Document

 

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
x
 
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended September 30, 2018
OR
o

 
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the transition period from            to           
Commission file number 1-10934
 
enblogocoloura11.jpg
 
ENBRIDGE INC.
(Exact Name of Registrant as Specified in Its Charter)
 
 
 
Canada
 
None
(State or Other Jurisdiction of
Incorporation or Organization)
 
(I.R.S. Employer
Identification No.)
200, 425 - 1st Street S.W.
Calgary, Alberta, Canada T2P 3L8
(Address of Principal Executive Offices) (Zip Code)
(403) 231-3900
(Registrant’s Telephone Number, Including Area Code)

Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No o
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes x No o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
Large accelerated filer x
 
Accelerated filer o
Non-accelerated filer o
 
Smaller reporting company o
Emerging growth company o
 
  
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. o
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No x
The registrant had 1,724,389,606 common shares outstanding as of October 26, 2018.
 


1

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



2

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


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

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


4

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

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



5

PART I - FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

ENBRIDGE INC.
CONSOLIDATED STATEMENTS OF EARNINGS
 
Three months ended
September 30,
 
Nine months ended
September 30,
 
2018

2017

 
2018

2017

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

 

 
 

 

Operating revenues
 

 

 
 

 

Commodity sales
6,919

5,012

 
20,638

18,498

Gas distribution sales
478

573

 
3,260

2,783

Transportation and other services
3,948

3,642

 
10,918

10,208

Total operating revenues (Note 3)
11,345

9,227

 
34,816

31,489

Operating expenses
 
 
 
 
 
Commodity costs
6,905

5,087

 
20,180

18,126

Gas distribution costs
112

215

 
1,857

1,659

Operating and administrative
1,652

1,587

 
4,929

4,784

Depreciation and amortization
799

848


2,452

2,388

Asset impairment (Note 6)
4

—

 
1,076

—

Goodwill impairment (Note 6)
1,019

—

 
1,019

—

Total operating expenses
10,491

7,737

 
31,513

26,957

Operating income
854

1,490

 
3,303

4,532

Income from equity investments
378

280

 
1,076

752

Other income/(expense)
 
 
 
 
 
Net foreign currency gain/(loss)
57

150

 
(171
)
257

Other
(33
)
75

 
61

182

Interest expense
(696
)
(653
)

(2,042
)
(1,704
)
Earnings before income taxes
560

1,342

 
2,227

4,019

Income tax expense (Note 12)
(347
)
(327
)

(177
)
(818
)
Earnings
213

1,015

 
2,050

3,201

Earnings attributable to noncontrolling interests and redeemable noncontrolling interests
(209
)
(168
)

(352
)
(633
)
Earnings attributable to controlling interests
4

847

 
1,698

2,568

Preference share dividends
(94
)
(82
)

(272
)
(246
)
Earnings/(loss) attributable to common shareholders
(90
)
765


1,426

2,322

Earnings/(loss) per common share attributable to common shareholders (Note 5)
(0.05
)
0.47


0.84

1.57

Diluted earnings/(loss) per common share attributable to common shareholders (Note 5)
(0.05
)
0.47

 
0.84

1.56

 See accompanying notes to the interim consolidated financial statements.




6

ENBRIDGE INC.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
 
Three months ended
September 30,
 
Nine months ended
September 30,
 
2018

2017

 
2018

2017

(unaudited; millions of Canadian dollars)
 

 

 
 

 

Earnings
213

1,015

 
2,050

3,201

Other comprehensive income/(loss), net of tax
 
 
 
 
 
Change in unrealized gain on cash flow hedges
57

97

 
150

10

Change in unrealized gain/(loss) on net investment hedges
83

285

 
(200
)
505

Other comprehensive income from equity investees
(1
)
1

 
18

9

Reclassification to earnings of (gain)/loss on cash flow hedges
31

(14
)
 
104

93

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

6

 
28

13

Foreign currency translation adjustments
(989
)
(2,057
)
 
1,637

(3,068
)
Other comprehensive income/(loss), net of tax
(814
)
(1,682
)

1,737

(2,438
)
Comprehensive income/(loss)
(601
)
(667
)
 
3,787

763

Comprehensive (income)/loss attributable to noncontrolling interests and redeemable noncontrolling interests
(102
)
155

 
(546
)
(204
)
Comprehensive income/(loss) attributable to controlling interests
(703
)
(512
)
 
3,241

559

Preference share dividends
(94
)
(82
)
 
(272
)
(246
)
Comprehensive income/(loss) attributable to common shareholders
(797
)
(594
)
 
2,969

313

See accompanying notes to the interim consolidated financial statements.


7

ENBRIDGE INC.
CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
 
Nine months ended
September 30,
 
2018

2017

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

 

Preference shares
 
 
Balance at beginning and end of period
7,747

7,255

Common shares
 

 

Balance at beginning of period
50,737

10,492

Common shares issued in Merger Transaction
—

37,429

Dividend Reinvestment and Share Purchase Plan
1,181

889

Shares issued on exercise of stock options
26

58

Balance at end of period
51,944

48,868

Additional paid-in capital
 

 

Balance at beginning of period
3,194

3,399

Stock-based compensation
40

70

Fair value of outstanding earned stock-based compensation from Merger Transaction
—

77

Options exercised
(14
)
(70
)
Enbridge Energy Company, Inc. common control transaction
—

78

Dilution loss on Enbridge Energy Partners, L.P. issuance of Class A units
—

(522
)
Dilution gain on Spectra Energy Partners, LP restructuring (Note 10)
1,136

—

Dilution gains/(losses) and other
(89
)
62

Sale of noncontrolling interests in subsidiaries (Note 10)
79

—

Balance at end of period
4,346

3,094

Deficit
 

 

Balance at beginning of period
(2,468
)
(716
)
Earnings attributable to controlling interests
1,698

2,568

Preference share dividends
(272
)
(246
)
Common share dividends declared
(2,297
)
(2,552
)
Dividends paid to reciprocal shareholder
25

22

Modified retrospective adoption of accounting standard (Note 2)
(86
)
—

Redemption value adjustment attributable to redeemable noncontrolling interests
(318
)
232

Adjustment for the recognition of unutilized tax deductions for stock-based compensation expense
—

41

Balance at end of period
(3,718
)
(651
)
Accumulated other comprehensive income/(loss) (Note 9)
 

 

Balance at beginning of period
(973
)
1,058

Other comprehensive income/(loss) attributable to common shareholders, net of tax
1,543

(2,009
)
Balance at end of period
570

(951
)
Reciprocal shareholding
 

 

Balance at beginning and end of period
(102
)
(102
)
Total Enbridge Inc. shareholders’ equity
60,787

57,513

Noncontrolling interests
 

 

Balance at beginning of period
7,597

577

Earnings attributable to noncontrolling interests
248

452

Other comprehensive income/(loss) attributable to noncontrolling interests, net of tax
 
 
Change in unrealized gain/(loss) on cash flow hedges
8

(13
)
Foreign currency translation adjustments
140

(446
)
Reclassification to earnings of loss on cash flow hedges
23

29

 
171

(430
)
Comprehensive income attributable to noncontrolling interests
419

22

Noncontrolling interests resulting from Merger Transaction
—

8,877

Enbridge Energy Company, Inc. common control transaction
—

(331
)
Dilution gain on Enbridge Energy Partners, L.P. issuance of Class A units
—

832

Spectra Energy Partners, LP restructuring (Note 10)
(1,486
)
—

Sale of noncontrolling interests in subsidiaries (Note 10)
1,183

—

Distributions
(637
)
(634
)
Contributions
23

498

Deconsolidation of Sabal Trail Transmission, LLC
—

(2,318
)
Disposition of Olympic Pipeline
—

(24
)
Other
12

(16
)
Balance at end of period
7,111

7,483

Total equity
67,898

64,996

Dividends paid per common share
2.013

1.803

See accompanying notes to the interim consolidated financial statements.


8

ENBRIDGE INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
 
Nine months ended
September 30,
 
2018

2017

(unaudited; millions of Canadian dollars)
 
 
Operating activities
 
 
Earnings
2,050

3,201

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

 

Depreciation and amortization
2,452

2,388

Deferred income tax (recovery)/expense
(51
)
725

Changes in unrealized (gain)/loss on derivative instruments, net (Note 11)
319

(1,243
)
Earnings from equity investments
(1,076
)
(752
)
Distributions from equity investments
1,090

859

Asset impairment
1,076

—

Goodwill impairment
1,019

—

(Gain)/loss on dispositions
76

(116
)
Other
101

132

Changes in operating assets and liabilities
943

121

Net cash provided by operating activities
7,999

5,315

Investing activities
 

 

Capital expenditures
(4,584
)
(5,868
)
Long-term investments
(1,051
)
(3,012
)
Distributions from equity investments in excess of cumulative earnings (Note 7)
1,243

62

Additions to intangible assets
(491
)
(668
)
Cash acquired in Merger Transaction
—

681

Proceeds from dispositions
1,913

622

Reimbursement of capital expenditures
—

212

Other
(102
)
(63
)
Net cash used in investing activities
(3,072
)
(8,034
)
Financing activities
 

 

Net change in short-term borrowings
(196
)
705

Net change in commercial paper and credit facility draws
(2,358
)
956

Debenture and term note issues, net of issue costs
3,537

7,176

Debenture and term note repayments
(3,757
)
(4,446
)
Sale of noncontrolling interest in subsidiaries
1,289

—

Purchase of interest in consolidated subsidiary
—

(227
)
Contributions from noncontrolling interests
23

498

Distributions to noncontrolling interests
(637
)
(714
)
Contributions from redeemable noncontrolling interests
62

614

Distributions to redeemable noncontrolling interests
(264
)
(180
)
Common shares issued
17

22

Preference share dividends
(268
)
(246
)
Common share dividends
(2,254
)
(2,077
)
Other
(5
)
—

Net cash provided by/(used in) financing activities
(4,811
)
2,081

Effect of translation of foreign denominated cash and cash equivalents and restricted cash
23

(77
)
Net increase/(decrease) in cash and cash equivalents and restricted cash
139

(715
)
Cash and cash equivalents and restricted cash at beginning of period
587

1,562

Cash and cash equivalents and restricted cash at end of period
726

847

See accompanying notes to the interim consolidated financial statements.




9

ENBRIDGE INC.
CONSOLIDATED STATEMENTS OF FINANCIAL POSITION
 
September 30,
2018

December 31,
2017

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

 

Assets
 

 

Current assets
 

 

Cash and cash equivalents
643

480

Restricted cash
83

107

Accounts receivable and other
5,668

7,053

Accounts receivable from affiliates
75

47

Inventory
1,362

1,528

 
7,831

9,215

Property, plant and equipment, net
90,679

90,711

Long-term investments
15,983

16,911

Deferred amounts and other assets
10,638

6,442

Intangible assets, net
3,273

3,267

Goodwill
33,477

34,457

Deferred income taxes
1,342

1,090

Total assets
163,223

162,093

 
 
 
Liabilities and equity
 

 

Current liabilities
 

 

Short-term borrowings
1,251

1,444

Accounts payable and other
7,599

9,518

Accounts payable to affiliates
190

157

Interest payable
611

634

Current portion of long-term debt
3,516

2,871

 
13,167

14,624

Long-term debt
58,707

60,865

Other long-term liabilities
9,090

7,510

Deferred income taxes
10,040

9,295

 
91,004

92,294

Contingencies (Note 14)




Redeemable noncontrolling interests
4,321

4,067

Equity
 

 

Share capital
 

 

Preference shares
7,747

7,747

Common shares (1,794 and 1,695 outstanding at September 30, 2018 and December 31, 2017, respectively)
51,944

50,737

Additional paid-in capital
4,346

3,194

Deficit
(3,718
)
(2,468
)
Accumulated other comprehensive income/(loss) (Note 9)
570

(973
)
Reciprocal shareholding
(102
)
(102
)
Total Enbridge Inc. shareholders’ equity
60,787

58,135

Noncontrolling interests
7,111

7,597

 
67,898

65,732

Total liabilities and equity
163,223

162,093

See accompanying notes to the interim consolidated financial statements.



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, 2017 included in our Annual Report on Form 10-K. In the opinion of management, the interim consolidated financial statements contain all normal recurring adjustments necessary to present fairly our financial position, results of operations and cash flows for the interim periods reported. These interim consolidated financial statements follow the same significant accounting policies as those included in our annual consolidated financial statements for the year ended December 31, 2017 included in our Annual Report on Form 10-K, except for the adoption of new standards (Note 2). Amounts are stated in Canadian dollars unless otherwise noted.
 
Our operations and earnings for interim periods can be affected by seasonal fluctuations within the gas distribution utility businesses, as well as other factors such as the supply of and demand for crude oil and natural gas, and may not be indicative of annual results.

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

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

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





11

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

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

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

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

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

Revenue from Contracts with Customers
Effective January 1, 2018, we adopted ASU 2014-09 on a modified retrospective basis to contracts that were not complete at the date of initial application. The new standard was issued with the intent of significantly enhancing consistency and comparability of revenue recognition practices across entities and industries. The new standard establishes a single, principles-based five-step model to be applied to all


12

contracts with customers and introduces new and enhanced disclosure requirements. It also requires the use of more estimates and judgments than the previous standards.
In adopting Accounting Standards Codification (ASC) 606, we applied the practical expedient for contract modifications whereby contracts that were modified before January 1, 2018 were not retrospectively restated. Instead, the aggregate effect of all contract modifications occurring before that time has been reflected when identifying satisfied and unsatisfied performance obligations, determining the transaction price and allocating the transaction price to satisfied and unsatisfied performance obligations.
Revenue was previously recognized for a certain contract within the Liquids Pipelines business unit using a formula-based method. Under the new revenue standard, revenue is recognized on a straight-line basis over the term of the agreement in order to reflect the fulfillment of our performance obligation to provide up to a specified volume of pipeline capacity throughout the term of the contract.
Certain payments received from customers to offset the cost of constructing assets required to provide services to those customers, referred to as Contributions in Aid of Construction (CIACs) were previously recorded as reductions of property, plant and equipment regardless of whether the amounts were imposed by regulation or arose from negotiations with customers. Under the new revenue standard, CIACs which are negotiated as part of an agreement to provide transportation and other services to a customer are deemed to be advance payments for future services and are recognized as revenue when those future services are provided. Accordingly, negotiated CIACs are accounted for as deferred revenue and recognized as revenue over the term of the associated revenue contract. Amounts which are required to be collected from the customer based on requirements of the regulator continue to be accounted for as reductions of property, plant and equipment.
The below table presents the cumulative, immaterial effect of the adoption of ASC 606 on our Consolidated Statement of Financial Position as at January 1, 2018 on each affected financial statement line item. For the three and nine months ended September 30, 2018, the effect of the adoption of ASC 606 on our Consolidated Statement of Earnings was not material.
 
Balance at December 31, 2017
Adjustments Due to ASC 606
Balance at
January 1, 2018
(millions of Canadian dollars)
 
 
 
Assets
 
 
 
Deferred amounts and other assets
6,442

(170
)
6,272

Property, plant and equipment, net
90,711

112

90,823

Liabilities and equity
 
 
 
Accounts payable and other
9,478

62

9,540

Other long-term liabilities
7,510

66

7,576

Deferred income taxes
9,295

(62
)
9,233

Redeemable noncontrolling interests
4,067

(38
)
4,029

Deficit
(2,468
)
(86
)
(2,554
)

FUTURE ACCOUNTING POLICY CHANGES
Amended Guidance on Cloud Computing Arrangements
In August 2018, ASU 2018-15 was issued to provide guidance on the accounting for implementation costs incurred in a cloud computing arrangement (CCA) that is a service contract. The amendment aligns the accounting for costs incurred to implement a CCA that is a service arrangement with the guidance on capitalizing costs associated with developing or obtaining internal-use software. Additionally, ASU 2018-15 specifies that an entity would apply ASC 350-40, Internal-use software, to determine which implementation costs related to a hosting arrangement that is a service contract should be capitalized and which should be expensed. Furthermore, the amendments in the update require capitalized costs be amortized on a straight-line basis generally over the term of the arrangement and presented in the same income statement line as fees paid for the hosting service. The new standard also requires that the balance sheet presentation of capitalized implementation costs to be the same as that of the prepayment


13

of fees related to the hosting arrangement, as well as similar consistency in classifications from a cash flow statement perspective. ASU 2018-15 is effective January 1, 2020 and early adoption is permitted. We are currently assessing the impact of the new standard on our consolidated financial statements.

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

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

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

Improvements to Accounting for Hedging Activities
ASU 2017-12 was issued in August 2017 with the objective of better aligning a company’s risk management activities and the resulting hedge accounting reflected in the financial statements. The amendments allow cash flow hedging of contractually specified components in financial and non-financial items. Under the new guidance, hedge ineffectiveness is no longer required to be measured and hedging instruments’ fair value changes will be recorded in the same income statement line as the hedged item. The ASU also allows the initial quantitative hedge effectiveness assessment to be performed at any time before the end of the quarter in which the hedge is designated. After initial quantitative testing is performed, an ongoing qualitative effectiveness assessment is permitted. The accounting update is effective January 1, 2019, with early adoption permitted, and is to be applied on a modified retrospective basis. We are currently assessing the impact of the new standard on our consolidated financial statements.

Amending the Amortization Period for Certain Callable Debt Securities Purchased at a Premium
ASU 2017-08 was issued in March 2017 with the intent of shortening the amortization period to the earliest call date for certain callable debt securities held at a premium. The accounting update is effective January 1, 2019 and will be applied on a modified retrospective basis. We are currently assessing the impact of the new standard on our consolidated financial statements.
 
Accounting for Credit Losses
ASU 2016-13 was issued in June 2016 with the intent of providing financial statement users with more useful information about the expected credit losses on financial instruments and other commitments to extend credit held by a reporting entity at each reporting date. Current treatment uses the incurred loss methodology for recognizing credit losses that delays the recognition until it is probable a loss has been incurred. The accounting update adds a new impairment model, known as the current expected credit loss model, which is based on expected losses rather than incurred losses. Under the new guidance, an entity will recognize as an allowance its estimate of expected credit losses, which the Financial Accounting Standards Board believes will result in more timely recognition of such losses. The accounting update is effective January 1, 2020. We are currently assessing the impact of the new standard on our consolidated financial statements.





14

Recognition of Leases
ASU 2016-02 was issued in February 2016 with the intent to increase transparency and comparability among organizations. It requires lessees of operating lease arrangements to recognize lease assets and lease liabilities on the statement of financial position and disclose additional key information about lease agreements. The accounting update also replaces the current definition of a lease and requires that an arrangement be recognized as a lease when a customer has the right to obtain substantially all of the economic benefits from the use of an asset, as well as the right to direct the use of the asset. We will adopt the new standard on January 1, 2019 and we intend to apply the transition practical expedients offered in connection with this update. The election to apply the package of practical expedients allows an entity to not apply the new lease standard to the prior year comparative periods in the year of adoption. Application of the package of practical expedients also permits entities not to reassess a) whether any expired or existing contracts contain leases in accordance with the new guidance, b) lease classifications, and c) whether initial direct costs capitalized under current guidance continue to meet the definition of initial direct costs under the new guidance.

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

In July 2018, ASU 2018-11 was issued to address additional stakeholder concerns regarding the unanticipated costs and complexities associated with the modified retrospective transition method as well as the requirement for lessors to separate components of a contract. Under the new guidance, entities are provided with an additional transition method which allows entities to apply the new standard at the date of adoption and to elect not to recast comparative periods presented. This amendment also provides a practical expedient which allows lessors to combine associated lease and nonlease components within a contract when certain conditions are met. We intend to adopt the new transition option in connection with the adoption of the new lease requirements; however we continue to evaluate the lessor practical expedient to combine lease and nonlease components.

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



15

3. REVENUE

REVENUE FROM CONTRACTS WITH CUSTOMERS
Major Products and Services
 
Liquids Pipelines

Gas Transmission and Midstream

Gas Distribution

Green Power and Transmission

Energy Services

Eliminations and Other

Consolidated

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

 
 

 

 

 

 

Transportation revenue
2,190

979

97

—

—

—

3,266

Storage and other revenue
31

53

55

—

—

—

139

Gas gathering and processing revenue
—

200

—

—

—

—

200

Gas distribution revenue
—

—

478

—

—

—

478

Electricity and transmission revenue
—

—

—

115

—

—

115

Commodity sales
—

298

—

—

—

—

298

Total revenue from contracts with customers
2,221

1,530

630

115

—

—

4,496

Commodity sales
—

—

—

—

6,621

—

6,621

Other revenue1
222

(6
)
11

2

—

(1
)
228

Intersegment revenue
86

4

4

—

25

(119
)
—

Total revenue
2,529

1,528

645

117

6,646

(120
)
11,345

 
Liquids Pipelines

Gas Transmission and Midstream

Gas Distribution

Green Power and Transmission

Energy Services

Eliminations and Other

Consolidated

Nine months ended
September 30, 2018
(millions of Canadian dollars)
 

 
 

 

 

 

 

Transportation revenue
6,327

2,889

487

—

—

—

9,703

Storage and other revenue
113

164

173

—

—

—

450

Gas gathering and processing revenue
—

636

—

—

—

—

636

Gas distribution revenue
—

—

3,260

—

—

—

3,260

Electricity and transmission revenue
—

—

—

417

—

—

417

Commodity sales
—

1,630

—

—

—

—

1,630

Total revenue from contracts with customers
6,440

5,319

3,920

417

—

—

16,096

Commodity sales
—

—

—

—

19,008

—

19,008

Other revenue1
(308
)
2

22

6

—

(10
)
(288
)
Intersegment revenue
256

8

10

—

106

(380
)
—

Total revenue
6,388

5,329

3,952

423

19,114

(390
)
34,816

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

We disaggregate revenue into categories which represent our principal performance obligations within each business segment because these revenue categories represent the most significant revenue streams in each segment and consequently are considered to be the most relevant revenue information for management to consider in evaluating performance.
Contract Balances
 
Receivables
Contract Assets
Contract Liabilities
(millions of Canadian dollars)
 
 
 
Balance as at January 1, 2018
2,475

290

992

Balance as at September 30, 2018
1,625

267

1,203


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


16

which our right to the payment is unconditional. Amounts included in contract assets are transferred to accounts receivable when our right to the consideration becomes unconditional.
Contract liabilities represent payments received for performance obligations which have not been fulfilled. Contract liabilities primarily relate to make-up rights and deferred revenue. Revenue recognized during the three and nine months ended September 30, 2018 included in contract liabilities at the beginning of the period is $19 million and $143 million, respectively. Increases in contract liabilities from cash received, net of amounts recognized as revenue during the three and nine months ended September 30, 2018 were $147 million and $345 million, respectively.
Performance Obligations
Segment
Nature of Performance Obligation
Liquids Pipelines

•
Transportation and storage of crude oil and natural gas liquids (NGL)
Gas Transmission and Midstream
•
Sale of crude oil, natural gas and NGLs
•
Transportation, storage, gathering, compression and treating of natural gas
•
Transportation of NGLs
Gas Distribution
•
Supply and delivery of natural gas
•
Transportation of natural gas
•
Storage of natural gas
Green Power and Transmission

•
Generation and transmission of electricity
•
Delivery of electricity from renewable energy generation facilities
There was no material revenue recognized in the three and nine months ended September 30, 2018 from performance obligations satisfied in previous periods.
Payment Terms
Payments are received monthly from customers under long-term transportation, commodity sales, and gas gathering and processing contracts. Payments from Gas Distribution customers are received on a continuous basis based on established billing cycles.
Certain contracts in the United States offshore business provide for us to receive a series of fixed monthly payments (FMPs) for a specified period which is less than the period during which the performance obligations are satisfied. As a result, a portion of the FMPs is recorded as a contract liability. The FMPs are not considered to be a financing arrangement because the payments are scheduled to match the production profiles of offshore oil and gas fields, which generate greater revenue in the initial years of their productive lives.
Revenue to be Recognized from Unfulfilled Performance Obligations
Total revenue from performance obligations expected to be fulfilled in future periods is $64.7 billion, of which $1.7 billion and $5.8 billion is expected to be recognized during the three months ending December 31, 2018, and the year ending December 31, 2019, respectively.

The revenues excluded from the amounts above based on optional exemptions available under ASC 606, as explained below, represent a significant portion of our overall revenues and revenues from contracts with customers. Certain revenues such as flow-through operating costs charged to shippers are recognized at the amount for which we have the right to invoice our customers and are excluded from the amounts for revenue to be recognized in the future from unfulfilled performance obligations above. Variable consideration is excluded from the amounts above due to the uncertainty of the associated consideration, which is generally resolved when actual volumes and prices are determined. For example, we consider interruptible transportation service revenues to be variable revenues since volumes cannot be estimated. Additionally, the effect of escalation on certain tolls which are contractually escalated for


17

inflation has not been reflected in the amounts above as it is not possible to reliably estimate future inflation rates. Revenues for periods extending beyond the current rate settlement term for regulated contracts where the tolls are periodically reset by the regulator are excluded from the amounts above since future tolls remain unknown. Finally, revenues from contracts with customers which have an original expected duration of one year or less are excluded from the amounts above.
SIGNIFICANT JUDGMENTS MADE IN RECOGNIZING REVENUE
Long-Term Transportation Agreements
For long-term transportation agreements, significant judgments pertain to the period over which revenue is recognized and whether the agreement provides for make-up rights for the shippers. Transportation revenue earned from firm contracted capacity arrangements is recognized ratably over the contract period. Transportation revenue from interruptible or volumetric-based arrangements is recognized when services are performed.
Estimates of Variable Consideration
Revenue from arrangements subject to variable consideration is recognized only to the extent that it is probable that a significant reversal in the amount of cumulative revenue recognized will not occur when the uncertainty associated with the variable consideration is subsequently resolved. Uncertainties associated with variable consideration relate principally to differences between estimated and actual volumes and prices. These uncertainties are resolved each month when actual volumes are sold or transported and actual tolls and prices are determined.
Recognition and Measurement of Revenue
 
Liquids Pipelines

Gas Transmission and Midstream

Gas Distribution

Green Power and Transmission

Energy Services

Consolidated

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

 
 

 

 

 
Revenue from products transferred at a point in time1
—

298

20

—

—

318

Revenue from products and services transferred over time2
2,221

1,232

610

115

—

4,178

Total revenue from contracts with customers
2,221

1,530

630

115

—

4,496

 
Liquids Pipelines

Gas Transmission and Midstream

Gas Distribution

Green Power and Transmission

Energy Services

Consolidated

Nine months ended
September 30, 2018
(millions of Canadian dollars)
 

 
 

 

 

 
Revenue from products transferred at a point in time1
—

1,630

65

—

—

1,695

Revenue from products and services transferred over time2
6,440

3,689

3,855

417

—

14,401

Total revenue from contracts with customers
6,440

5,319

3,920

417

—

16,096

1 
Revenue from sales of crude oil, natural gas and NGLs.
2 
Revenue from crude oil and natural gas pipeline transportation, storage, natural gas gathering, compression and treating, natural gas distribution, natural gas storage services and electricity sales.

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

Performance Obligations Satisfied Over Time
For arrangements involving the transportation and sale of petroleum products and natural gas where the transportation services or commodities are simultaneously received and consumed by the shipper or customer, we recognize revenue over time using an output method based on volumes of commodities


18

delivered or transported. The measurement of the volumes transported or delivered corresponds directly to the benefits received by the shippers or customers during that period.

Determination of Transaction Prices
Prices for gas processing and transportation services are determined based on the capital cost of the facilities, pipelines and associated infrastructure required to provide such services plus a rate of return on capital invested that is determined either through negotiations with customers or through regulatory processes for those operations that are subject to rate regulation.
Prices for commodities sold are determined by reference to market price indices plus or minus a negotiated differential and in certain cases a marketing fee.
Prices for natural gas sold and distribution services provided by regulated natural gas distribution operations are prescribed by regulation.

4.
SEGMENTED INFORMATION

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

Gas Transmission and Midstream

Gas Distribution

Green Power and Transmission

Energy Services

Eliminations and Other

Consolidated

Three months ended
September 30, 2018
(millions of Canadian dollars)
 
 
 
 
 
 
 
Revenues
2,529

1,528

645

117

6,646

(120
)
11,345

Commodity and gas distribution costs
(5
)
(270
)
(137
)
—

(6,726
)
121

(7,017
)
Operating and administrative
(790
)
(519
)
(263
)
(38
)
(17
)
(25
)
(1,652
)
Asset impairment
—

—

—

(4
)
—

—

(4
)
Goodwill impairment
—

(1,019
)
—

—

—

—

(1,019
)
Income/(loss) from equity investments
131

262

(12
)
(6
)
3

—

378

Other income/(expense)
10

(42
)
23

(18
)
(2
)
53

24

Earnings/(loss) before interest, income taxes, and depreciation and amortization
1,875

(60
)
256

51

(96
)
29

2,055

Depreciation and amortization
 
 
 
 
 
 
(799
)
Interest expense
 

 

 

 

 

 

(696
)
Income tax expense
 

 

 

 

 

 

(347
)
Earnings
 
 
 
 
 
 
213

Capital expenditures1
651

413

311

6

—

(19
)
1,362




19

 
Liquids Pipelines

Gas Transmission and Midstream

Gas Distribution

Green Power and Transmission

Energy Services

Eliminations and Other

Consolidated

Three months ended
September 30, 2017
(millions of Canadian dollars)
 

 

 
 

 

 

 

Revenues
2,324

1,862

716

109

4,284

(68
)
9,227

Commodity and gas distribution costs
(5
)
(703
)
(242
)
1

(4,421
)
68

(5,302
)
Operating and administrative
(770
)
(498
)
(246
)
(42
)
(11
)
(20
)
(1,587
)
Income/(loss) from equity investments
118

162

(3
)
—

3

—

280

Other income/(expense)
36

33

15

—

(5
)
146

225

Earnings/(loss) before interest, income taxes, and depreciation and amortization
1,703

856

240

68

(150
)
126

2,843

Depreciation and amortization
 
 
 
 
 
 
(848
)
Interest expense
 

 

 

 

 

 

(653
)
Income tax expense
 

 

 

 

 

 

(327
)
Earnings












1,015

Capital expenditures1
529

1,052

302

64

—

22

1,969

 
Liquids Pipelines

Gas Transmission and Midstream

Gas Distribution

Green Power and Transmission

Energy Services

Eliminations and Other

Consolidated

Nine months ended
September 30, 2018
(millions of Canadian dollars)
 

 
 

 

 

 

 

Revenues
6,388

5,329

3,952

423

19,114

(390
)
34,816

Commodity and gas distribution costs
(14
)
(1,481
)
(1,969
)
—

(18,965
)
392

(22,037
)
Operating and administrative
(2,251
)
(1,560
)
(782
)
(104
)
(50
)
(182
)
(4,929
)
Asset impairment
(154
)
(913
)
—

(4
)
—

(5
)
(1,076
)
Goodwill impairment
—

(1,019
)
—

—

—

—

(1,019
)
Income/(loss) from equity investments
399

699

(5
)
(27
)
10

—

1,076

Other income/(expense)
(15
)
25

66

(2
)
(1
)
(183
)
(110
)
Earnings/(loss) before interest, income taxes, and depreciation and amortization
4,353

1,080

1,262

286

108

(368
)
6,721

Depreciation and amortization
 
 
 
 
 
 
(2,452
)
Interest expense
 

 

 

 

 

 

(2,042
)
Income tax expense
 

 

 

 

 

 

(177
)
Earnings
 
 

 

 

 

 

2,050

Capital expenditures1
1,776

2,105

733

30

—

(11
)
4,633

 
Liquids Pipelines

Gas Transmission and Midstream

Gas Distribution

Green Power and Transmission

Energy Services

Eliminations and Other

Consolidated

Nine months ended
September 30, 2017
(millions of Canadian dollars)
 

 
 

 

 

 

 

Revenues
6,722

5,051

3,322

386

16,272

(264
)
31,489

Commodity and gas distribution costs
(13
)
(2,053
)
(1,740
)
4

(16,251
)
268

(19,785
)
Operating and administrative
(2,214
)
(1,305
)
(676
)
(123
)
(34
)
(432
)
(4,784
)
Income from equity investments
312

427

10

2

5

(4
)
752

Other income/(expense)
33

143

21

1

(3
)
244

439

Earnings/(loss) before interest, income taxes, and depreciation and amortization
4,840

2,263

937

270

(11
)
(188
)
8,111

Depreciation and amortization
 
 
 
 
 
 
(2,388
)
Interest expense
 

 

 

 

 

 

(1,704
)
Income tax expense
 

 

 

 

 

 

(818
)
Earnings
 

 

 

 

 

 

3,201

Capital expenditures1
1,723

3,081

794

293

1

90

5,982

 
1 
Includes allowance for equity funds used during construction.


20

5.
EARNINGS PER COMMON SHARE
 
BASIC
Earnings per common share is calculated by dividing earnings attributable to common shareholders by the weighted average number of common shares outstanding. The weighted average number of common shares outstanding has been reduced by our pro-rata weighted average interest in our own common shares of 13 million for the three and nine months ended September 30, 2018 and 2017, resulting from our reciprocal investment in Noverco Inc.
 
DILUTED
The treasury stock method is used to determine the dilutive impact of stock options. This method assumes any proceeds from the exercise of stock options would be used to purchase common shares at the average market price during the period.

Weighted average shares outstanding used to calculate basic and diluted earnings per share are as follows:
 
Three months ended
September 30,
 
Nine months ended
September 30,
 
2018

2017

 
2018

2017

(number of common shares in millions)
 

 

 
 

 

Weighted average shares outstanding
1,705

1,635

 
1,695

1,482

Effect of dilutive options
3

7

 
4

8

Diluted weighted average shares outstanding
1,708

1,642


1,699

1,490


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

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

6.
ACQUISITIONS AND DISPOSITIONS

ASSETS HELD FOR SALE
Canadian Natural Gas Gathering and Processing Businesses
On July 4, 2018, we entered into agreements to sell our Canadian natural gas gathering and processing businesses to Brookfield Infrastructure Partners L.P. and its institutional partners for a cash purchase price of approximately $4.3 billion, subject to customary closing adjustments. Separate agreements were entered into for those facilities currently governed by provincial regulations and those governed by federal regulations (collectively, Canadian Natural Gas Gathering and Processing Businesses assets). On October 1, 2018, we closed the sale of the provincially regulated facilities for proceeds of approximately $2.5 billion. These assets were included within our Gas Transmission and Midstream segment. The sale of the federally regulated facilities is expected to close in mid-2019 for proceeds of approximately $1.8 billion.

During the third quarter of 2018, we classified the Canadian Natural Gas Gathering and Processing Businesses assets as held for sale. As these assets represented a portion of a reporting unit, we allocated a portion of the goodwill of the reporting unit to these assets using a relative fair value approach. As a result of the goodwill allocation, the carrying value of Canadian Natural Gas Gathering and Processing Businesses assets is greater than the sale price consideration less the cost to sell. Therefore, we recorded a goodwill impairment of $1,019 million on the Consolidated Statements of Earnings for the three and nine months ended September 30, 2018. Further, the held for sale


21

classification represented a triggering event and required us to perform a goodwill impairment test for the related reporting unit. The results of the test did not indicate any additional goodwill impairment.

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

We expect to close the sale of Line 10 within one year, subject to regulatory approval and certain closing conditions. As such, during the first quarter of 2018, we classified Line 10 assets as held for sale and measured them at the lower of their carrying value or fair value less costs to sell, which resulted in a loss of $154 million ($95 million after-tax attributable to us) included within Asset impairment on the Consolidated Statements of Earnings for the nine months ended September 30, 2018.

The table below summarizes the presentation of net assets held for sale in our Consolidated Statements of Financial Position:
 
September 30, 2018

December 31, 2017

(millions of Canadian dollars)
 

 
Accounts receivable and other (current assets held for sale)
154

424

Deferred amounts and other assets (long-term assets held for sale)1
4,841

1,190

Accounts payable and other (current liabilities held for sale)
(70
)
(315
)
Other long-term liabilities (long-term liabilities held for sale)2
(430
)
(34
)
Net assets held for sale
4,495

1,265

1
Included within Deferred amounts and other assets at September 30, 2018, is property, plant and equipment of $4.1 billion and goodwill of $482 million. Included within Deferred amounts and other assets at December 31, 2017, is property, plant and equipment of $1.1 billion.
2
Included within Other long-term liabilities at September 30, 2018 are deferred tax liabilities of $329 million.

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

A loss on disposal of $20 million (€14 million) was included in Other income/(expense) in the Consolidated Statements of Earnings for the sale of 49% of our interest in the Hohe See Offshore wind farm and its subsequent expansion. Subsequent to the sale, the remaining interests in these assets continue to be accounted for as an equity method investment, and are a part of our Green Power and Transmission segment.
 
Gains of $62 million and $17 million (US$13 million) were included in Additional paid-in capital in the Consolidated Statements of Financial Position for the sale of 49% interest in the Canadian and United States renewable assets, respectively. Subsequent to the sale, because we maintained a controlling interest, these assets continue to be consolidated and are a part of our Green Power and Transmission segment. In addition, we recognized noncontrolling interests in our Consolidated Statements of Financial Position as at September 30, 2018 to reflect the interests that we do not hold (Note 10).



22

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

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

Midcoast Operating, L.P.
On August 1, 2018, our indirect subsidiary, Enbridge (U.S.) Inc. closed the sale of Midcoast Operating, L.P. and its subsidiaries (collectively, MOLP) to AL Midcoast Holdings, LLC (an affiliate of ArcLight Capital Partners, LLC) for total cash proceeds of $1.4 billion (US$1.1 billion). A loss on disposal of $74 million (US$57 million) was included in Other income/(expense) in the Consolidated Statements of Earnings. MOLP conducted our United States natural gas and natural gas liquids gathering, processing, transportation and marketing businesses, and was a part of our Gas Transmission and Midstream segment.

Upon closing of the sale, we also recorded a liability of $387 million (US$298 million) for future volume commitments retained by us. The associated loss is included in the loss on disposal of $74 million discussed above. As at September 30, 2018, $75 million (US$58 million) and $306 million (US$237 million) were included in Accounts payable and other and Other long-term liabilities, respectively, on the Consolidated Statements of Financial Position.

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

In the first quarter of 2018, as a result of entering into a definitive sales agreement, the fair value of the assets held for sale as at March 31, 2018 were revised based on the sale price. Accordingly, we recorded a loss of $913 million ($701 million after-tax). This loss has been included within Asset impairment on the Consolidated Statements of Earnings for the nine months ended September 30, 2018.

7.
VARIABLE INTEREST ENTITIES

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


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

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


23


UNCONSOLIDATED VARIABLE INTEREST ENTITY
Enbridge Renewable Infrastructure Investments S.a.r.l. (ERII)
To facilitate the sale on August 1, 2018, we transferred our interest in the Hohe See Offshore wind farm and its subsequent expansion to a newly formed partnership, ERII. Subsequently, a 49% interest in ERII was sold to CPPIB. ERII is a VIE due to insufficient equity at risk to finance its activities. We are not the primary beneficiary of ERII since the power to direct the activities of ERII that most significantly impact its economic performance is shared. We account for ERII by using the equity method as we retain significant influence through a 51% voting interest in substantive decisions.

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

OTHER
Sabal Trail Transmission, LLC
Spectra Energy Partners, LP (SEP) owns a 50% interest in Sabal Trail Transmission, LLC (Sabal Trail), a joint venture that operates a pipeline originating in Alabama that transports natural gas to Florida and has been classified as a variable interest entity.

On April 30, 2018, Sabal Trail issued US$500 million in aggregate principal amount of 4.246% senior notes due in 2028, US$600 million in aggregate principal amount of 4.682% senior notes due in 2038 and US$400 million in aggregate principal amount of 4.832% senior notes due in 2048. Sabal Trail distributed net proceeds from the offering to the members as a partial reimbursement of construction and development costs incurred by the members. The net distribution made to SEP was US$744 million and was used to pay down indebtedness and is included within Distributions from equity investments in excess of cumulative earnings on the Consolidated Statement of Cash Flows for the nine months ended September 30, 2018. These events triggered reconsideration and as a result, it was concluded that Sabal Trail was no longer a VIE as at June 30, 2018 due to sufficient equity at risk to finance its activities.

8.
DEBT

CREDIT FACILITIES
The following table provides details of our committed credit facilities as at September 30, 2018:
 
 
 
 
September 30, 2018
 
Maturity
Total
Facilities

Draws1

Available

(millions of Canadian dollars)
 
 
 
 
Enbridge Inc.
2019-2023
5,602

2,330

3,272

Enbridge (U.S.) Inc.
2019
1,829

—

1,829

Enbridge Energy Partners, L.P.2
2019-2022
3,167

2,210

957

Enbridge Gas Distribution Inc. (EGD)
2019-2020
1,017

779

238

Enbridge Income Fund
2020
1,500

9

1,491

Enbridge Pipelines Inc.
2020
3,000

1,214

1,786

Spectra Energy Partners, LP3
2022
3,232

2,153

1,079

Union Gas Limited (Union Gas)
2021
700

481

219

Total committed credit facilities
 
20,047

9,176

10,871

 
1
Includes facility draws, letters of credit and commercial paper issuances that are back-stopped by credit facilities.
2
Includes $239 million (US$185 million) of commitments that expire in 2020.
3
Includes $435 million (US$336 million) of commitments that expire in 2021.


24


During the second quarter of 2018, Enbridge (U.S.) Inc. terminated a US$500 million credit facility, which was scheduled to mature in 2019, and repaid drawn amounts. In addition, an unutilized Enbridge US$100 million credit facility expired.

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

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

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

Our credit facilities carry a weighted average standby fee of 0.2% per annum on the unused portion and draws bear interest at market rates. Certain credit facilities serve as a back-stop to the commercial paper programs and we have the option to extend such facilities, which are currently scheduled to mature from 2019 to 2023.

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

LONG-TERM DEBT ISSUANCES
During the nine months ended September 30, 2018, we completed the following long-term debt issuances:
Company
Issue Date
 
 
Principal Amount
(millions of Canadian dollars, unless otherwise stated)
 
 
Enbridge Inc.
 
 
 
 
March 2018
Fixed-to-floating rate subordinated notes due 20781
  US$850
 
April 2018
Fixed-to-floating rate subordinated notes due 20782
$750
 
April 2018
Fixed-to-floating rate subordinated notes due 20783
  US$600
Spectra Energy Partners, LP4
 
 
 
 
January 2018
3.50% senior notes due 2028
  US$400
 
January 2018
4.15% senior notes due 2048
US$400
1
Notes mature in 60 years and are callable on or after year 10. For the initial 10 years, the notes carry a fixed interest rate of 6.25%. Subsequently, the interest rate will be set to equal the three-month London Interbank Offered Rate (LIBOR) plus a margin of 364 basis points from years 10 to 30, and a margin of 439 basis points from years 30 to 60.
2
Notes mature in 60 years and are callable on or after year 10. For the initial 10 years, the notes carry a fixed interest rate of 6.625%. Subsequently, the interest rate will be set to equal the Canadian Dollar Offered Rate plus a margin of 432 basis points from years 10 to 30, and a margin of 507 basis points from years 30 to 60.
3
Notes mature in 60 years and are callable on or after year five. For the initial five years, the notes carry a fixed interest rate of 6.375%. Subsequently, the interest rate will be set to equal the three-month LIBOR plus a margin of 359 basis points from years five to 10, a margin of 384 basis points from years 10 to 25, and a margin of 459 basis points from years 25 to 60.
4
Issued through Texas Eastern Transmission, LP, a wholly-owned operating subsidiary of SEP.



25

LONG-TERM DEBT REPAYMENTS
During the nine months ended September 30, 2018, we completed the following long-term debt repayments:
Company
Retirement/Repayment Date
 
 
Principal Amount
Cash Consideration1
(millions of Canadian dollars, unless otherwise stated)
 
 
 
Enbridge Energy Partners, L.P.
 
 
 
 
April 2018
6.50% senior notes
US$400
 
Enbridge Pipelines (Southern Lights) L.L.C
 
 
 
 
 
June 2018
3.98% medium-term notes due June 2040
US$20
 
Enbridge Southern Lights LP
 
 
 
 
 
January 2018
4.01% medium-term notes due June 2040
$9
 
 
July 2018
4.01% medium-term notes due June 2040
$8
 
Midcoast Energy Partners, L.P.
 
 
 
 
Redemption2
 
 
 
 
 
July 2018
3.56% senior notes due September 2019
US$75
US$76
 
July 2018
4.04% senior notes due September 2021
US$175
US$182
 
July 2018
4.42% senior notes due September 2024
US$150
US$161
Spectra Energy Capital, LLC
 
 
 
 
Repurchase via Tender Offer2
 
 
 
 
 
March 2018
6.75% senior unsecured notes due 2032
US$64
US$80
 
March 2018
7.50% senior unsecured notes due 2038
US$43
US$59
Redemption2
 
 
 
 
March 2018
5.65% senior unsecured notes due 2020
US$163
US$172
 
March 2018
3.30% senior unsecured notes due 2023
US$498
US$508
Repayment
 
 
 
 
 
April 2018
6.20% senior notes
US$272
 
 
July 2018
6.75% senior notes
 
US$118
 
Spectra Energy Partners, LP
 
 
 
 
 
September 2018
2.95% senior notes
 
US$500
 
Union Gas Limited
 
 
 
 
 
April 2018
5.35% medium-term notes
$200
 
 
August 2018
8.75% debenture
 
$125
 
Westcoast Energy Inc.
 
 
 
 
 
May 2018
6.90% senior secured notes
$13
 
 
May 2018
4.34% senior secured notes
$4
 
 
September 2018
8.50% debenture
 
$150
 
1
Cash consideration disclosed for repayments where the cash paid differs from the principal amount.
2
The loss on debt extinguishment of $64 million (US$50 million), net of a fair value adjustment recorded upon completion of the Merger Transaction, was reported within Interest expense in the Consolidated Statements of Earnings.

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

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

DEBT COVENANTS
Our credit facility agreements and term debt indentures include standard events of default and covenant provisions whereby accelerated repayment and/or termination of the agreements may result if we were to default on payment or violate certain covenants. As at September 30, 2018, we were in compliance with all debt covenants.


26


9.
COMPONENTS OF ACCUMULATED OTHER COMPREHENSIVE INCOME
 
Changes in AOCI attributable to our common shareholders for the nine months ended September 30, 2018 and 2017 are as follows:
 
Cash Flow 
Hedges

Net
Investment
Hedges

Cumulative
Translation
Adjustment

Equity
Investees

Pension and
OPEB
Adjustment

Total

(millions of Canadian dollars)
 
 
 
 
 
 
Balance as at January 1, 2018
(644
)
(139
)
77

10

(277
)
(973
)
Other comprehensive income/(loss) retained in AOCI
167

(232
)
1,495

(8
)
—

1,422

Other comprehensive (income)/loss reclassified to earnings
 
 
 
 
 


Interest rate contracts1
92

—

—

—

—

92

Commodity contracts2
(1
)
—

—

—

—

(1
)
Foreign exchange contracts3
6

—

—

—

—

6

Other contracts4
10

—

—

—

—

10

Amortization of pension and OPEB actuarial loss and prior service costs5
—

—

—

—

36

36

 
274

(232
)
1,495

(8
)
36

1,565

Tax impact
 

 

 

 

 

 

Income tax on amounts retained in AOCI
(26
)
32

—

9

—

15

Income tax on amounts reclassified to earnings
(29
)
—

—

—

(8
)
(37
)
 
(55
)
32

—

9

(8
)
(22
)
Balance as at September 30, 2018
(425
)
(339
)
1,572

11

(249
)
570

 
Cash Flow
Hedges

Net
Investment
Hedges

Cumulative
Translation
Adjustment

Equity
Investees

Pension and
OPEB
Adjustment

Total

(millions of Canadian dollars)
 
 
 
 
 
 
Balance as at January 1, 2017
(746
)
(629
)
2,700

37

(304
)
1,058

Other comprehensive income/(loss) retained in AOCI
29

496

(2,616
)
(4
)
—

(2,095
)
Other comprehensive (income)/loss reclassified to earnings
 
 
 
 
 


Interest rate contracts1
104

—

—

—

—

104

Commodity contracts2
(5
)
—

—

—

—

(5
)
Foreign exchange contracts3
(2
)
—

—

—

—

(2
)
Other contracts4
(3
)
—

—

—

—

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

—

—

—

—

21

21

 
123

496

(2,616
)
(4
)
21

(1,980
)
Tax impact
 
 
 
 
 
 
Income tax on amounts retained in AOCI
(9
)
9

—

13

—

13

Income tax on amounts reclassified to earnings
(34
)
—

—

—

(8
)
(42
)
 
(43
)
9

—

13

(8
)
(29
)
Balance as at September 30, 2017
(666
)
(124
)
84

46

(291
)
(951
)
 
1
Reported within Interest expense in the Consolidated Statements of Earnings.
2
Reported within Commodity costs in the Consolidated Statements of Earnings.
3
Reported within Other income/(expense) in the Consolidated Statements of Earnings.
4
Reported within Operating and administrative expense in the Consolidated Statements of Earnings.
5
These components are included in the computation of net periodic benefit costs and are reported within Other income/(expense) in the Consolidated Statements of Earnings.



27

10. NONCONTROLLING INTERESTS
 
Renewable Assets
On August 1, 2018, we closed the sale of a 49% interest in all of our Canadian renewable assets and a 49% interest in two United States renewable assets to CPPIB (Note 6). As a result, we recorded an increase in Noncontrolling interests, Additional paid-in capital and Deferred income tax liabilities of $1,183 million, $79 million and $27 million, respectively, for the nine months ended September 30, 2018. For the three months ended September 30, 2018, CPPIB's distributions and allocation of earnings were not proportionate to its ownership.

SEP Incentive Distribution Rights
As at December 31, 2017, we collectively owned a 75% ownership interest in SEP, together with 100% of SEP's incentive distribution rights (IDRs). On January 22, 2018, Enbridge and SEP announced the execution of a definitive agreement, resulting in us converting all of our IDRs and general partner economic interests in SEP into 172.5 million newly issued SEP common units. As part of the transaction, all of the IDRs were eliminated. We now hold a non-economic general partner interest in SEP and own approximately 403 million SEP common units, representing approximately 83% of SEP's outstanding common units. As a result of this restructuring, we recorded a decrease in Noncontrolling interests of $1.5 billion and increases in Additional paid-in capital and Deferred income tax liabilities of $1.1 billion and $333 million, respectively, for the nine months ended September 30, 2018.

11. RISK MANAGEMENT AND FINANCIAL INSTRUMENTS

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

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

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

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

Interest Rate Risk
Our earnings and cash flows are exposed to short-term interest rate variability due to the regular repricing of our variable rate debt, primarily commercial paper. Pay fixed-receive floating interest rate swaps are used to hedge against the effect of future interest rate movements. We have implemented a program to significantly mitigate the impact of short-term interest rate volatility on interest expense via execution of floating to fixed interest rate swaps with an average swap rate of 2.6%.


28


As a result of the Merger Transaction, we are exposed to changes in the fair value of fixed rate debt that arise as a result of the changes in market interest rates. Pay floating-receive fixed interest rate swaps are used to hedge against future changes to the fair value of fixed rate debt. We have assumed a program within our subsidiaries to mitigate the impact of fluctuations in the fair value of fixed rate debt via execution of fixed to floating interest rate swaps with an average swap rate of 2.2%.

Our earnings and cash flows are also exposed to variability in longer term interest rates ahead of anticipated fixed rate term debt issuances. Forward starting interest rate swaps are used to hedge against the effect of future interest rate movements. We have assumed a program within some of our subsidiaries to mitigate our exposure to long-term interest rate variability on select forecast term debt issuances via execution of floating to fixed interest rate swaps with an average swap rate of 3.1%.

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

Commodity Price Risk
Our earnings and cash flows are exposed to changes in commodity prices as a result of our ownership interests in certain assets and investments, as well as through the activities of our energy services subsidiaries. These commodities include natural gas, crude oil, power and NGL. We employ financial and physical derivative instruments to fix a portion of the variable price exposures that arise from physical transactions involving these commodities. We use primarily non-qualifying derivative instruments to manage commodity price risk.

Emission Allowance Price Risk
Emission allowance price risk is the risk of gain or loss due to changes in the market price of emission allowances that our gas distribution business has been required to purchase for itself and most of its customers to meet greenhouse gas compliance obligations under the Ontario Cap and Trade program. Similar to the gas supply procurement framework, the Ontario Energy Board's (OEB) framework for emission allowance procurement allows recovery of fluctuations in emission allowance prices in customer rates, subject to OEB approval.
 
Equity Price Risk
Equity price risk is the risk of earnings fluctuations due to changes in our share price. We have exposure to our own common share price through the issuance of various forms of stock-based compensation, which affect earnings through revaluation of the outstanding units every period. We use equity derivatives to manage the earnings volatility derived from one form of stock-based compensation, restricted share units. We use a combination of qualifying and non-qualifying derivative instruments to manage equity price risk.

TOTAL DERIVATIVE INSTRUMENTS
The following table summarizes the Consolidated Statements of Financial Position location and carrying value of our derivative instruments.

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



29

September 30, 2018
Derivative
Instruments
Used as
Cash Flow Hedges

Derivative
Instruments
Used as Net
Investment Hedges

Derivative
Instruments
Used as
Fair Value Hedges

Non-
Qualifying
Derivative Instruments

Total Gross
Derivative
Instruments as Presented

Amounts
Available for Offset

Total Net
Derivative Instruments

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

1

—

66

67

(49
)
18

Interest rate contracts
49

—

—

—

49

(3
)
46

Commodity contracts
1

—

—

119

120

(85
)
35

 
50

1

—

185

236

(137
)
99

Deferred amounts and other assets
 
 
 
 
 
 
 
Foreign exchange contracts
4

—

—

39

43

(29
)
14

Interest rate contracts
42

—

—

—

42

(1
)
41

Commodity contracts
18

—

—

12

30

(25
)
5

Other contracts
—

—

—

—

—

—

—

 
64

—

—

51

115

(55
)
60

Accounts payable and other
 
 
 
 
 
 
 
Foreign exchange contracts
(5
)
—

—

(371
)
(376
)
49

(327
)
Interest rate contracts
(50
)
—

(9
)
(179
)
(238
)
3

(235
)
Commodity contracts
—

—

—

(411
)
(411
)
85

(326
)
Other contracts
(1
)
—

—

(8
)
(9
)
—

(9
)
 
(56
)
—

(9
)
(969
)
(1,034
)
137

(897
)
Other long-term liabilities
 
 
 
 
 
 
 
Foreign exchange contracts
—

(11
)
—

(1,420
)
(1,431
)
29