial liabilities
 

 

 

 

Current derivative liabilities
 

 

 

 

Foreign exchange contracts

(564
)

(564
)
Interest rate contracts

(847
)

(847
)
Commodity contracts
(29
)
(16
)
(299
)
(344
)
Other contracts

(1
)

(1
)
 
(29
)
(1,428
)
(299
)
(1,756
)
Long-term derivative liabilities
 

 

 

 

Foreign exchange contracts

(1,524
)

(1,524
)
Interest rate contracts

(390
)

(390
)
Commodity contracts
(12
)
(9
)
(59
)
(80
)
Other contracts

(6
)

(6
)
 
(12
)
(1,929
)
(59
)
(2,000
)
Total net financial assets/(liabilities)
 

 

 

 

Foreign exchange contracts

(1,770
)

(1,770
)
Interest rate contracts

(1,237
)

(1,237
)
Commodity contracts
(5
)
49

(128
)
(84
)
Other contracts

(7
)

(7
)
 
(5
)
(2,965
)
(128
)
(3,098
)


33


December 31, 2019
Level 1

Level 2

Level 3

Total Gross
Derivative
Instruments

(millions of Canadian dollars)
 

 

 

 

Financial assets
 

 

 

 

Current derivative assets
 

 

 

 

Foreign exchange contracts

161


161

Commodity contracts

33

130

163

Other contracts

4


4

 

198

130

328

Long-term derivative assets
 

 

 

 

Foreign exchange contracts

81


81

Commodity contracts

12

5

17

Other contracts

3


3

 

96

5

101

Financial liabilities
 

 

 

 

Current derivative liabilities
 

 

 

 

Foreign exchange contracts

(410
)

(410
)
Interest rate contracts

(353
)

(353
)
Commodity contracts
(5
)
(23
)
(145
)
(173
)
 
(5
)
(786
)
(145
)
(936
)
Long-term derivative liabilities
 

 

 

 

Foreign exchange contracts

(934
)

(934
)
Interest rate contracts

(181
)

(181
)
Commodity contracts

(6
)
(59
)
(65
)
 

(1,121
)
(59
)
(1,180
)
Total net financial assets/(liabilities)
 

 

 

 

Foreign exchange contracts

(1,102
)

(1,102
)
Interest rate contracts

(534
)

(534
)
Commodity contracts
(5
)
16

(69
)
(58
)
Other contracts

7


7

 
(5
)
(1,613
)
(69
)
(1,687
)
 
The significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments were as follows:
June 30, 2020
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
(7
)
Forward gas price
1.96

5.24

3.22

$/mmbtu2
Crude
16

Forward crude price
23.00

54.36

41.31

$/barrel
Power
(56
)
Forward power price
21.00

67.14

52.62

$/MW/H
Commodity contracts - physical1
 
 
 
 
 
 
Natural gas
17

Forward gas price
1.43

6.84

2.88

$/mmbtu2
Crude
(99
)
Forward crude price
33.45

74.06

50.63

$/barrel
NGL
1

Forward NGL price
0.19

1.29

0.57

$/gallon
 
(128
)
 
 
 
 
 
1
Financial and physical forward commodity contracts are valued using a market approach valuation technique.
2
One million British thermal units (mmbtu).
 


34


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. Changes in forward commodity prices could result in significantly different fair values for our Level 3 derivatives.

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,
 
2020

2019

(millions of Canadian dollars)
 

 

Level 3 net derivative liability at beginning of period
(69
)
(11
)
Total gain/(loss) unrealized
 

 

Included in earnings1
(107
)
103

Included in OCI
7

(20
)
Settlements
41

(174
)
Level 3 net derivative liability at end of period
(128
)
(102
)
1
Reported within Transportation and other services revenues, Commodity costs and Operating and administrative expense in the Consolidated Statements of Earnings.
 
There were no transfers into or out of Level 3 as at June 30, 2020 or December 31, 2019.
 
FAIR VALUE OF OTHER FINANCIAL INSTRUMENTS
Our other long-term investments in other entities with no actively quoted prices are classified as Fair Value Measurement Alternative (FVMA) investments and are recorded at cost less impairment. The carrying value of FVMA other long-term investments totaled $56 million and $99 million as at June 30, 2020 and December 31, 2019, respectively.
 
We have Restricted long-term investments held in trust totaling $508 million and $434 million as at June 30, 2020 and December 31, 2019, respectively, which are recognized at fair value.
 
We have a held-to-maturity preferred share investment carried at its amortized cost of $566 million and $580 million as at June 30, 2020 and December 31, 2019, 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 is $566 million and $580 million as at June 30, 2020 and December 31, 2019, respectively.
 
As at June 30, 2020 and December 31, 2019, our long-term debt had a carrying value of $67.1 billion and $64.4 billion, respectively, before debt issuance costs and a fair value of $74.0 billion and $70.5 billion, respectively. We also have non-current notes receivable carried at book value and recorded in Deferred amounts and other assets in the Consolidated Statements of Financial Position. As at June 30, 2020 and December 31, 2019, the non-current notes receivable had a carrying value of $1,034 million and $1,026 million, respectively, which also approximates their fair value.

The fair value of financial assets and liabilities other than derivative instruments, 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.
 
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.
 

35


During the six months ended June 30, 2020 and 2019, we recognized an unrealized foreign exchange loss of $371 million and a gain of $250 million, respectively, on the translation of United States dollar denominated debt and unrealized loss of $4 million and a gain of $3 million, respectively, on the change in fair value of our outstanding foreign exchange forward contracts in OCI. During the six months ended June 30, 2020 and 2019, we recognized realized losses of nil, in OCI associated with the settlement of foreign exchange forward contracts and recognized realized losses of nil, in OCI associated with the settlement of United States dollar denominated debt that had matured during the period.

11. INCOME TAXES

The effective income tax rates for the three months ended June 30, 2020 and 2019 were 25.0% and 19.2%, respectively and for the six months ended June 30, 2020 and 2019 were 9.2% and 20.9%, respectively.

The period-over-period change in the effective income tax rates is due to the effect of rate-regulated accounting for income taxes and the benefit of foreign rate differentials being partially offset by higher United States minimum tax relative to the change in earnings period-over-period.

12. PENSION AND OTHER POSTRETIREMENT BENEFITS
 
Three months ended
June 30,
 
Six months ended
June 30,
 
2020

2019

 
2020

2019

(millions of Canadian dollars)
 
 
 
 
 
Service cost
58

51

 
100

102

Interest cost
54

50

 
87

101

Expected return on plan assets
(113
)
(84
)
 
(180
)
(168
)
Amortization of actuarial loss and prior service costs
10

8

 
19

15

Net periodic benefit costs
9

25

 
26

50



For the three and six months ended June 30, 2020, we incurred $236 million in severance costs related to our voluntary workforce reduction program. Severance costs are included in Operating and administrative expense in the Consolidated Statements of Earnings.

13. CONTINGENCIES
 
We and our subsidiaries are involved in various 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.

14. SUBSEQUENT EVENTS

On July 8, 2020, we issued US$1.0 billion of 60-year hybrid subordinated notes payable semi-annually in arrears. The notes mature on July 15, 2080 and are redeemable on year 10 and every five years thereafter. Refer to Note 7. Debt for further discussion of the issuance.


36


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 quarterly report on Form 10-Q and our annual report on Form 10-K for the year ended December 31, 2019.

As of the end of the second quarter of 2019, we have qualified as a foreign private issuer for purposes of the United States Securities Exchange Act of 1934, as amended (Exchange Act). We intend to continue to file annual reports on Form 10-K, quarterly reports on Form 10-Q and current reports on Form 8-K with the U.S. Securities and Exchange Commission instead of filing the reporting forms available to foreign private issuers. We also intend to maintain our Form S-3 registration statements.

RECENT DEVELOPMENTS

COVID-19 PANDEMIC, REDUCED CRUDE OIL DEMAND AND COMMODITY PRICES

The COVID-19 pandemic and the emergency response measures enacted by governments in Canada, the United States and around the world, have caused material disruption to many businesses resulting in a severe slow down in Canadian, United States and global economies, leading to increased volatility in financial markets worldwide and demand reduction for commodities. While various global producers, including the Organization of Petroleum Exporting Countries and other oil producing nations (OPEC+), reached agreements to cut crude oil production in the second quarter of 2020, downward pressure on commodity prices continues and could continue for the foreseeable future, particularly given concerns over crude oil inventories. As a result, prices of crude oil, natural gas, natural gas liquids and other commodities whose prices are highly correlated to crude oil have decreased and remain volatile.

We have taken proactive measures to deliver energy safely and reliably during the COVID-19 pandemic. We activated our crisis management team to focus on a number of priorities, including: (i) the health and safety of our employees and the public; (ii) operational reliability for our customers and markets; (iii) identification of essential personnel and procedures; and (iv) extensive stakeholder communication and outreach including updates to our Board of Directors. We are following recommendations from public health authorities and medical experts and have taken steps to help prevent our employees’ exposure to the spread of COVID-19, including, where practical, work-at-home plans enacted in March 2020 and the implementation of business continuity plans to enable the integrity of our operations and protect the health of our employees in pipeline control functions and service centers, our field representatives and other essential functions.

The safe operation of our facilities has not been impacted. We continue to employ all safety processes and procedures in the normal course. Our business continuity plans are designed to enable us to manage operational developments related to COVID-19 as they unfold. We provide an essential service across North America. Our customers, and the communities where we operate, depend on us to safely and reliably provide the energy they need to heat their homes and fuel their lives.


37


The COVID-19 pandemic has had a deep impact in the communities in which we operate. We are continuing to provide support in our communities by advancing funds to respond and provide relief to those who are most vulnerable. Our teams in our operating regions are working closely with our nonprofit community partners, our closest Indigenous and Tribal neighbors and local governments to identify where resources are needed most.

The COVID-19 pandemic, reduced crude oil demand and reduced commodity prices present potential new or elevated risks to our business. In late March, we began to see impacts both on the supply of, and demand for, crude oil and other liquid hydrocarbons transported on our pipelines. Several shippers on our crude oil pipelines have responded to significantly lower demand caused by the COVID-19 pandemic, declining storage availability and refinery utilization, and commodity price declines by reducing volumes in the second quarter of 2020. Average Mainline System volumes in the second quarter of 2020 were 2,439 thousand barrels per day (kbpd) or approximately 400 kbpd lower than the 2,842 kbpd average for the first quarter of 2020. Over the balance of 2020, we anticipate a continued but gradual recovery in demand as travel and border restrictions are lifted and mobility returns to North America. This view is supported by our expectation that the refineries operating in our core Mainline System markets (i.e. the United States Midwest, Eastern Canada and the United States Gulf Coast) will continue to experience higher utilization rates given their scale, complexity and cost competitiveness. We continue to expect that Mainline System volumes will be under utilized by 200-400 kbpd in the third quarter of 2020 and 100-300 kbpd in the fourth quarter of 2020, and return to full utilization in early 2021. For every 100 kbpd increase or decrease in volumes on our Mainline System, our revenues, net of power savings, are expected to increase or decline by approximately $35 million per quarter.

In our US Midstream business, our equity affiliate DCP Midstream, LP, responded to the drastic decline in commodity prices by decreasing their distributions to us by 50 percent (beginning with the first quarter distribution paid in May 2020), thereby modestly reducing our cash flows. As a further outcome of the drastic commodity price decline, we recorded a $1.7 billion impairment on our equity method investment in DCP Midstream in the first quarter of 2020, based on the decline in the market price of DCP Midstream, LP publicly-traded units as at March 31, 2020. No further impairment was recorded in the second quarter of 2020.

In addition, these circumstances have led to the deterioration of the credit profiles of some of our customers and suppliers. We will continue to monitor this risk and take credit risk mitigating actions.

The situation around the COVID-19 pandemic, reduced crude oil demand and reduced commodity prices is evolving and our assessment of risks is included in Part II, Item 1A. Risk Factors.

While the length and depth of the current energy demand reduction and its impact is challenging to estimate at this time, we have initiated several actions to further strengthen our resiliency and position for the future, while assuring that the safety and reliability of our operations remains our first priority. We have taken actions to reduce operating costs by approximately $300 million in 2020, including reductions to employees and Board of Directors compensation, a voluntary workforce reduction program, as well as supply chain savings. We have also recently executed $0.4 billion of asset sales and increased our available liquidity to over $14 billion. We are experiencing a natural slowing of 2020 capital spending in light of COVID-19 and the health and safety measures put into place by federal and regional governments. In addition, we believe that the following factors further demonstrate the resiliency of our low-risk business model:
Our assets are highly contracted and commercially underpinned by long-term take-or-pay and cost-of-service agreements;
Approximately 95 percent of our revenues in the first half of 2020 were from investment grade customers or non-investment grade customers who have provided credit enhancements;
The acquisition of Spectra Energy in 2017 provided us with greater diversification into natural gas with embedded low risk commercial structures. We currently have approximately 40 different sources of cash flows by geography and by different customer groups;

38


A strong financial position with over $14 billion of net available liquidity which gives us the capacity to fund all of our capital projects and any debt maturities through 2021 without accessing the capital markets; and
We limit the maximum cash flow loss that could arise from direct market price risks through a comprehensive long-term economic hedging program.

We will continue to actively monitor our business environment and may take further actions that we determine are in the best interests of Enbridge, our employees, customers, partners and stakeholders, or as required by federal, state or provincial authorities. At this time, given the many outstanding questions as to the length and depth of the COVID-19 pandemic and the current low commodity price environment, the impact on us is uncertain; however, it is possible that they continue to have an adverse impact on our business and results of operations.

MAINLINE SYSTEM CONTRACTING

On February 24, 2020, the Canada Energy Regulator (CER) issued a Notice of Public Hearing which outlined the process for participation in the hearing and identified a list of issues for discussion in the proceeding. In March 2020, letters were filed with the CER by a group of potential intervenors that requested the CER delay setting hearing dates associated with our Mainline System contract filing. Subsequently, the CER issued a letter requesting comments on the potential delay of proceedings.

We filed our response with the CER on May 1, 2020, and on May 19, 2020, the CER announced that the regulatory process for our proposal to offer contracted transportation service on our Mainline System will proceed in a single phase hearing process that balances the need to address COVID-19 pandemic related challenges and the CER's mandate to adjudicate in an appropriately expeditious manner.

We filed our responses to initial CER information requests in June 2020 and intend to file our responses to a second round of information requests in August 2020.

We expect an oral hearing to occur sometime after April 2021, but a hearing date has not yet been set. If a replacement agreement is not in place by June 30, 2021, the Competitive Tolling Settlement provides for tolls to continue on an interim basis.

GAS TRANSMISSION AND MIDSTREAM RATE PROCEEDINGS

Texas Eastern
On February 25, 2020, Texas Eastern Transmission, LP (Texas Eastern) received approval from the Federal Energy Regulatory Commission (FERC) of its uncontested rate case settlement with customers. In the first quarter of 2020, Texas Eastern recognized revenues from the settled rates retroactive to June 1, 2019, and put the settled rates into effect on April 1, 2020.

Algonquin
In May 2020, Algonquin Gas Transmission, LLC (Algonquin) reached an agreement with customers and filed a Stipulation and Agreement with the FERC. On July 2, 2020, Algonquin received approval from the FERC of its uncontested rate case settlement with customers.

BC Pipeline
In May 2020, Westcoast Energy Inc. filed the 2020-2021 rate settlement agreement with their BC Pipeline shippers with the CER for approval. On July 17, 2020, the rate settlement agreement was approved by the CER and Westcoast Energy Inc. has submitted an application to set the interim rates as final.


39


East Tennessee, Maritimes & Northeast and Alliance Pipeline
We expect to begin customer settlement discussions for East Tennessee Natural Gas and the United States portions of both the Alliance Pipeline and the Maritimes & Northeast Pipeline in the fourth quarter of 2020.

GAS DISTRIBUTION AND STORAGE RATE APPLICATIONS

2020 Rate Application
In October 2019, Enbridge Gas filed an application with the Ontario Energy Board (OEB) for the setting of rates for 2020 and for the funding of discrete incremental capital investments through the incremental capital module (ICM) mechanism. The 2020 rate application was filed in accordance with the parameters of Enbridge Gas’s OEB approved Price Cap Incentive Regulation (IR) rate setting mechanism and represents the second year of a five-year term. In December 2019, Enbridge Gas received a Decision and Order from the OEB for Phase 1 of the application which approved 2020 rates, exclusive of requested ICM amounts, on an interim basis effective January 1, 2020.

On May 14, 2020, the OEB issued a Phase 2 Decision and Order approving Enbridge Gas’s application for ICM funding. Final 2020 rates, inclusive of requested ICM amounts, were approved as part of an OEB Rate Order issued on June 11, 2020.

2021 Rate Application
On June 30, 2020, Enbridge Gas filed Phase 1 of an application with the OEB for the setting of rates for 2021. The 2021 rate application was filed in accordance with the parameters of Enbridge Gas's OEB approved Price Cap IR rate setting mechanism and represents the third year of a five-year term. Phase 1 of the application addresses mechanistic Price Cap IR rate adjustments. An OEB decision on Phase 1 of Enbridge Gas's application is anticipated in the fourth quarter of 2020. Phase 2 of the application, expected to be filed in the fourth quarter of 2020, will address ICM funding requirements.

FINANCING UPDATE

On February 20, 2020, we raised US$750 million of two-year floating rate notes in the United States debt capital markets and on April 1, 2020, Enbridge Gas completed a $1.2 billion dual tranche offering of 10-year and 30-year notes in the Canadian debt capital markets. On May 12, 2020, we raised $1.3 billion with a dual tranche offering of 5-year and 7-year notes in the Canadian debt capital markets. On July 8, 2020, we raised an additional US$1.0 billion of 60-year hybrid subordinated notes in the United States debt capital markets. Through these capital market activities, we completed our 2020 debt funding plan and strengthened our financial position.

In February 2020, we closed three new non-revolving credit facilities totaling US$1.5 billion and on March 31, 2020, we established a new syndicated one-year revolving credit facility in the amount of $1.7 billion. On April 9, 2020, we increased the amount of our new revolving facility by an additional $1.3 billion bringing the total amount to $3.0 billion, significantly enhancing our available liquidity.

In July 2020, we extended approximately $10.0 billion of our 364 day extendible credit facilities to July 2021, inclusive of a one-year term out provision to July 2022.

These financing activities, in combination with the asset monetization activities noted below, will enable us to fund our current portfolio of capital projects without requiring access to the capital markets through 2021 if market access is restricted or pricing is unattractive. Refer to Liquidity and Capital Resources.


40


ASSET MONETIZATION

Ozark Gas Transmission and Ozark Gas Gathering
On April 1, 2020, we closed the sale of our Ozark assets for cash proceeds of approximately $63 million.

Montana-Alberta Tie Line
On May 1, 2020, we closed the sale of our MATL transmission assets for cash proceeds of approximately $189 million.

Éolien Maritime France SAS
On May 1, 2020, we executed agreements to sell 49% of an entity that holds our 50% interest in Éolien Maritime France SAS (EMF) to the Canada Pension Plan Investment Board (CPP Investments) for initial proceeds in excess of $100 million. Post-closing, CPP Investments will fund their 49% share of all ongoing future development capital. Closing of the transaction is subject to customary regulatory approvals and is expected to occur in the fourth quarter of 2020. Refer to Growth Projects - Commercially Secured Projects - Renewable Power Generation and Other Announced Projects Under Development.

FÉCAMP OFFSHORE WIND FARM CONSTRUCTION

On June 2, 2020, we announced the start of construction of the Fécamp Offshore Wind Project as well as the finalization of project financing agreements. Our second offshore wind project in France, this project will be comprised of 71 wind turbines that are expected to generate approximately 500-MW. Refer to Growth Projects - Commercially Secured Projects - Renewable Power Generation.

TEXAS EASTERN PIPELINE RUPTURE

On May 4, 2020, a rupture occurred on Line 10, a 30-inch natural gas pipeline that makes up part of the Texas Eastern natural gas pipeline system in Fleming County, Kentucky. There were no reported injuries or damaged structures as a result of the rupture. Texas Eastern crews isolated all three pipelines in this corridor as part of the initial incident response and investigation. The Line 25 36-inch pipeline has since been returned to service. The National Transportation Safety Board is working with the Pipeline and Hazardous Materials Safety Administration (PHMSA) and Enbridge to investigate the incident. On June 1, 2020, the PHMSA issued an amendment to the Lincoln County Corrective Action Order (CAO) addressing the Fleming County rupture. Texas Eastern is currently performing precautionary integrity assessments in compliance with the CAO and we are focused on restoring the pipeline to full service by the winter heating season. The Texas Eastern natural gas pipeline system extends approximately 1,700 miles from the Gulf Coast region of Texas and Louisiana to Ohio, Pennsylvania, New Jersey and New York.


41


RESULTS OF OPERATIONS
 
 
Three months ended
June 30,
 
Six months ended
June 30,
 
2020

2019

 
2020

2019

(millions of Canadian dollars, except per share amounts)
 

 

 
 

 

Segment earnings/(loss) before interest, income taxes and depreciation and amortization
 
 
 
 
 
Liquids Pipelines
2,340

1,992

 
3,190

4,064

Gas Transmission and Midstream
950

941

 
(104
)
1,961

Gas Distribution and Storage
383

390

 
987

1,052

Renewable Power Generation
163

94

 
283

218

Energy Services
(99
)
221

 
22

227

Eliminations and Other
261

107

 
(705
)
355

Earnings before interest, income taxes and depreciation and amortization
3,998

3,745

 
3,673

7,877

Depreciation and amortization
(949
)
(842
)
 
(1,831
)
(1,682
)
Interest expense
(681
)
(637
)
 
(1,387
)
(1,322
)
Income tax expense
(591
)
(436
)
 
(42
)
(1,020
)
(Earnings)/loss attributable to noncontrolling interests
(36
)
2

 
(5
)
(35
)
Preference share dividends
(94
)
(96
)
 
(190
)
(191
)
Earnings attributable to common shareholders
1,647

1,736

 
218

3,627

Earnings per common share attributable to common shareholders
0.82

0.86

 
0.11

1.80

Diluted earnings per common share attributable to common shareholders
0.82

0.86

 
0.11

1.80


EARNINGS ATTRIBUTABLE TO COMMON SHAREHOLDERS

Three months ended June 30, 2020, compared with the three months ended June 30, 2019

Earnings attributable to common shareholders were positively impacted by $127 million due to certain unusual, infrequent or other non-operating factors, primarily explained by the following:
a non-cash, unrealized derivative fair value gain of $1,186 million ($876 million after-tax) in 2020, compared with a gain of $424 million ($336 million after-tax) in 2019, 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 risks; and
a non-cash, net positive adjustment to crude oil and natural gas inventories in our Energy Services business segment of $340 million ($257 million after-tax) in 2020, compared with a net negative adjustment of $6 million ($5 million after-tax) in 2019.

The positive factors above were partially offset by the following:
a non-cash, unrealized loss of $525 million ($397 million after-tax) in 2020, compared with a gain of $139 million ($103 million after-tax) in 2019, reflecting the revaluation of derivatives used in our Energy Services business segment to manage the profitability of transportation and storage transactions, as well as manage the exposure to movements in commodity prices; and
employee severance, transition and transformation costs of $268 million ($200 million after-tax) in 2020 compared with $21 million ($16 million after-tax) in 2019 primarily related to our voluntary workforce reduction program offered in the second quarter of 2020.


42


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 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 $216 million decrease in earnings attributable to common shareholders is primarily explained by the following significant business factors:
decreased earnings from our Liquids Pipelines segment due to lower volume demand resulting from the COVID-19 pandemic impact on supply and demand for crude oil and related products;
the absence of earnings in 2020 from the federally-regulated portion of our Canadian natural gas gathering and processing businesses which were sold on December 31, 2019;
increased income tax expense primarily due to higher United States minimum tax and timing of recognition of newly enacted Canadian tax legislation that came into effect in the second half of 2019; and
higher depreciation and amortization expense as a result of new assets placed into service throughout 2019 and the first quarter of 2020, primarily the Canadian Line 3 Replacement (L3R) Program.

The negative business factors above were partially offset by the following:
increased earnings from our Gas Transmission and Midstream segment due to settled rates on Texas Eastern resulting from the February 2020 rate settlement;
increased earnings from new Liquids Pipelines, Gas Transmission and Midstream, and Renewable Power Generation assets that were placed into service throughout 2019 and the first quarter of 2020;
increased earnings from our Gas Distribution and Storage segment due to higher distribution charges resulting from increases in rates and customer base; 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 $1.39 in 2020 compared with $1.34 in 2019.

Six months ended June 30, 2020, compared with the six months ended June 30, 2019

Earnings attributable to common shareholders were negatively impacted by $3,221 million due to certain unusual, infrequent or other non-operating factors, primarily explained by the following:
a combined loss of $2,060 million ($1,550 million after-tax) related to our equity method investment in DCP Midstream due to a loss of $1,736 million ($1,306 million after-tax) resulting from an impairment to the carrying value of our investment and a loss of $324 million ($244 million after-tax) resulting from further asset and goodwill impairment losses, refer to Part I. Item 1. Financial Statements - Note 9. Impairment of Equity Investments;
a non-cash, unrealized derivative fair value loss of $770 million ($585 million after-tax) in 2020, compared with a gain of $1,024 million ($750 million after-tax) in 2019, 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 risks;
a non-cash, net negative adjustment to crude oil and natural gas inventories in our Energy Services business segment of $2 million ($2 million after-tax) in 2020, compared with a net positive adjustment of $85 million ($61 million after-tax) in 2019;
a loss of $159 million ($119 million after-tax) in 2020 resulting from the February 2020 Texas Eastern rate settlement that re-established the Excess Accumulated Deferred Income Tax (EDIT) regulated liability that was previously eliminated in December 2018; and

43


employee severance, transition and transformation costs of $279 million ($212 million after-tax) in 2020 compared with $65 million ($62 million after-tax) in 2019 primarily related to our voluntary workforce reduction program offered in the second quarter of 2020.

The negative factors above were partially offset by a non-cash, unrealized loss of $49 million ($37 million after-tax) in 2020, compared with a loss of $122 million ($88 million after-tax) in 2019, reflecting the revaluation of derivatives used in our Energy Services business segment to manage the profitability of transportation and storage transactions, as well as manage the exposure to movements in commodity prices.

After taking into consideration the factors above, the remaining $189 million decrease in earnings attributable to common shareholders is primarily explained by the following significant business factors:
decreased earnings from our Energy Services segment due to the significant compression of location and quality differentials in certain markets and fewer opportunities to achieve profitable transportation margins on facilities where we hold capacity obligations;
decreased earnings from our Gas Distribution and Storage segment due to warmer weather experienced in our franchise areas;
the absence of earnings in 2020 from the federally-regulated portion of our Canadian natural gas gathering and processing businesses which were sold on December 31, 2019;
increased income tax expense primarily due to higher United States minimum tax and timing of recognition of newly enacted Canadian tax legislation that came into effect in the second half of 2019; and
higher depreciation and amortization expense as a result of new assets placed into service throughout 2019 and the first quarter of 2020, primarily the Canadian L3R Program.

The negative business factors above were partially offset by the following:
stronger contributions from our Liquids Pipelines segment due to a higher International Joint Tariff (IJT) Benchmark Toll;
increased earnings from our Gas Transmission and Midstream segment due to settled rates on Texas Eastern, retroactive to June 1, 2019, resulting from the February 2020 rate settlement;
increased earnings from new Liquids Pipelines, Gas Transmission and Midstream, and Renewable Power Generation assets that were placed into service throughout 2019 and the first quarter of 2020; and
the net favorable effect of translating United States dollar EBITDA at a higher Average Exchange Rate of $1.37 in 2020 compared with $1.33 in 2019.

BUSINESS SEGMENTS

LIQUIDS PIPELINES
 
 
Three months ended
June 30,
 
Six months ended
June 30,
 
2020

2019

 
2020

2019

(millions of Canadian dollars)
 

 

 
 

 

Earnings before interest, income taxes and depreciation and amortization
2,340

1,992

 
3,190

4,064


Three months ended June 30, 2020, compared with the three months ended June 30, 2019

EBITDA was positively impacted by $370 million due to certain unusual, infrequent or other non-operating factors, primarily explained by a non-cash, unrealized gain of $616 million in 2020, compared with a gain of $227 million in 2019, 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 risks.


44


After taking into consideration the factor above, the remaining $22 million decrease is primarily explained by the following significant business factors:
lower Mainline System ex-Gretna throughput of 2,439 kbpd in 2020 compared with 2,661 kbpd in 2019 due to lower volume demand resulting from the COVID-19 pandemic impact on supply and demand for crude oil and related products; and
lower throughput on our Bakken Pipeline System, Flanagan South Pipeline and Seaway Crude Pipeline System driven by the significant impact of lower crude oil prices and the COVID-19 pandemic on supply and demand for crude oil and related products.

The negative business factors above were partially offset by the following:
a higher IJT Benchmark Toll on our Mainline System of US$4.21 in 2020 compared with US$4.15 in 2019;
contributions from the Canadian L3R Program that was placed into service on December 1, 2019 with an interim surcharge on Mainline System volumes of US$0.20 per barrel for the IJT Benchmark Toll; and
the net favorable effect of translating United States dollar EBITDA at a higher Average Exchange Rate of $1.39 in 2020 compared with $1.34 in 2019.

Six months ended June 30, 2020, compared with the six months ended June 30, 2019

EBITDA was negatively impacted by $1,042 million due to certain unusual, infrequent or other non-operating factors, primarily explained by a non-cash, unrealized loss of $450 million in 2020, compared with a gain of $570 million in 2019, 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 risks.

After taking into consideration the factor above, the remaining $168 million increase is primarily explained by the following significant business factors:
a higher IJT Benchmark Toll on our Mainline System of US$4.21 in 2020 compared with US$4.15 in 2019;
contributions from the Canadian L3R Program that was placed into service on December 1, 2019 with an interim surcharge on Mainline System volumes of US$0.20 per barrel for the IJT Benchmark Toll; and
the net favorable effect of translating United States dollar EBITDA at a higher Average Exchange Rate of $1.37 in 2020 compared with $1.33 in 2019.

The positive business factors above were partially offset by:
lower Mainline System ex-Gretna throughput of 2,641 kbpd in 2020 compared with 2,689 kbpd in 2019 due to lower volume demand resulting from the COVID-19 pandemic impact on supply and demand for crude oil and related products; and
lower throughput on our Bakken Pipeline System, Flanagan South Pipeline and Seaway Crude Pipeline System driven by the significant impact of lower crude oil prices and the COVID-19 pandemic on supply and demand for crude oil and related products.



45


GAS TRANSMISSION AND MIDSTREAM
 
 
Three months ended
June 30,
 
Six months ended
June 30,
 
2020

2019

 
2020

2019

(millions of Canadian dollars)
 
 
 
 
 
Earnings/(loss) before interest, income taxes and depreciation and amortization
950

941

 
(104
)
1,961


 
 Three months ended June 30, 2020, compared with the three months ended June 30, 2019

EBITDA was negatively impacted by $30 million due to certain unusual, infrequent or other non-operating factors, primarily explained by a non-cash, negative equity earnings adjustment of $22 million in 2020 compared with a positive adjustment of $9 million in 2019 related to changes in the mark-to-market value of derivative financial instruments of our equity method investee, DCP Midstream.

After taking into consideration the factor above, the remaining $39 million increase is primarily explained by the following significant business factors:
higher revenues from settled rates on Texas Eastern resulting from the February 2020 rate settlement;
contributions from the Stratton Ridge project and the second phase of the Atlantic Bridge project that were placed into service in the second and fourth quarters of 2019, respectively; and
the net favorable effect of translating United States dollar EBITDA at a higher Average Exchange Rate of $1.39 in 2020 compared with $1.34 in 2019.

The positive business factors above were partially offset by the following:
the absence of earnings in 2020 from the federally-regulated portion of our Canadian natural gas gathering and processing businesses which were sold on December 31, 2019;
higher operating costs on our US Gas Transmission assets;
narrowed AECO-Chicago basis at our Alliance Pipeline joint venture; and
lower commodity prices impacting fractionation margins at our Aux Sable joint venture.

Six months ended June 30, 2020, compared with the six months ended June 30, 2019

EBITDA was negatively impacted by $2,161 million due to certain unusual, infrequent or other non-operating factors, primarily explained by the following:
a loss of $1,736 million in 2020 resulting from an impairment to the carrying value of our equity method investment in DCP Midstream related to a decline in the market price of DCP Midstream, LP's publicly-traded units;
a loss of $324 million in 2020 resulting from further asset and goodwill impairment losses at our equity method investee, DCP Midstream; and
a loss of $159 million in 2020 resulting from the February 2020 Texas Eastern rate settlement that re-established the Excess Accumulated Deferred Income Tax regulated liability that was previously eliminated in December 2018.

The negative factors above were partially offset by a non-cash, positive equity earnings adjustment of $31 million in 2020 compared with a negative adjustment of $4 million in 2019 related to changes in the mark-to-market value of derivative financial instruments of our equity method investee, DCP Midstream.

After taking into consideration the factors above, the remaining $96 million increase is primarily explained by the following significant business factors:
higher revenues from settled rates on Texas Eastern, retroactive to June 1, 2019, resulting from the February 2020 rate settlement;

46


contributions from the Stratton Ridge project and the second phase of the Atlantic Bridge project that were placed into service in the second and fourth quarters of 2019, respectively; and
the net favorable effect of translating United States dollar EBITDA at a higher Average Exchange Rate of $1.37 in 2020 compared with $1.33 in 2019.

The positive business factors above were partially offset by the following:
the absence of earnings in 2020 from the federally-regulated portion of our Canadian natural gas gathering and processing businesses which were sold on December 31, 2019;
higher operating costs on our US Gas Transmission assets;
narrowed AECO-Chicago basis at our Alliance Pipeline joint venture; and
lower commodity prices impacting fractionation margins at our Aux Sable joint venture.

GAS DISTRIBUTION AND STORAGE
 
Three months ended
June 30,
 
Six months ended
June 30,
 
2020

2019

 
2020

2019

(millions of Canadian dollars)
 
 
 
 
 
Earnings before interest, income taxes and depreciation and amortization
383

390

 
987

1,052

 

Three months ended June 30, 2020, compared with the three months ended June 30, 2019

EBITDA was negatively impacted by $23 million due to certain unusual, infrequent and other non-operating factors, primarily explained by a non-cash, unrealized loss of $15 million in 2020 compared with an unrealized gain of $4 million in 2019 arising from the change in the mark-to-market value of Noverco's derivative financial instruments.

After taking into consideration the factor above, the remaining $16 million increase is primarily explained by the following significant business factors:
colder weather experienced in our franchise service areas in 2020 when compared with 2019; when compared with the normal weather forecast embedded in rates, the colder weather in 2020 positively impacted 2020 EBITDA by approximately $22 million while the colder weather in 2019 positively impacted 2019 EBITDA by approximately $19 million;
higher distribution charges resulting from increases in rates and customer base; and
synergy captures realized from the amalgamation of Enbridge Gas Distribution (EGD) and Union Gas Limited (Union Gas).

The positive business factors above were partially offset by the absence of earnings in 2020 from Enbridge Gas New Brunswick and St. Lawrence Gas Company, Inc. which were sold on October 1, 2019 and November 1, 2019, respectively.

Six months ended June 30, 2020, compared with the six months ended June 30, 2019

EBITDA was positively impacted by $3 million due to certain unusual, infrequent and other non-operating factors, primarily explained by employee severance and transition costs of $15 million in 2020 compared with $39 million in 2019 related to the amalgamation of EGD and Union Gas. This positive factor was partially offset by a non-cash, unrealized loss of $9 million in 2020 compared with an unrealized gain of $8 million in 2019 arising from the change in the mark-to-market value of Noverco's derivative financial instruments.


47


After taking into consideration the factors above, the remaining $68 million decrease is primarily explained by the following significant business factors:
warmer weather experienced in our franchise service areas in 2020 when compared with the colder than normal weather experienced in 2019. When compared with the normal weather forecast embedded in rates, the warmer weather in 2020 negatively impacted 2020 EBITDA by approximately $19 million while the colder weather in 2019 positively impacted 2019 EBITDA by approximately $52 million; and
the absence of earnings in 2020 from Enbridge Gas New Brunswick and St. Lawrence Gas Company, Inc. which were sold on October 1, 2019 and November 1, 2019, respectively.

The negative business factors above were partially offset by the following:
higher distribution charges resulting from increases in rates and customer base; and
synergy captures realized from the amalgamation of EGD and Union Gas.

RENEWABLE POWER GENERATION
 
 
 
Three months ended
June 30,
 
Six months ended
June 30,
 
2020

2019

 
2020

2019

(millions of Canadian dollars)
 

 

 
 

 

Earnings before interest, income taxes and depreciation and amortization
163

94

 
283

218

 
Three months ended June 30, 2020, compared with the three months ended June 30, 2019

EBITDA was positively impacted by $19 million due to certain unusual, infrequent and other non-operating factors, primarily explained by a gain of $4 million on disposal and a $9 million further revision to the fair value of our MATL transmission assets.
 
After taking into consideration the factor above, the remaining $50 million increase is primarily explained by the following significant business factors:
stronger wind resources at United States wind facilities;
reimbursements received at certain Canadian wind facilities resulting from a change in operator; and
contributions from the Hohe See Offshore Wind Project, which reached full operating capacity in October 2019 and the Albatros expansion, which was placed into service in January 2020.

The positive business factors above were partially offset by higher mechanical repair costs at certain United States wind facilities.

Six months ended June 30, 2020, compared with the six months ended June 30, 2019

EBITDA was positively impacted by $20 million due to certain unusual, infrequent and other non-operating factors, primarily explained by a gain of $4 million on disposal and a $9 million further revision to the fair value of our MATL transmission assets.

After taking into consideration the factor above, the remaining $45 million increase is primarily explained by the following significant business factors:
stronger wind resources at United States wind facilities;
reimbursements received at certain Canadian wind facilities resulting from a change in operator; and
contributions from the Hohe See Offshore Wind Project, which reached full operating capacity in October 2019 and the Albatros expansion, which was placed into service in January 2020.


48


The positive business factors above were partially offset by the following:
higher mechanical repair costs at certain United States wind facilities; and
lower wind resources at Canadian wind facilities.

ENERGY SERVICES

 
Three months ended
June 30,
 
Six months ended
June 30,
 
2020

2019

 
2020

2019

(millions of Canadian dollars)
 

 

 
 

 

Earnings/(loss) before interest, income taxes and depreciation and amortization
(99
)
221

 
22

227

 
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, 2020, compared with the three months ended June 30, 2019

EBITDA was negatively impacted by $318 million due to certain unusual, infrequent or other non-operating factors, explained by a non-cash, unrealized loss of $525 million in 2020, compared with a gain of $139 million in 2019, reflecting the revaluation of derivatives used to manage the profitability of transportation and storage transactions, as well as manage the exposure to movements in commodity prices. This negative factor was partially offset by a non-cash, net positive adjustment to crude oil and natural gas inventories of $340 million in 2020 compared with a net negative adjustment of $6 million in 2019.

After taking into consideration the factors above, the remaining $2 million decrease reflects fewer opportunities to achieve profitable transportation margins on facilities which Energy Services holds capacity obligations, partially offset by favorable storage opportunities.

Six months ended June 30, 2020, compared with the six months ended June 30, 2019

EBITDA was negatively impacted by $14 million due to certain unusual, infrequent or other non-operating factors, explained by a non-cash, net negative adjustment to crude oil and natural gas inventories of $2 million in 2020 compared with a net positive adjustment of $85 million in 2019. This negative factor was partially offset by a non-cash, unrealized loss of $49 million in 2020, compared with a loss of $122 million in 2019, reflecting the revaluation of derivatives used to manage the profitability of transportation and storage transactions, as well as manage the exposure to movements in commodity prices.

After taking into consideration the factors above, the remaining $191 million decrease reflects the significant compression of location and quality differentials in certain markets and fewer opportunities to achieve profitable transportation margins on facilities which Energy Services holds capacity obligations, partially offset by favorable storage opportunities. The first quarter of 2019 was exceptionally strong, benefiting from favorable location and quality differentials, which increased opportunities to realize profitable margins.


49


ELIMINATIONS AND OTHER
 
 
Three months ended
June 30,
 
Six months ended
June 30,
 
2020

2019

 
2020

2019

(millions of Canadian dollars)
 
 
 
 
 
Earnings/(loss) before interest, income taxes and depreciation and amortization
261

107

 
(705
)
355

 
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, 2020, compared with the three months ended June 30, 2019

EBITDA was positively impacted by $131 million due to certain unusual, infrequent and other non-operating factors, primarily explained by a non-cash, unrealized gain of $585 million in 2020, compared with a gain of $192 million in 2019, 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.

The positive factor above was partially offset by the following unusual, infrequent or other non-operating factors:
employee severance, transition and transformation costs of $253 million in 2020 compared with $17 million in 2019 primarily related to our voluntary workforce reduction program offered in the second quarter of 2020; and
a non-cash, unrealized intercompany foreign exchange loss of $22 million in 2020.

After taking into consideration the factors above, the remaining $23 million increase is primarily explained by lower operating and administrative costs in 2020 as a result of cost containment actions and the timing of the recovery of certain operating administrative costs allocated to the business segments.

Six months ended June 30, 2020, compared with the six months ended June 30, 2019

EBITDA was negatively impacted by $1,108 million due to certain unusual, infrequent and other non-operating factors, primarily explained by the following:
a non-cash, unrealized loss of $313 million in 2020, compared with a gain of $444 million in 2019, 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 $257 million in 2020 compared with $26 million in 2019 primarily related to our voluntary workforce reduction program offered in the second quarter of 2020;
a loss of $74 million in 2020 from non-cash changes in a corporate guarantee obligation; and
a loss of $43 million in 2020 from the write-down of certain minor investments in emerging energy and other technologies.

After taking into consideration the factors above, the remaining $48 million increase is primarily explained by lower operating and administrative costs in 2020 as a result of cost containment actions and the timing of the recovery of certain operating administrative costs allocated to the business segments.


50


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.
United States Line 3 Replacement Program
100
%
US$2.9 billion
US$1.5 billion
Pre-construction
Under review3
2.
Southern Access Expansion
100
%
US$0.5 billion
US$0.5 billion
Under construction
Under review4
3.
Other - United States
100
%
US$0.1 billion
No significant expenditures to date
Under construction
1H - 2021
GAS TRANSMISSION AND MIDSTREAM
 
 
 
 
4.
T-South Reliability & Expansion Program
100
%
$1.0 billion
$0.5 billion
Under construction
2H - 2021
5.
Spruce Ridge Project5
100
%
$0.5 billion
$0.1 billion
Under construction
2H - 2021
6.
Other - United States6
Various

US$1.0 billion
US$0.4 billion
Various stages
2020 - 2023
GAS DISTRIBUTION AND STORAGE
 
 
 
 
7.
System Modernization - Windsor & Owen Sound
100
%
$0.2 billion
No significant expenditures to date
Under construction
Q4 - 2020
8.
Dawn-Parkway Expansion
100
%
$0.2 billion
No significant expenditures to date
Pre-construction
2021 - 2022
9.
Utility Growth Capital & Storage Enhancements
100
%
$0.3 billion
No significant expenditures to date
Pre-construction
2021 - 2023
RENEWABLE POWER GENERATION
 
 
10.
East-West Tie Line
25
%
$0.2 billion
No significant expenditures to date
Under construction
2H - 2021
11.
Saint-Nazaire France Offshore Wind Project7
25.5
%
$0.9 billion
$0.1 billion
Under construction
2H - 2022
(€0.6 billion)
(€0.1 billion)
12.
Fécamp Offshore Wind Project8
17.9
%
$0.7 billion
No significant expenditures to date
Under construction
2023
(€0.5 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, 2020.
3 Update to in-service date pending receipt of all permits required to complete construction.
4 Estimated in-service date will be adjusted to coincide with the in-service date of the U.S. L3R Program.
5 Expenditures were revised in the second quarter of 2020 due to scope modifications.
6 Includes the US$0.1 billion Sabal Trail Phase II project placed into service on May 1, 2020.
7 Reflects the sale of 49% of an entity that holds our 50% interest in EMF to CPP Investments expected to close in the fourth quarter of 2020. After closing, our equity contribution will be $0.15 billion, with the remainder of the project financed through non-recourse project level debt.
8 Reflects the sale of 49% of an entity that holds our 50% interest in EMF to CPP Investments expected to close in the fourth quarter of 2020. After closing, our equity contribution will be $0.10 billion, with the remainder of the project financed through non-recourse project level debt.

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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.

GAS TRANSMISSION AND MIDSTREAM

Sabal Trail Phase II - an expansion of our existing Sabal Trail pipeline through the addition of two new greenfield compressor stations in Albany, Georgia and Dunnellon, Florida. The expansion received FERC approval in April 2020 and was placed into service on May 1, 2020.

GAS DISTRIBUTION AND STORAGE

Utility Growth Capital & Storage Enhancements - we are proceeding with $0.3 billion of utility growth capital expenditures including regulated rate base system reinforcements and an enhancement of our unregulated storage facilities at Dawn, Ontario.

RENEWABLE POWER GENERATION

Fécamp Offshore Wind Project - an offshore wind project that will be comprised of 71 wind turbines located off the northwest coast of France and is expected to generate approximately 500-MW. Project revenues are underpinned by a 20-year fixed price power purchase agreement.

On May 1, 2020, we executed agreements to sell 49% of an entity that holds our 50% interest in EMF to CPP Investments, inclusive of the Fécamp Offshore Wind Project and the Saint-Nazaire France Offshore Wind Project. Post-closing, CPP Investments will fund their 49% share of all ongoing future development capital. Closing of the transaction is subject to customary regulatory approvals and is expected to occur in the fourth quarter of 2020.

GROWTH PROJECTS - REGULATORY MATTERS

United States Line 3 Replacement Program
On February 3, 2020, and through its subsequent order on May 1, 2020, the Minnesota Public Utilities Commission (MNPUC) deemed the revised final Environmental Impact Statement (EIS) adequate and reinstated the Certificate of Need and Route Permit, allowing for construction of the pipeline to commence following the issuance of required permits. On May 21, 2020, various parties filed petitions for reconsideration with the MNPUC contesting the adequacy of the second revised EIS, and the MNPUC’s restored grant of the Certificate of Need and the Route Permit. On June 1, 2020, Enbridge and various supporting parties filed responses to those filed petitions for reconsideration. On June 25, 2020 the MNPUC denied all petitions for reconsideration reaffirming its prior decisions in all three dockets.

As for environmental permits, the Minnesota Pollution Control Agency (MPCA) released a draft of the revised 401 Water Quality Certificate permit in February 2020. Following a public comment period, the MPCA announced on June 3, 2020 that it will conduct a contested case hearing regarding the 401 Water Quality Certificate permit. After an Administrative Law Judge (ALJ) was assigned to the case, the contested case hearing schedule was established on June 23, 2020. Parties filed direct testimony on July 24, 2020 and must file rebuttal testimony on August 7, 2020. Cross examination before the ALJ will occur between August 24-28, 2020, followed by the ALJ issuing their report on October 16, 2020. The ALJ’s contested case hearing schedule confirms that in order to maintain jurisdiction the MPCA is required by the Clean Water Act to make a final decision regarding the 401 Water Quality Certificate by November 14, 2020.


52


At this time, we cannot determine when all necessary permits to commence construction will be issued. Depending on the final in-service date, there is a risk that the project may exceed our total cost estimate of $9 billion for the combined L3R Program. However, at this time, we do not anticipate any capital cost impacts that would be material to our financial position and outlook.

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:

RENEWABLE POWER GENERATION

Éolien Maritime France SAS - on May 1, 2020, we executed agreements to sell 49% of an entity that holds our 50% interest in EMF to CPP Investments. Post-closing, CPP Investments will fund their 49% share of all ongoing future development capital. Closing of the transaction is subject to customary regulatory approvals and is expected to occur in the fourth quarter of 2020. After the transaction closes, through our investment in EMF, we will own equity interests in three French offshore wind projects, including Saint-Nazaire (25.5%), Fécamp (17.9%) and Courseulles (21.7%). The Saint-Nazaire France Offshore Wind Project reached a positive final investment decision in 2019 and the Fécamp Offshore Wind Project reached a positive final investment decision in June 2020 and are now considered to be commercially secured. The remaining project, Courseulles, is expected to reach a final investment decision by next year.

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

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 include any issuances of additional common equity and was the primary consideration for the suspension of our Dividend Reinvestment and Share Purchase Plan in November 2018.

As discussed within Recent Developments - Financing Update, as a result of the COVID-19 pandemic and the corresponding impact on the capital markets, we have elected to increase our liquidity through additional credit facilities to ensure we will not have to access the capital markets through 2021 to fund our current portfolio of capital projects if market access is restricted or pricing is unattractive.
 

53


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, 2020:
 
Maturity
Dates
Total
Facilities

Draws1

Available

(millions of Canadian dollars)
 
 
 
 
Enbridge Inc.
2021-2024
12,013

5,531

6,482

Enbridge (U.S.) Inc.
2021-2024
7,491

2,531

4,960

Enbridge Pipelines Inc.
20212
3,000

1,985

1,015

Enbridge Gas Inc.
20212
2,000

355

1,645

Total committed credit facilities
 
24,504

10,402

14,102

 
1
Includes facility draws and commercial paper issuances that are back-stopped by credit facility.
2
Maturity date is inclusive of the one-year term out option.

On February 24, 2020, Enbridge Inc. entered into a two year, non-revolving credit facility for US$1 billion with a syndicate of lenders.

On February 25, 2020, Enbridge Inc. entered into two, one year, non-revolving, bilateral credit facilities for a total of US$500 million.

On March 31, 2020, Enbridge Inc. entered into a one year, revolving, syndicated credit facility for $1.7 billion. On April 9, 2020, Enbridge Inc. exercised an accordion provision and increased the facility to $3.0 billion.

On July 23 and 24, 2020, we extended approximately $10.0 billion of our 364 day extendible credit facilities to July 2021, inclusive of a one-year term out provision to July 2022.

In addition to the committed credit facilities noted above, we maintain $795 million of uncommitted demand credit facilities, of which $519 million were unutilized as at June 30, 2020. As at December 31, 2019, we had $916 million of uncommitted credit facilities, of which $476 million were unutilized.

Our net available liquidity of $14,564 million as at June 30, 2020, was inclusive of $462 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, 2020, we were in compliance with all debt covenants and we expect to continue to comply with such covenants.


54


LONG-TERM DEBT ISSUANCES
During the six months ended June 30, 2020, we completed the following long-term debt issuances:
Company
Issue Date
 
 
Principal Amount
(millions of Canadian dollars, unless otherwise stated)
 
 
Enbridge Inc.
 
 
 
February 2020
Floating rate notes
 
US$750

May 2020
3.20% medium-term notes
 
$750
 
May 2020
2.44% medium-term notes
 
$550
Enbridge Gas Inc.
 
 
 
 
April 2020
2.90% medium-term notes
 
$600
 
April 2020
3.65% medium-term notes
 
$600

On July 8, 2020, Enbridge Inc. issued US$1.0 billion of 60-year hybrid subordinated notes payable semi-annually in arrears. For the initial 10 years, the notes carry a fixed interest rate of 5.75%. Subsequently, the interest rate per annum will be reset to equal the 5-year United States Treasury rate plus 5.31% every five years from years 10 to 30 and the 5-year United States Treasury rate plus 6.06% every five years from years 30 to 60. The notes mature on July 15, 2080 and are redeemable on year 10 and every five years thereafter.

LONG-TERM DEBT REPAYMENTS
During the six months ended June 30, 2020, we completed the following long-term debt repayments:
Company
Repayment Date
 
 
Principal Amount
(millions of Canadian dollars, unless otherwise stated)
 
 
Enbridge Inc.
 
 
 
January 2020
Floating rate notes
US$700
 
March 2020
4.53% medium-term notes
$500
 
June 2020
Floating rate notes
 
US$500
Enbridge Pipelines (Southern Lights) L.L.C.
 
 
 
June 2020
3.98% senior notes due 2040
 
US$26
Enbridge Pipelines Inc.
 
 
 
 
April 2020
4.45% medium-term notes
 
$350
Enbridge Southern Lights LP
 
 
 
 
June 2020
4.01% senior notes due 2040
 
$7
Spectra Energy Partners, LP
 
 
 
January 2020
6.09% senior secured notes
 
US$111
 
June 2020
Floating rate notes
 
US$400
Westcoast Energy Inc.
 
 
 
 
January 2020
9.90% debentures
 
$100

Strong internal cash flow, proceeds from non-core asset dispositions, ready access to liquidity from diversified sources and a stable business model have enabled us to manage our credit profile. We actively monitor and manage key financial metrics with the objective of sustaining investment grade credit ratings from the major credit rating agencies and 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 EBITDA.


55


There are no material restrictions on our cash. Total restricted cash of $35 million, as reported on 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.

Excluding current maturities of long-term debt, we had a negative working capital position as at June 30, 2020. 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.

SOURCES AND USES OF CASH
 
 
Six months ended
June 30,
 
2020

2019

(millions of Canadian dollars)
 

 

Operating activities
5,225

4,670

Investing activities
(2,266
)
(3,457
)
Financing activities
(3,124
)
(1,058
)
Effect of translation of foreign denominated cash and cash equivalents and restricted cash
(14
)
(25
)
Increase/(decrease) in cash and cash equivalents and restricted cash
(179
)
130

 
Significant sources and uses of cash for the six months ended June 30, 2020 and June 30, 2019 are summarized below:
 
Operating Activities
 
The increase in cash provided by operating activities was primarily attributable to 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 the impact of certain unusual, infrequent or other non-operating factors as discussed under Results of Operations.

Investing Activities
 
The decrease in cash used in investing activities was primarily attributable to proceeds received from dispositions in the second quarter of 2020 and lower contributions to the Gray Oak Holdings LLC equity investment.
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.
 

56


Financing Activities
 
The increase in cash used in financing activities was primarily attributable to an increase in repayments of long-term debt and a decrease in commercial paper and credit facility draws.
The factors above were partially offset by an increase in issuances of long-term debt and the absence of Westcoast Energy Inc.'s redemption of all of its outstanding Series 7 and Series 8 preference shares in 2020 when compared with the corresponding period in 2019.
Our common share dividend payments increased period-over-period primarily due to the 9.8% increase in our common share dividend rate.

SUMMARIZED FINANCIAL INFORMATION

On January 22, 2019, Enbridge entered into supplemental indentures with its wholly-owned subsidiaries, Spectra Energy Partners, LP (SEP) and EEP (the Partnerships), pursuant to which Enbridge fully and unconditionally guaranteed, on a senior unsecured basis, the payment obligations of the Partnerships with respect to the outstanding series of notes issued under the respective indentures of the Partnerships. Concurrently, the Partnerships entered into a subsidiary guarantee agreement pursuant to which they fully and unconditionally guaranteed, on a senior unsecured basis, the outstanding series of senior notes of Enbridge. The Partnerships have also entered into supplemental indentures with Enbridge pursuant to which the Partnerships have issued full and unconditional guarantees, on a senior unsecured basis, of senior notes issued by Enbridge subsequent to January 22, 2019. As a result of the guarantees, holders of any of the outstanding guaranteed notes of the Partnerships (the Guaranteed Partnership Notes) 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 (the Guaranteed Enbridge 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.

Consenting SEP notes and EEP notes under Guarantee
SEP Notes1
EEP Notes2
4.600% Senior Notes due 2021
4.200% Notes due 2021
4.750% Senior Notes due 2024
5.875% Notes due 2025
3.500% Senior Notes due 2025
5.950% Notes due 2033
3.375% Senior Notes due 2026
6.300% Notes due 2034
5.950% Senior Notes due 2043
7.500% Notes due 2038
4.500% Senior Notes due 2045
5.500% Notes due 2040
 
7.375% Notes due 2045
1
As at June 30, 2020, the aggregate outstanding principal amount of SEP notes was approximately US$3.5 billion.
2
As at June 30, 2020, the aggregate outstanding principal amount of EEP notes was approximately US$3.0 billion.


57


Enbridge Notes under Guarantees
USD Denominated1
CAD Denominated2
Floating Rate Note due 2022
4.850% Senior Notes due 2020
2.900% Senior Notes due 2022
4.260% Senior Notes due 2021
4.000% Senior Notes due 2023
3.160% Senior Notes due 2021
3.500% Senior Notes due 2024
4.850% Senior Notes due 2022
2.500% Senior Notes due 2025
3.190% Senior Notes due 2022
4.250% Senior Notes due 2026
3.190% Senior Notes due 2022
3.700% Senior Notes due 2027
3.940% Senior Notes due 2023
3.125% Senior Notes due 2029
3.940% Senior Notes due 2023
4.500% Senior Notes due 2044
3.950% Senior Notes due 2024
5.500% Senior Notes due 2046
2.440% Senior Notes due 2025
4.000% Senior Notes due 2049
3.200% Senior Notes due 2027
 
3.200% Senior Notes due 2027
 
6.100% Senior Notes due 2028
 
2.990% Senior Notes due 2029
 
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
 
4.240% Senior Notes due 2042
 
4.570% Senior Notes due 2044
 
4.570% Senior Notes due 2044
 
4.870% Senior Notes due 2044
 
4.560% Senior Notes due 2064
1
As at June 30, 2020, the aggregate outstanding principal amount of the Enbridge United States dollar denominated notes was approximately US$7.5 billion.
2
As at June 30, 2020, the aggregate outstanding principal amount of the Enbridge Canadian dollar denominated notes was approximately $8.4 billion.

In accordance with Rule 3-10 of the United States Securities and Exchange Commission's Regulation S-X, which provides an exemption from the reporting requirements of the Exchange Act for fully consolidated 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 summarized financial information with separate columns representing the following:

1.
Enbridge Inc., the Parent Issuer and Guarantor;
2.
SEP, a Subsidiary Issuer and Guarantor, and
3.
EEP, a Subsidiary Issuer and Guarantor.

We have provided summarized financial information for each of the Guarantors in line with the requirements of Rule 13-01, which requires that Guarantors with investment balances in Subsidiary Non-Guarantors be excluded and transactions and amounts with Non-Guarantors and other related parties be presented separately.


58


Summarized Financial Information as at and for the six months ended June 30, 2020
 
Parent Issuer and Guarantor
 
Subsidiary Issuer and Guarantor - SEP
 
Subsidiary Issuer and Guarantor - EEP
 
(millions of Canadian dollars)
 
Operating revenues
 
 
 
Operating loss
(36
)
(1
)
(2
)
Earnings/(loss)
(333
)
(50
)
318
 
Earnings/(loss) attributable to common shareholders
(523
)
(50
)
318
 
 
Parent Issuer and Guarantor
 
Subsidiary Issuer and Guarantor - SEP
 
Subsidiary Issuer and Guarantor - EEP

(millions of Canadian dollars)
 
Accounts receivable from affiliates
780
 
 
5

Short-term loans receivable from affiliates
95
 
 
4,754

Other current assets
281
 
7
 
9

Long-term loans receivable from affiliates
32,192
 
73
 
1,937

Other long-term assets
4,379
 
957
 

Accounts payable to affiliates
796
 
829
 
158

Short-term loans payable to affiliates
1,038
 
2,207
 
2,026

Other current liabilities
3,382
 
477
 
58

Long-term loans payable to affiliates
18,577
 
 
3,269

Other long-term liabilities
31,402
 
4,593
 
3,993

 
Summarized Financial Information as at December 31, 2019
 
Parent Issuer and Guarantor
 
Subsidiary Issuer and Guarantor - SEP
 
Subsidiary Issuer and Guarantor - EEP
 
(millions of Canadian dollars)
 
Accounts receivable from affiliates
729
 
 
12
 
Short-term loans receivable from affiliates
1,691
 
 
3,961
 
Other current assets
438
 
41
 
8
 
Long-term loans receivable from affiliates
47,285
 
73
 
2,387
 
Other long-term assets
3,681
 
933
 
1
 
Accounts payable to affiliates
736
 
367
 
68
 
Short-term loans payable to affiliates
367
 
2,058
 
1,991
 
Other current liabilities
5,204
 
598
 
52
 
Long-term loans payable to affiliates
33,686
 
 
3,112
 
Other long-term liabilities
28,585
 
4,708
 
3,801
 

The Guaranteed Enbridge Notes and the Guaranteed Partnership Notes are structurally subordinated to the indebtedness of the Subsidiary Non-Guarantors in respect of the assets of those Subsidiary Non-Guarantors.


59


Under United States bankruptcy law and comparable provisions of state fraudulent transfer laws, a guarantee can be voided, or claims may be subordinated to all other debts of that guarantor if, among other things, the guarantor, at the time the indebtedness evidenced by its guarantee or, in some states, when payments become due under the guarantee:
received less than reasonably equivalent value or fair consideration for the incurrence of the guarantee and was insolvent or rendered insolvent by reason of such incurrence;
was engaged in a business or transaction for which the guarantor’s remaining assets constituted unreasonably small capital; or
intended to incur, or believed that it would incur, debts beyond its ability to pay those debts as they mature.

The guarantees of the Guaranteed Enbridge Notes contain provisions to limit the maximum amount of liability that the Partnerships could incur without causing the incurrence of obligations under the guarantee to be a fraudulent conveyance or fraudulent transfer under United States federal or state law.

Each of the Partnerships is entitled to a right of contribution from the other Partnership for 50% of all payments, damages and expenses incurred by that Partnership in discharging its obligations under the guarantees for the Guaranteed Enbridge Notes.

Under the terms of the guarantee agreement and applicable supplemental indentures, the guarantees of either of the Partnerships of any Guaranteed Enbridge Notes will be unconditionally released and discharged automatically upon the occurrence of any of the following events:
any direct or indirect sale, exchange or transfer, whether by way of merger, sale or transfer of equity interests or otherwise, to any person that is not an affiliate of Enbridge, of any of Enbridge’s direct or indirect limited partnership of other equity interests in that Partnership as a result of which the Partnership ceases to be a consolidated subsidiary of Enbridge;
the merger of that Partnership into Enbridge or the other Partnership or the liquidation and dissolution of that Partnership;
the repayment in full or discharge or defeasance of those Guaranteed Enbridge Notes, as contemplated by the applicable indenture or guarantee agreement;
with respect to EEP, the repayment in full or discharge or defeasance of each of the consenting EEP notes listed above;
with respect to SEP, the repayment in full or discharge or defeasance of each of the consenting SEP notes listed above; or
with respect to any series of Guaranteed Enbridge Notes, with the consent of holders of at least a majority of the outstanding principal amount of that series of Guaranteed Enbridge Notes.

The guarantee obligations of Enbridge of the Guaranteed Partnership Notes will terminate with respect to any series of Guaranteed Partnership Notes if that series is discharged or defeased.

LEGAL AND OTHER UPDATES

LIQUIDS PIPELINES
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. The Oglala Sioux and Yankton Sioux Tribes also filed claims in the case to challenge the Army Corps permit and environmental review process.


60


In August 2018, the Army Corps completed the environmental analysis required on remand by the June 2017 order of the United States Court for the District of Columbia and reaffirmed the issuance of the permit for the Dakota Access Pipeline. All four plaintiff Tribes subsequently amended their complaints to include claims challenging the adequacy of the Army Corps’ August 2018 decision, and the parties filed cross-motions for summary judgment on the merits of the plaintiffs’ amended claims. Briefing on the parties’ cross-motions for summary judgment was completed on November 25, 2019. On March 25, 2020, the Court issued an opinion, granting and denying in part the parties’ cross-motions for summary judgment. The Court ordered the Army Corps to prepare an Environmental Impact Statement to address unresolved controversy pertaining to potential spill impacts resulting from the Dakota Access Pipeline.

On July 6, 2020, the Court issued an order vacating the Army Corps’ easement for the Dakota Access Pipeline and requiring that the pipeline be shut down by August 5, 2020. Dakota Access, LLC and the Army Corps appealed the decision and filed a motion for a stay pending appeal with the Court of Appeals. On July 14, 2020, the Court of Appeals granted a temporary administrative stay to allow the Court time to consider briefing on whether to continue the stay until the appeal is decided on the merits.

Line 5 Dual Pipelines - Tunnel Project
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 (the State) related to the construction of the Line 5 Dual Pipelines Tunnel Project (Tunnel Project). On October 31, 2019, the Court determined that Michigan law PA 359 is valid and is not unconstitutional. On November 5, 2019, the Michigan Attorney General filed an appeal with the Michigan Court of Appeals and briefing for that appeal is now complete. On June 11, 2020, the Michigan Court of Appeals upheld the Court's determination that Michigan law PA 359 is valid and is not unconstitutional. The State did not file for leave to appeal to the Supreme Court of Michigan within the requisite time period so this lawsuit has concluded.

On June 27, 2019, the Michigan Attorney General filed a complaint in the Michigan Ingham County Circuit Court that requests the Court to declare the easement that we have for the operation of the dual pipelines in the Straits of Mackinac (the Straits) to be invalid and to prohibit 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”. On September 16, 2019, we filed our motion for summary disposition and requested dismissal of the State’s Complaint in its entirety. On that same date, the State filed a motion for partial summary disposition and judgment in its favor on its claim that the easement was void from inception. The case was argued on May 22, 2020 and supplemental briefing on the issue of federal preemption was completed on July 6, 2020.

On March 6, 2020, the Mackinac Straits Corridor Authority (Corridor Authority) met. At the meeting, the Corridor Authority reviewed the actions that we have taken in accordance with the Tunnel Project agreement, and on formal motions approved those actions.

During the first quarter of 2020, we filed all major environmental permits, including the joint permit application with the Michigan Department of Environment, Great Lakes and Energy and the Army Corps. In addition, we filed an independent application to the Michigan Public Service Commission and they have scheduled a public hearing date for August 24, 2020.

Upon receipt of all required permits we expect to begin construction of the Tunnel Project. Construction and commissioning of the Tunnel Project is expected to be completed in late 2024.


61


Line 5 Dual Pipelines - East Segment
On June 18, 2020, during seasonal maintenance work on Line 5, we discovered that a screw anchor support had shifted from its original position. We immediately shut down the pipeline and notified the State and our federal regulator, the PHMSA. The issue with the screw anchor was isolated to the east segment of Line 5 and an inspection of the west segment of Line 5 confirmed there were no issues or damage to the anchor structures or pipeline on that segment. Normal operations of the west segment of Line 5 resumed on June 20, 2020, and investigation of the east segment of Line 5 is ongoing.

On June 22, 2020, the Michigan Attorney General, on behalf of the State, filed a motion for a Temporary Restraining Order in the Michigan Ingham County Circuit Court to cease the continued operation of the west segment of Line 5 and to ensure operation of the east segment of Line 5 was not resumed. Further, the Temporary Restraining Order was to compel "legally required information" to be shared with the State for determination that the operation of Line 5 through the Straits is safe. On June 25, 2020, an Order was issued prohibiting the operation of Line 5 pending a hearing on the State’s motion for Preliminary Injunction on June 30, 2020. On July 1, 2020, following the hearing, the Temporary Restraining Order was amended allowing the west segment of Line 5 to restart for the purposes of conducting an in-line inspection, which reconfirmed that the line is safe to operate as there was no damage to the pipeline. The east segment of Line 5 remains shut down as we work with the PHMSA to ensure all safety assessments are complete and data provided prior to restarting the east segment of Line 5.

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 $3.0 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 Part I. Item 1. Financial Statements - Note 2. Changes in Accounting Policies.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Our exposure to market risk is described in Part II. Item 7A. Quantitative and Qualitative Disclosures About Market Risk of our Annual Report on Form 10-K for the year ended December 31, 2019. Other than as set out below, there have been no material modifications to those quantitative and qualitative disclosures about market risk.

COVID-19 PANDEMIC RISK
The spread of the COVID-19 pandemic has caused significant volatility in Canada, the United States and international markets. While we have taken proactive measures to deliver energy safely and reliably during this pandemic, given the ongoing dynamic nature of the circumstances surrounding COVID-19, the impact of this pandemic on our business remains uncertain.


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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 Exchange Act is recorded, processed, summarized and reported within the time periods specified by the U.S. Securities and Exchange Commission'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, 2020, 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 U.S. Securities and Exchange Commission 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, 2020 and found no change that has materially affected, or is reasonably likely to materially affect, internal control over financial reporting.



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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, 2019 and our Quarterly Report on Form 10-Q for the quarter ended March 31, 2020, which could materially affect our financial condition or future results. Other than as set out below, there have been no material modifications to those risk factors.

The COVID-19 pandemic has adversely affected local and global economies and could negatively impact our business, financial position, results of operations and cash flows.

The World Health Organization declared COVID-19 to be a pandemic on March 11, 2020. In response to the rapid global spread of COVID-19, governments have enacted emergency measures to combat the spread of the virus. These measures include restrictions on business activity and travel, as well as requirements to isolate or quarantine, which could continue or expand. Certain of our operations and projects have been deemed essential services in critical infrastructure sectors and are currently exempt from certain business activity restrictions; however, there is no guarantee that this exemption will continue. These actions have interrupted business activities and supply chains; disrupted travel; contributed to significant volatility in the financial and commodity markets, resulting in a general decline in equity prices and lower interest rates; impacted social conditions; and adversely impacted national and international economic conditions, including commodity prices and demand for energy, as well as the labor market.

Given the ongoing and dynamic nature of the circumstances surrounding the COVID-19 pandemic, it is difficult to predict how significant the impact of this pandemic, including any responses to it, will be on North American or global economies or our business, or for how long disruptions are likely to continue. The extent of such impact will depend on future developments and factors outside of our control, which are highly uncertain, rapidly evolving and cannot be predicted, including new information which may emerge concerning the severity or duration of this pandemic and actions taken by governments and others to contain the COVID-19 pandemic or its impact. Such developments, which could have a material adverse effect on our customers, suppliers, regulators, business, financial position, results of operations and cash flows, include disruptions that, among other things:
adversely impacted market fundamentals, such as commodity prices and supply and demand for energy, decreasing volumes transported on our systems, increasing our exposure to asset utilization risks and adversely affecting our results;
adversely impacted our Liquids Pipelines growth rate and results; however, the full extent of such adverse impact is still uncertain;
could prevent one or more of our secured capital projects from proceeding, delay its completion or increase its anticipated cost;
adversely impacted the operations or financial position of our third-party suppliers, service providers or customers and increase our exposure to contract-related risks or customer credit risk;

64


adversely impacted the global capital markets, which could adversely impact our ability to access capital markets at effective rates, the ratings assigned to our securities or our credit facilities;
increased our risks associated with emergency measures taken (including remote working, distancing and additional personal protective equipment), including increased cyber security risks, increased costs and the potential for reduced availability or productivity of our employees or third-party contractors or service providers;
adversely impacted our ability to accurately forecast assumptions used to evaluate expansion projects, acquisitions and divestitures on an ongoing basis or for our financial guidance;
adversely impacted the carrying value of our equity method investment in DCP Midstream and could adversely impact the outcome of future asset impairment tests, indicating that the carrying value of such assets might be impaired;
could adversely impact the execution of current and future trade policies between Canada and the United States; and
could result in future business interruption losses that our insurance coverage may not be sufficient to cover.

There can be no assurance that our strategies to address potential disruptions will mitigate these risks or the adverse impacts to our business, financial position, results of operations and cash flows. Future adverse impacts to our business, financial position, results of operations and cash flows may materialize that are not yet known. In addition, disruptions related to the COVID-19 pandemic may also have the effect of heightening many of the other risks described in Part I. Item 1A. Risk Factors included in our Annual Report on Form 10-K. The risk that is most significantly heightened by the COVID-19 pandemic is the impact of commodity price weakness and volatility on our Liquids Pipelines, Gas Transmission and Midstream and Energy Services businesses, as detailed in the risk factor below. Even after the COVID-19 pandemic has subsided, we may continue to experience adverse impacts to our business as a result of its global impact, including any related recession, as well as lingering impacts on supply of, demand for and prices of crude oil, natural gas, natural gas liquids, liquefied natural gas and renewable energy.

Weakness and volatility in commodity prices increase utilization risks in respect to our assets and may have an adverse effect on our results of operations.

The COVID-19 pandemic and concerns about global economic growth have caused considerable uncertainty in the market for crude oil, natural gas and other commodities, lowering demand forecasts. This, and the changing relationship dynamic among OPEC+ members, has put severe downward pressure on prices. The economic climate in Canada, the United States and abroad has deteriorated and worldwide demand for petroleum products has diminished. 2020 has seen a dramatic decline in the price of crude oil, natural gas and NGL and other commodities whose prices are highly correlated to crude oil. The West Texas Intermediate benchmark prices for crude oil had been trading around US$60 per barrel in December 2019 and fell to as low as US$14 per barrel in March 2020 and into negative values in April 2020. Crude oil prices have started to recover in the second quarter of 2020, with West Texas Intermediate benchmark prices reaching US$40 primarily due to the announcement of crude oil productions cuts in April 2020 and June 2020. Crude oil prices may again decline or may be halted in their recovery.

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In respect to our Liquids Pipeline assets, we are exposed to throughput risk under the Competitive Tolling Settlement on the Canadian Mainline and under certain tolling agreements applicable to other Liquids Pipelines assets, such as the Lakehead System. A decrease in volumes transported can directly and adversely affect our revenues and earnings. The current commodity price environment has impacted both the supply of and demand for crude oil and other liquid hydrocarbons transported on our pipelines. Several shippers on our pipelines have responded to commodity price declines and significantly lower demand caused by COVID-19 by canceling delivery of previously nominated batches in the second quarter of 2020. This has led to a reduction in Mainline System throughputs of approximately 400 kbpd for the second quarter of 2020 compared to first quarter 2020 average Mainline System throughputs of 2,842 kbpd, which were aligned with or stronger than our expectations. At this time, it is difficult to predict the quantum of the impact on Mainline System throughput for the remainder of 2020 due to the unpredictability of the market currently as well as the projected duration of demand impacts caused by COVID-19. We continue to expect that Mainline System volumes will be under utilized by 200-400 kbpd in the third quarter of 2020 and 100-300 kbpd in the fourth quarter of 2020, and return to full utilization in early 2021. For every 100 kbpd increase or decrease in volumes on our Mainline System, our revenues, net of power savings, are expected to increase or decline by approximately $35 million per quarter.
 
While reduced demand has impacted throughput and revenue on the Mainline System, the financial impact of reduced throughput on our upstream regional pipelines and our downstream market extension pipelines is largely mitigated by the presence of take-or-pay contracts. The financial impact is also mitigated through cost-of-service arrangements with credit-worthy counterparties or parties that are not investment grade but have instead provided credit support in the form of letters of credit or other instruments. The existing market circumstances will stress the creditworthiness of many of these counterparties and we continue to evaluate the situation on an ongoing basis. To date, we have not had any counterparty default on its obligations to maintain credit support or pay its tolls under these contracts and at this time, we do not foresee a material impact to our financial results.

Shippers have also reduced investment in exploration and development programs for 2020. The decline in oil prices is also causing some sponsors of oil sands development programs to reconsider the timing of previously announced upstream development projects. Cancellation or deferral of these projects would affect longer-term supply growth from the Western Canadian Sedimentary Basin (WCSB).

With respect to our Gas Transmission and Midstream assets, the low commodity prices have had limited impact on demand for natural gas shipped within our long-haul Gas Transmission assets in the United States and Canada. These assets are comprised of primarily cost-of-service and take-or-pay contract arrangements which are not directly impacted by fluctuations in commodity prices.

Within our US Midstream assets, our investment in DCP Midstream and to a lesser extent the Aux Sable liquids product plant are engaged in the businesses of gathering, treating and processing natural gas and natural gas liquids. Given the drastic decline in commodity prices, DCP Midstream made the decision to decrease its distribution to us by 50 percent (beginning with the first quarter distribution paid in May 2020), thereby reducing our cash flows. Aux Sable results will also be negatively impacted by these lower commodity prices.

With respect to our Energy Services business, we generate margins by capitalizing on quality, time and location differentials when opportunities arise. The recent volatility in commodity prices could limit margin opportunities and impede our ability to cover capacity commitments.

At this point, given the many outstanding questions as to the length and depth of the current low commodity price environment, the impact on us is uncertain; however, it is possible that it may have an adverse impact on our business and our results of operations.


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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.

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
4.1
 
10.1*
 
31.1*
 
31.2*
 
32.1*
 
32.2*
 
101.INS*
 
XBRL Instance Document.
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.
104
 
Cover Page Interactive Data File - the cover page XBRL tags are embedded within the Inline XBRL document (included in Exhibit 101)


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SIGNATURES
 
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
 
 
 
 
ENBRIDGE INC.
 
 
(Registrant)
 
 
 
Date:
July 29, 2020
By:   
/s/ Al Monaco
 
 
Al Monaco
President and Chief Executive Officer
 
 
 
 
Date:
July 29, 2020
By:   
/s/ Colin K. Gruending
 
 
 
Colin K. Gruending
Executive Vice President and Chief Financial Officer
(Principal Financial Officer)

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Exhibit 10.1



ENBRIDGE INC.
DIRECTORS’ COMPENSATION PLAN
February 11, 2020
Amended, Effective June 1, 2020





Effective January 1, 2020, and amendment effective June 1, 2020








ENBRIDGE INC.
DIRECTORS’ COMPENSATION PLAN
1.
DEFINED TERMS
As used herein, the following terms shall have the following meanings, respectively:
“Beneficiary” means any person(s) designated by a Director as indicated on the Designation of Beneficiary Form, to receive any cash amount or Shares under this Plan in the event of the Director’s death;
“Board” means the Board of Directors of the Corporation;
“Bonus Retainer” means a direct grant of DSUs to a Director in addition to such Director’s regular retainer.
“Canadian Election Form” means the election form required to be submitted by the Canadian Taxpayers to the Corporation;
“Canadian Taxpayer” means a Director whose income is subject to Canadian federal income taxation;
“Code” means the U.S. Internal Revenue Code of 1986, as amended;
“Comparator Group” has the meaning set forth in Section 4;
“Compensation” has the meaning set forth in Section 7;
“Corporation” means Enbridge Inc., and includes any successor corporation thereto;
“Deferred Stock Unit Account” has the meaning set forth in Subsection 9(a);
“Deferred Stock Units” or “DSUs” mean units credited to a Director in accordance with Subsection 9(b);
“Designation of Beneficiary Form” means the form attached hereto as Appendix “B”;
“Director” means a director of the Corporation;
“DRS” means the Direct Registration System;
“Dual-Taxed Member” means a Director that is both a U.S. Taxpayer and a Canadian Taxpayer;
“Estate” means the estate of a deceased Director;
“Governance Committee” means the Governance Committee of the Board;

2


“Market Value”, as of a particular day, means the weighted average of the trading price for one (1) Share on The Toronto Stock Exchange for the five (5) Trading Days immediately preceding that day;
“Payment Date” means the date on which Directors would normally receive payments of Compensation;
“Plan” means this Directors’ Compensation Plan effective January 1, 2018, as the same may be amended or varied from time to time;
“Retirement Date”, in respect of a Director, means the effective date on which the Director ceases to be a Director, for any reason whatsoever;
“Share” means a common share of the Corporation;
“Trading Day” means any day, other than a Saturday or Sunday, on which The Toronto Stock Exchange is open for trading;
“Trustee” means the trustee engaged by the Corporation for purposes of facilitating the payment of Share-based Compensation in accordance with Section 8.
“U.S. Election Form” means the election form required to be submitted by U.S. Taxpayers to the Corporation; and
“U.S. Taxpayer” means a Director whose income is subject to U.S. federal income taxation.
2.
PURPOSE AND OBJECTIVES
(a)
The purpose of this Plan is to provide a compensation system for Directors. This Plan applies only to the members of the Board and does not apply to board members of affiliate organizations or employees of the Corporation or any of its subsidiaries.
(b)
The objectives of this Plan are:
(i)
to compensate Directors commensurate with the risks, responsibilities and time commitments assumed by Board members;
(ii)
to attract and retain the services of the most qualified individuals to serve on the Board;
(iii)
to align the interests of Directors with the Corporation’s shareholders;
(iv)
to provide competitive levels of compensation by considering various pay components typically provided to directors; and
(v)
to deliver such compensation in a tax effective manner.
(c)
The Board provides oversight and stewardship over this Plan through the Governance Committee and has overall responsibility for determining the philosophical framework of the Directors’ compensation program.

3


3.
ADMINISTRATION
The Governance Committee will administer this Plan in its discretion. The Governance Committee shall have the power to interpret the provisions of this Plan and to make regulations and formulate administrative provisions for its implementation, and to make such changes in the regulations and administrative provisions as, from time to time, the Governance Committee deems proper and in the best interests of the Corporation. Such regulations and provisions may include the delegation to any Director(s) or any officer(s) of the Corporation of such administrative duties and powers of the Governance Committee as it may see fit.
4.
EXTERNAL BENCHMARKING
(a)
The Board supports maintaining a level of compensation for Directors that is competitive with compensation levels paid to directors of comparable public corporations; reflects the risks accompanying Board membership and the time commitments and responsibilities required of Directors, committee members and Board or Committee Chairs; and reflects the size and complexity of the Corporation’s business.
(b)
The Governance Committee will, from time to time, with the assistance of qualified external experts in the area of compensation benchmarking, review and determine the appropriate comparable public corporations against which comparisons are made (the “Comparator Group”) with the intention that such Comparator Group be consistent with the periodic evaluation of executive management compensation.
(c)
To the extent possible and appropriate, the Governance Committee shall align the Comparator Group with the group used to benchmark executive management compensation practices as approved by the Human Resources & Compensation Committee (refer to Enbridge Inc. senior management compensation policy Compensation Comparators).
5.
COMMUNICATION
The Board recognizes that Compensation is an important component of corporate governance and is committed to ensuring that the material terms of the compensation program are properly disclosed to shareholders and regulators.
6.
APPLICATION
This Plan applies to each individual while serving as a Director and, subject to Subsections 10(c), (d), (e), (f) and 11(a) (ii) and (iii), (c), (d) and (e), shall cease to apply on the Director’s Retirement Date.

4


7.
DIRECTORS’ COMPENSATION
(a)
General
The Board, on the recommendation of the Governance Committee, shall determine from time to time the amount of compensation to be paid to Directors (the “Compensation”) including, without limitation, amounts in respect of retainers (including the retainer for the Chair of the Corporation and Chairs of committees of the Board), Board meeting and committee meeting attendance fees, and any other amounts which the Board in its discretion considers to be appropriate. In addition, the Board shall determine the amount of expenses, if any, for which the Directors will be reimbursed.
(a)
Fee Structure and Payment Particulars
(i)
Compensation will be made on the basis of a flat fee structure that incorporates all Board, committee, and Chair retainers as determined by the Board. The Board’s policy is to target flat fee levels at the 50th percentile of total compensation levels paid to directors of the Comparator Group (as defined in Section 4).
(ii)
As of January 1, 2020, Compensation shall be as set out in Appendix “A”. Changes to Appendix “A” may be made by the Board following a recommendation of or consultation with the Governance Committee. Upon any such change being approved by the Board, a new Appendix “A” incorporating the changes and effective as of the date established by the Board shall be attached to the Plan and become Appendix “A” for all purposes of the Plan.
(iii)
Compensation is paid quarterly, in arrears. All Directors, regardless of country of residency, shall be paid in US dollars.
(iv)
A percentage of the Compensation may be withheld in cases where a Director’s attendance at Board meetings or Committee meetings or both, falls below the established minimum. The Governance Committee will review the continuation of the Director on the Board if an inordinate number of meetings are missed.
(v)
At any time, the Board, on the recommendation of the Governance Committee, may grant to Directors a Bonus Retainer in the form of a direct grant of DSUs. For U.S. Taxpayers only, DSUs comprising a Bonus Retainer shall be payable on December 31 of the year following the year of the Director’s Retirement Date and no U.S. Taxpayer shall be permitted to elect the form or timing of payment of any portion of a Bonus Retainer.

5


(b)
Forms of Payment
The Board, on the recommendation of the Governance Committee, shall determine the portion(s), if any, of the Compensation that a Director may elect to receive by way of cash, Shares or Deferred Stock Units. Until revised by the Board, each Director and Chair of the Board will, subject to requirements of minimum share ownership criteria, as set out in Appendix “A”, elect to receive Compensation as cash, Shares or Deferred Stock Units, in whole or in part, in increments of 5% (totalling 100% of the Compensation payable to such Director).
8.
COMPENSATION - SHARES
(a)
In respect of any amount of Compensation payable to a Director in Shares, funds sufficient for the purchase in the open market of such Shares shall be paid to the Trustee by the Corporation in trust for such Director from time to time, and shall be applied by the Trustee to the purchase of Shares, in the open market on a stock exchange, for that Director.
(b)
The Shares to which a Director becomes entitled hereunder shall be calculated on the basis of the Market Value thereof two (2) weeks prior to the Payment Date.
(c)
The Trustee shall cause such Shares to be registered in the name of the Director and held in electronic book-entry form through the DRS.
(d)
The Trustee shall cause the transfer agent to provide (i) a Direct Registration (DRS) Advice to each Director promptly after each purchase of Shares on such Director’s behalf, which will set out the number of Shares so purchased and the aggregate number of Shares held by such Director in the DRS, and (ii) a Direct Registration (DRS) Statement to each such Director annually. In addition, the Trustee shall promptly provide any other information required by the Director for tax reporting purposes.
9.
COMPENSATION - DEFERRED STOCK UNITS
(a)
Deferred Stock Unit Account
An account, to be known as a “Deferred Stock Unit Account”, shall be maintained by the Corporation for each Director and will show the number of Deferred Stock Units credited to a Director, to four (4) decimal places, from time to time.
(b)
Crediting Deferred Stock Unit Account
In respect of any amount of Compensation payable to a Director in Deferred Stock Units, the number of Deferred Stock Units to be credited to that Director will be calculated by dividing the dollar amount of the quarterly Compensation payable to that Director in Deferred Stock Units on the Payment Date by the Market Value two (2) weeks prior to such date.

6


(c)
Additional Deferred Stock Units From Dividends On Shares
In addition to Subsection 9(b), whenever any cash dividend or other cash distribution is paid on the Shares, additional Deferred Stock Units will be credited to the Director’s Deferred Stock Unit Account. The number of such additional Deferred Stock Units will be calculated by dividing the aggregate dividends that would have been paid to such Director if the Deferred Stock Units in the Director’s Deferred Stock Unit Account had been Shares, by the Market Value of a Share on the date on which the dividends are paid on the Shares, less the amount of any discount then in effect for the reinvestment of dividends under the Corporation’s Dividend Reinvestment and Share Purchase Plan.
10.
CANADIAN TAXPAYER - DEFERRED STOCK UNITS
This Section 10 only applies to Canadian Taxpayers:
(a)
Choice of Compensation Mix
(i)
The Directors shall elect on or before December 31 of the preceding year in which Compensation will be earned, the portion of such Compensation, excluding any Bonus Retainer, to be received by the Director in cash, Shares or Deferred Stock Units in respect of that calendar year, and, failing such election, the Director shall, subject to any minimum amounts of cash, Shares or Deferred Stock Units as set out in Appendix “A”, be deemed to have elected 100% in cash.
(ii)
Where a Director joins the Board after January 1 in any year, such Director shall make his or her compensation mix election within thirty (30) days of his or her election or appointment to the Board.
(iii)
In all cases, the Directors’ elections shall be irrevocable and shall remain in force from the date of such election until the date of the next election.
(b)
Canadian Election Form
Each Director shall fill out a Canadian Election Form indicating their elected compensation mix and deliver such Canadian Election Form to the Corporation on the dates set out above.
(c)
Elected Payment Date – Canadian Taxpayer
Except as provided in Subsection 10(e), the determined value of the Deferred Stock Units credited to the Deferred Stock Unit Account of a Director whose income is subject to Canadian income tax, net of required withholdings, shall be paid to that Director on a date to be agreed upon by that Director and the Corporation, provided that the payment date must be a date subsequent to the Retirement Date and may be no later than December 31 of the first calendar year commencing after that Retirement Date.

7


(d)
No Election Default
If no such payment date agreement is reached, pursuant to Subsection 10(c), the payment date will be December 31 of the first calendar year commencing after that Director’s Retirement Date.
(e)
Payment on Death of a Canadian Taxpayer
(i)
When a Director dies, the value of the Deferred Stock Units credited to that Director’s Deferred Stock Unit Account, net of applicable withholdings, shall be paid to his or her Beneficiary as soon as practicable after the Director’s death, provided that the payment shall be made no later than December 31 of the first calendar year commencing after that Director’s Retirement Date.
(ii)
Notwithstanding the above, if the Beneficiary of the deceased Director has not been determined within sixty (60) days after the Director’s death, the Corporation shall make such payment to the Estate.
(f)
Determining Value for Canadian Taxpayers
To determine the value of Deferred Stock Units for the purposes of a payment to a Director (or, where the Director has died, his or her Beneficiary or Estate, as the case may be) under Subsections 10(c), (d) or (e), a Deferred Stock Unit will be valued equal to the Market Value multiplied by the number of Deferred Stock Units (including fractional Units) credited to a Director’s Deferred Stock Unit Account on the following basis:
(i)
for Subsections 10 (c) and (d), the Market Value on the third (3rd) Trading Day before the elected payment date; and
(ii)
for Subsection 10(e), the Market Value on the next Trading Day after the Director’s death.
(g)
Effect of Reorganization of the Corporation for Canadian Taxpayers
In the event of any merger, consolidation or other reorganization of the Corporation in which the Corporation is not the surviving or continuing corporation, all Deferred Stock Units granted hereunder and outstanding on the date of such reorganization shall be assumed by the surviving or continuing corporation. If, in the event of any such merger, consolidation or other reorganization, provision for such assumption satisfactory to an owner of a Deferred Stock Unit granted under this Plan is not made by the surviving or continuing corporation, such owner shall have distributed to him or her within sixty (60) days after the reorganization, in full satisfaction, cash in payment of the Market Value on the Trading Day immediately preceding the day of such reorganization.

8


11.
US TAXPAYER- DEFERRED STOCK UNITS
This Section 11 only applies to U.S. Taxpayers:
(a)    Choice of Compensation Mix and Election Payment Date
Directors shall elect on or before December 31 of the calendar year immediately preceding the calendar year in which Compensation will be earned:
(i)
the portion of such Compensation, excluding any Bonus Retainer, to be received by those Directors in cash, Shares or Deferred Stock Units in respect of that calendar year. If no election is made the Director shall, subject to any minimum amounts of cash, Shares or Deferred Stock Units as set out in Appendix “A”, be deemed to have elected 100% in cash;
(ii)
the date, to be agreed upon by each of the Directors and the Corporation for payment of such Director’s Deferred Stock Unit Account where such date may be any date after that Director’s Retirement Date, provided that the payment date is after that Retirement Date and no later than December 31 of the first calendar year commencing after that Retirement Date. If no such payment date is determined, the Corporation, at its sole discretion, shall pay the amount owing from Director’s Deferred Stock Unit Account within ninety (90) days following that Director’s Retirement Date;
(iii)
where a Director joins the Board after January 1 in any year, such Director shall make his or her election for both compensation mix and payment date within thirty (30) days of his or her election or appointment to the Board; and
(iv)
in all cases, the Directors’ elections shall be irrevocable and shall remain in force from the date of such election until the Director’s Retirement Date.
(a)
U.S. Election Form
Each Director shall fill out a U.S. Election Form indicating their elected compensation mix and payment date of their Deferred Stock Unit Account and deliver such U.S. Election Form to the Corporation. Such form shall be irrevocable.
(b)
Specified Employee
Notwithstanding Subsection 11 (a), if the payment of a Director’s Deferred Stock Unit Account would be subject to taxation or penalties under Code Section 409A because the timing of such payment is not delayed as provided in Section 409A for a “specified employee,” then if the Director is (1) a U.S. Taxpayer and (2) a “specified employee” under Code Section 409A, any payment which that Director would otherwise be entitled to receive during the six (6) month period following the Director’s Retirement Date shall be delayed and paid within fifteen (15) days after the date that is six (6) months following the Director’s Retirement Date, or such earlier date upon which such amount can be paid under Code Section 409A without being subject to such taxation, such as upon that Director’s death.

9


(c)
Payment on Death of a U.S. Taxpayer
(i)
When a Director dies, the value of the Deferred Stock Unit Account, credited to that Director’s Deferred Stock Unit Account, net of applicable withholdings, shall be paid to his or her Beneficiary not later than by the later of (i) the end of the calendar year of the Director’s Retirement Date, or (ii) ninety (90) days following that Director’s date of death, provided that the Beneficiary shall not be permitted to designate the taxable year in which such payment is made.
(ii)
Notwithstanding the above, if the Beneficiary of the deceased Director has not been determined within sixty (60) days after the Director’s death, the Corporation shall make such payment to the Estate.
(e)    Determining Value for U.S. Taxpayers
To determine the value of Deferred Stock Units for the purposes of a payment to a Director (or, where the Director has died, his or her Beneficiary or Estate, as the case may be) under Subsections 11(a)(ii), (iii), (c) or (d), a Deferred Stock Unit will be valued equal to the Market Value multiplied by the number of Deferred Stock Units (including fractional Units) credited to a Director’s Deferred Stock Unit Account on the following basis:
(i)
for Subsections 11(a)(ii),(iii) and (c), the Market Value on the third (3rd) Trading Day before the elected payment date; and
(ii)
for Subsection 11(d), the Market Value on the next Trading Day after the Director’s death.
(a)
Dual-Taxed Members
In the event that a Director is both a U.S. Taxpayer and a Canadian Taxpayer at the time that the Director’s Deferred Stock Units become payable, the provisions of this Section 11(f) shall apply:
(i)
If the Director has made a valid election under Section 11(a) and (b) with regard to payment of the Director’s Deferred Stock Units, payment of such Director’s Deferred Stock Unit Account shall be made in accordance such election, subject to Section 11(c).
(ii)
If the Director has not made a valid election under Section 11(a) and (b) with regard to payment of the Director’s Deferred Stock Units, payment of such Director’s Deferred Stock Unit Account shall be made as of a date determined by the Corporation in its discretion, with such payment date to be within ninety (90) days following the Director’s Retirement Date, subject to the following:

10


a.
If the ninety (90) day period begins in one calendar year and ends in the following calendar year, the payment date within such 90-day period shall be determined in the sole discretion of the Corporation, and the Director shall not be permitted to make a payment election under Section 10(c) and (d) of the Plan that applies for a Canadian Taxpayer; or
b.
If the ninety (90) day period begins and ends in the same calendar year, the Director shall be permitted to make a payment election under Section 10(c) and (d) of the Plan, but the payment date elected by the Director must fall within the 90-day period following the Director’s Retirement Date.
(g)    Code Section 409A Compliance
With respect to any Director who is a U.S. Taxpayer, the Corporation intends that this Plan shall comply with the applicable provisions of Code Section 409A, or an exemption from the application of Code Section 409A, in order to prevent the inclusion in the gross income of such Director of any deferred amount in a taxable year that is prior to the taxable year in which such amount would otherwise be distributed or made available to such Director under the terms of this Plan. This Plan shall be construed, interpreted and administered in a manner consistent with such intent. In furtherance of this intent, to the extent that any term of this Plan is ambiguous, such term shall be interpreted to comply with Code Section 409A, or an exemption from the application of Code Section 409A, as determined by the Corporation.
(h)
Effect of Reorganization of the Corporation for U.S. Taxpayers and Dual-Taxed Members
In the event of any merger, consolidation or other reorganization of the Corporation where the surviving or continuing corporation does not assume all of the Director’s Deferred Stock Units that are outstanding on the date of such reorganization, and such event constitutes a “change in control” of the Corporation within the meaning of Code Section 409A, then the surviving or continuing corporation shall distribute to the Director, within sixty (60) days after the closing date of such event, in complete satisfaction of all the rights of the Director under this Plan, cash in full payment of the Market Value of the Director’s Deferred Stock Units as valued as of the Trading Day immediately preceding the closing date of such event. In the event that the Director is a Dual-Taxed Member, this Section 11(h) shall apply and Section 10(g) shall be inapplicable.
12.
BROKERAGE COMMISSIONS
All brokerage commissions and other transaction costs in respect of Share purchases made under Section 8 of this Plan shall be paid by the Corporation.

11


13.
TAXES AND REPORTING
(a)
The Corporation shall deduct from all amounts otherwise payable to a Director (or Beneficiary or Estate, as the case may be) all amounts, including applicable taxes, that are required by law to be withheld with respect to amount otherwise payable.
(b)
Notwithstanding anything else contained herein, each Director who participates in this Plan shall be responsible for:
(i)
the payment of all applicable taxes including, but not limited to, income taxes payable in connection with the acquisition, holding and delivery of Shares for or to a Director pursuant to this Plan and the payment of the value of the Deferred Stock Units, subject to deduction and remittance by the Corporation of applicable withholding taxes; and
(ii)
compliance with the continuous disclosure requirements of the applicable securities commissions or similar regulatory authorities in Canada and those exchanges upon which the Corporation’s Shares are traded, including, but not limited to, the preparation and filing of insider trading reports respecting the acquisition of Shares pursuant to this Plan,
and the Corporation, its employees and agents shall bear no liability in connection with the payment of such taxes or the compliance with such disclosure requirements.
14.
DILUTION ADJUSTMENTS
In the event that the outstanding Shares of the Corporation shall be increased or decreased, or changed into, or exchanged for a different number or kind of shares or other securities of the Corporation or another corporation, whether through a stock dividend, stock split, consolidation, recapitalization, amalgamation, reorganization, arrangement or other transaction, the Governance Committee or the Board may make appropriate adjustments to the number or kind of shares or securities upon which Deferred Stock Units are based under this Plan, and as regards Deferred Stock Units previously granted or to be granted pursuant to this Plan, in the number or kind of shares or securities upon which Deferred Stock Units are based and the purchase price therefor.
15.
OPERATION OF RIGHTS PLAN
The appropriate adjustments in the number of Deferred Stock Units may be made by the Board in its discretion in order to give effect to the adjustments in the number of Shares of the Corporation resulting from the implementation and operation of the Shareholder Rights Plan Agreement originally dated as of November 9, 1995 and as amended from time to time.

12


16.
AMENDMENTS, ETC.
Subject to applicable regulatory approval, the Board may revise, suspend or discontinue this Plan in whole or in part. No such revision, suspension, or discontinuance shall alter or impair the rights of a Director in respect of Deferred Stock Units or Shares previously granted or received under this Plan, without the consent of that Director.
17.
PERIODIC REVIEW
The compensation available, and competitiveness of this Plan relative to the Comparator Group, will be reviewed:
(a)
by external consultants every second year, commencing in 2015; and
(b)
by internal management every second year, commencing in 2014.
18.
EFFECTIVE DATE
This Plan is effective as of January 1, 2020, and may be amended from time to time. Commencing January 1, 2020, no new Shares or Deferred Stock Units shall be granted or received under any previous “Directors’ Compensation Plan” for Enbridge Inc. Any Shares or Deferred Stock Units previously granted or received under such previous compensation plans shall continue without alteration, including any previous elected payment date made by a Director, or impairment of the rights of a Director with respect to such Compensation.

13


APPENDIX “A”
to the Directors’ Compensation Plan
Retainer and Fees
1.
Flat Fee Schedule
The following table establishes the annual fee schedule for Directors and is effective as of June 1, 2020.
 
Elective Payment Form1

 
Compensation Elements

 
Annual Fee
2
Before minimum share ownership
After minimum share ownership

Cash

Shares

DSUs
 
 
Cash
 
Shares

DSUs
Board Retainer
$242,250

Up to 50%

Up to 50%

50% to 100%

Up to 65%

Up to 65%

35% to 100%
Additional Board Chair Retainer
$225,250
Additional Committee Chair Retainer:
AFRC
HRCC
S&R
GC
CSR


$25,000
$20,000
$15,000
$15,000
$15,000

1.    Directors may elect the form of payment in increments of 5% up to the percentage amounts specified in the table.
2.
All fees in U.S. dollars.
2.
Penalty for Non-Attendance
At the end of each year, the Governance Committee will review the record of attendance of Directors at Committee meetings and Board meetings. The Chair of the Governance Committee along with the Board Chair, at their discretion, will recommend to the Board appropriate penalties for non-attendance by Directors at Committee and Board meetings.
3.
Travel Fees
A per diem allowance of $1,500 U.S. shall be paid in cash to Directors who travel from their home state or province to a meeting in another state or province.



14


4.
Share Ownership Requirement
Effective January 1, 2016, Directors shall hold a personal investment in Shares and Deferred Stock Units of at least three (3) times the amount of the annual Board Retainer, expressed in Canadian currency and be required to achieve such investment within five (5) years of joining the Board.









































_______________________
 
1U.S. Currency for those Directors paid in U.S. funds.


15


APPENDIX “B”
to the Directors’ Compensation Plan
DESIGNATION OF BENEFICIARY FORM

I, _____________________________________ (Director’s Name) for the purposes of

designating a Beneficiary pursuant to the Directors’ Compensation Plan of Enbridge Inc.

hereby designate _______________________ (insert name of Beneficiary (ies)) as my

Beneficiary of the Compensation owed to me by the Corporation.
 

At my own discretion, I make an additional designation should my Beneficiary not survive me.

I designate as my contingent Beneficiary _________________________________ (insert

name of contingent Beneficiary) of the Compensation owed to me by the Corporation.


I make this designation on the _____ day of _______, 20____.





________________________
Signature

    
________________________
Print Name    

Instructions:
This Designation of Beneficiary Form should be completed, signed and delivered to Enbridge Inc. as soon as possible once you have been appointed to the Board of the Corporation. Any changes to the above will require the delivery of an amended form.

In the event that you would like to name a contingent beneficiary, should your primary beneficiary not survive you, please indicate above, a contingent beneficiary.

For questions regarding your Plan or Form, please call Karen Uehara at (587)955-2986. For delivery to Enbridge Inc., please fax your Form to (403) 231-5929.

16
Exhibit 31.1
CERTIFICATION PURSUANT TO SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002
I, Al Monaco, certify that:
1.
I have reviewed this quarterly report on Form 10-Q of Enbridge Inc.;

2.
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.
The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a.
Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b.
Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c.
Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d.
Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5.
The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

a.
All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

b.
Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date:
July 29, 2020
By:
/s/ Al Monaco
 
 
 
Al Monaco
President and Chief Executive Officer
Enbridge Inc.

Exhibit 31.2
CERTIFICATION PURSUANT TO SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002
I, Colin K. Gruending, certify that:
1.
I have reviewed this quarterly report on Form 10-Q of Enbridge Inc.;

2.
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.
The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a.
Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b.
Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c.
Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d.
Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5.
The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

a.
All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

b.
Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting

Date:
July 29, 2020
By:
/s/ Colin K. Gruending
 
 
 
Colin K. Gruending
Executive Vice President and Chief Financial Officer
(Principal Financial Officer)
Enbridge Inc.

EXHIBIT 32.1
CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report of Enbridge Inc. on Form 10-Q for the period ending June 30, 2020 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Al Monaco, President and Chief Executive Officer of Enbridge Inc., certify, pursuant to 18 U.S.C. section 1350, as adopted pursuant to section 906 of the Sarbanes-Oxley Act of 2002, that:
1.
The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

2.
The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of Enbridge Inc.

Date:
July 29, 2020
By:
/s/ Al Monaco
 
 
 
Al Monaco
President and Chief Executive Officer
Enbridge Inc.


EXHIBIT 32.2
CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report of Enbridge Inc. on Form 10-Q for the period ending June 30, 2020 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Colin K. Gruending, Executive Vice President and Chief Financial Officer of Enbridge Inc., certify, pursuant to 18 U.S.C. section 1350, as adopted pursuant to section 906 of the Sarbanes-Oxley Act of 2002, that:
1.
The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

2.
The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of Enbridge Inc.

Date:
July 29, 2020
By:
/s/ Colin K. Gruending
 
 
 
Colin K. Gruending
Executive Vice President and Chief Financial Officer
(Principal Financial Officer)
Enbridge Inc.