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 September 30, ~~2019~~2020



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

For the transition period from to

Commission file number 1-10934




ENBRIDGE ~~INC~~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

Accelerated filer

☐

Non-accelerated filer

☐

Smaller reporting company

☐

Emerging growth company

☐

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

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

The registrant had ~~2,023,924,736~~2,025,219,063 common shares outstanding as at ~~November 1, 2019.~~

October 30, 2020.

	~~Page~~
		~~PART I~~	Page
		PART I
Item 1.		Financial Statements	6
Item 2.		Management’s Discussion and Analysis of Financial Condition and Results of Operations	5239
Item 3.		Quantitative and Qualitative Disclosures About Market Risk	7365
Item 4.		Controls and Procedures	7465
		PART II
Item 1.		Legal Proceedings	7566
Item 1A.		Risk Factors	7566
Item 2.		Unregistered Sales of Equity Securities and Use of Proceeds	7569
Item 3.		Defaults Upon Senior Securities	7569
Item 4.		Mine Safety Disclosures	7569
Item 5.		Other Information	7569
Item 6.		Exhibits	7669
		Signatures	7770

GLOSSARY



AOCI
~~AOCI~~	Accumulated other comprehensive income/(loss)
Army Corps		United States Army Corps of Engineers
ASC		Accounting Standards Codification
ASU		Accounting Standards Update
~~CER~~		~~The~~

Average Exchange Rate		Canadian ~~Regulator Act created the new~~ to United States dollar average exchange rate
CER		Canada Energy Regulator ~~and repealed the National Energy Board Act, on August 28, 2019~~
~~EBITDA~~CPP Investments		Canada Pension Plan Investment Board
DCP Midstream		DCP Midstream, LLC
EBITDA		Earnings before interest, income taxes and depreciation and amortization
~~EEP~~
EEP		Enbridge Energy Partners, L.P.
~~Enbridge~~		~~Enbridge Inc.~~
~~Merger Transaction~~		~~Combination of Enbridge and Spectra Energy through a stock-for-stock merger transaction which closed on February 27, 2017~~
~~MNPUC~~EMF		~~Minnesota Public Utilities Commission~~Éolien Maritime France SAS
~~MOLP~~Enbridge		~~Midcoast Operating, L.P. and its subsidiaries~~Enbridge Inc.
~~NGL~~

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~~SEP		Spectra Energy Partners, LP
OCI		Other comprehensive income/(loss)
~~VIE~~		~~Variable Interest Entity~~






Texas Eastern		Texas Eastern Transmission, LP

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 ~~earnings/(loss) per share; expected~~ future cash flows; expected ~~performance of the Liquids Pipelines, Gas Transmission and Midstream, Gas Distribution, Renewable Power Generation and Transmission, and Energy Services businesses;~~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 ~~expected~~the timing thereof;~~estimated future dividends;~~ expected benefits of transactions, including the realization of efficiencies and synergies; expected future actions of regulators and related court ~~proceedings; expected costs related to leak remediation~~proceedings and potential insurance recoveries; expectations regarding commodity prices; supply forecasts; expectations regarding the impact of the stock-for-stock merger transaction completed on February 27, 2017 between Enbridge and Spectra Energy Corp (the Merger Transaction) including our combined scale, financial flexibility, growth program, future business prospects and performance;other litigation; anticipated competition; United States Line 3 Replacement Program (U.S. L3R Program); ~~the expected in-service date of the Canadian Line 3 Replacement Program (Canadian L3R Program);~~ Line 5 related matters; ~~Mainline System contracting; expected impact~~the status of the ~~Federal Energy Regulatory Commission (FERC) policy on treatment of income taxes; the transactions undertaken to simplify our corporate structure;~~Dakota Access Pipeline; estimated future dividends; our dividend payout policy; dividend growth and dividend payout expectation; and expectations on impact of our hedging ~~program; and expectations resulting from the successful execution of our 2018-2020 Strategic Plan.~~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 ~~assumptions about~~ 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;~~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 ~~the Merger Transaction;~~transactions; governmental legislation; ~~acquisitions and the timing thereof; the success of integration plans;~~ impact of ~~the~~our dividend policy on our future cash flows; our credit ratings; capital project funding; expected EBITDA; expected earnings/(loss); expected ~~earnings/(loss) per share; expected~~ future cash ~~flows~~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 ~~the impact of the Merger Transaction on us,~~expected EBITDA, expected earnings/(loss), expected ~~earnings/(loss) per share,~~future cash flows, expected distributable cash flow or estimated future dividends.

The most relevant assumptions associated with forward-looking statements ~~regarding~~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.~~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 ~~realization~~successful execution of ~~anticipated benefits and synergies of the Merger Transaction,~~our strategic priorities, operating performance, regulatory parameters, changes in regulations applicable to our business, acquisitions, dispositions ~~the~~and other transactions, ~~undertaken to simplify our corporate structure,~~ our dividend policy, project approval and support, renewals of rights-of-way, weather, economic and competitive conditions, public opinion, changes in tax laws and tax rates, changes in trade agreements, exchange rates, interest rates, commodity prices,political decisions, ~~and~~ supply of and demand for commodities, 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 ~~statements~~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.

PART I - FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

ENBRIDGE INC.

CONSOLIDATED STATEMENTS OF EARNINGS


	Three months ended September 30,				Nine months ended September 30,					Three months ended September 30,		Nine months ended September 30,
	2019		2018		2019		2018			2020	2019	2020	2019
(unaudited; millions of Canadian dollars, except per share amounts)									(unaudited; millions of Canadian dollars, except per share amounts)
Operating revenues									Operating revenues
Commodity sales	7,396		6,919		22,444		20,638		Commodity sales	4,595	7,396	14,920	22,444
Transportation and other services									Transportation and other services	4,075	3,748	11,609	12,188
Gas distribution sales	454		478		3,085		3,260		Gas distribution sales	440	454	2,550	3,085
Transportation and other services	3,748		3,948		12,188		10,918
Total operating revenues (Note 3)	11,598		11,345		37,717		34,816		Total operating revenues (Note 3)	9,110	11,598	29,079	37,717
Operating expenses									Operating expenses
Commodity costs	7,216		6,905		21,910		20,180		Commodity costs	4,443	7,216	14,464	21,910
Gas distribution costs	104		112		1,623		1,857		Gas distribution costs	83	104	1,188	1,623
Operating and administrative	1,741		1,652		5,061		4,929		Operating and administrative	1,554	1,741	4,955	5,061
Depreciation and amortization	844		799		2,526		2,452		Depreciation and amortization	935	844	2,766	2,526
Impairment of long-lived assets	105		4		105		1,076		Impairment of long-lived assets	0	105	0	105
Impairment of goodwill	—		1,019		—		1,019
Total operating expenses	10,010		10,491		31,225		31,513		Total operating expenses	7,015	10,010	23,373	31,225
Operating income	1,588		854		6,492		3,303		Operating income	2,095	1,588	5,706	6,492
Income from equity investments	333		378		1,159		1,076		Income from equity investments	315	333	805	1,159
Impairment of equity investments (Note 9)									Impairment of equity investments (Note 9)	(615)	0	(2,351)	0
Other income/(expense)									Other income/(expense)
Net foreign currency (loss)/gain	(43	)	57		311		(171	)
Net foreign currency gain/(loss)									Net foreign currency gain/(loss)	173	(43)	(257)	311
Other	81		(33	)	192		61		Other	85	81	(8)	192
Interest expense	(644	)	(696	)	(1,966	)	(2,042	)	Interest expense	(718)	(644)	(2,105)	(1,966)
Earnings before income taxes	1,315		560		6,188		2,227		Earnings before income taxes	1,335	1,315	1,790	6,188
Income tax expense (Note 12)	(255	)	(347	)	(1,275	)	(177	)
Income tax expense (Note 11)									Income tax expense (Note 11)	(231)	(255)	(273)	(1,275)
Earnings	1,060		213		4,913		2,050		Earnings	1,104	1,060	1,517	4,913
Earnings attributable to noncontrolling interests and redeemable noncontrolling interests	(15	)	(209	)	(50	)	(352	)
Earnings attributable to noncontrolling interests									Earnings attributable to noncontrolling interests	(20)	(15)	(25)	(50)
Earnings attributable to controlling interests	1,045		4		4,863		1,698		Earnings attributable to controlling interests	1,084	1,045	1,492	4,863
Preference share dividends	(96	)	(94	)	(287	)	(272	)	Preference share dividends	(94)	(96)	(284)	(287)
Earnings/(loss) attributable to common shareholders	949		(90	)	4,576		1,426
Earnings/(loss) per common share attributable to common shareholders (Note 5)	0.47		(0.05	)	2.27		0.84
Diluted earnings/(loss) per common share attributable to common shareholders (Note 5)	0.47		(0.05	)	2.27		0.84
Earnings attributable to common shareholders									Earnings attributable to common shareholders	990	949	1,208	4,576
Earnings per common share attributable to common shareholders (Note 5)									Earnings per common share attributable to common shareholders (Note 5)	0.49	0.47	0.60	2.27
Diluted earnings per common share attributable to common shareholders (Note 5)									Diluted earnings per common share attributable to common shareholders (Note 5)	0.49	0.47	0.60	2.27

See accompanying notes to the interim consolidated financial statements.

ENBRIDGE INC.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME


	Three months ended September 30,				Nine months ended September 30,					Three months ended September 30,		Nine months ended September 30,
	2019		2018		2019		2018			2020	2019	2020	2019
(unaudited; millions of Canadian dollars)									(unaudited; millions of Canadian dollars)
Earnings	1,060		213		4,913		2,050		Earnings	1,104	1,060	1,517	4,913
Other comprehensive income/(loss), net of tax									Other comprehensive income/(loss), net of tax
Change in unrealized gain/(loss) on cash flow hedges	(170	)	57		(597	)	150		Change in unrealized gain/(loss) on cash flow hedges	29	(170)	(532)	(597)
Change in unrealized gain/(loss) on net investment hedges	(74	)	83		147		(200	)	Change in unrealized gain/(loss) on net investment hedges	154	(74)	(221)	147
Other comprehensive income from equity investees	2		(1	)	19		18
Other comprehensive income/(loss) from equity investees									Other comprehensive income/(loss) from equity investees	(14)	2	6	19
Excluded components of fair value hedges									Excluded components of fair value hedges	(1)	0	7	0
Reclassification to earnings of loss on cash flow hedges	28		31		74		104		Reclassification to earnings of loss on cash flow hedges	58	28	138	74
Reclassification to earnings of pension and other postretirement benefits (OPEB) amounts	1		5		44		28
Reclassification to earnings of pension and other postretirement benefits amounts									Reclassification to earnings of pension and other postretirement benefits amounts	3	1	10	44
Foreign currency translation adjustments	704		(989	)	(1,898	)	1,637		Foreign currency translation adjustments	(1,119)	704	1,817	(1,898)
Other comprehensive income/(loss), net of tax	491		(814	)	(2,211	)	1,737		Other comprehensive income/(loss), net of tax	(890)	491	1,225	(2,211)
Comprehensive income/(loss)	1,551		(601	)	2,702		3,787
Comprehensive (income)/loss attributable to noncontrolling interests and redeemable noncontrolling interests	(41	)	(102	)	23		(546	)
Comprehensive income/(loss) attributable to controlling interests	1,510		(703	)	2,725		3,241
Comprehensive income									Comprehensive income	214	1,551	2,742	2,702
Comprehensive (income)/loss attributable to noncontrolling interests									Comprehensive (income)/loss attributable to noncontrolling interests	16	(41)	(79)	23
Comprehensive income attributable to controlling interests									Comprehensive income attributable to controlling interests	230	1,510	2,663	2,725
Preference share dividends	(96	)	(94	)	(287	)	(272	)	Preference share dividends	(94)	(96)	(284)	(287)
Comprehensive income/(loss) attributable to common shareholders	1,414		(797	)	2,438		2,969
Comprehensive income attributable to common shareholders									Comprehensive income attributable to common shareholders	136	1,414	2,379	2,438

~~10.~~ ~~NONCONTROLLING INTERESTS~~9. IMPAIRMENT OF EQUITY INVESTMENTS

~~Preferred Shares Redemption~~Steckman Ridge, LP

~~On March 20,~~Steckman Ridge, LP (Steckman) is engaged in the storage of natural gas, is owned 50% by Enbridge, and is recorded as an equity method investment. During the quarter, Steckman’s forecasted performance was adjusted for the expectation that future available capacity will be re-contracted at lower than expected rates and an other than temporary impairment loss on our investment of $221 million for the three and nine months ended September 30, 2020 was recorded based on a discounted cash flow analysis. The carrying value of this investment as at September 30, 2020 and December 31, 2019 ~~Westcoast Energy Inc. exercised its right~~was $96 million and $222 million, respectively.

Southeast Supply Header, L.L.C.

Southeast Supply Header, L.L.C. (SESH) provides natural gas transmission services from east Texas and northern Louisiana to ~~redeem all~~the southeast markets of ~~its outstanding 5.5% Cumulative Redeemable First Preferred Shares, Series 7 (Series 7 Shares)~~the Gulf Coast. SESH is owned 50% by Enbridge and ~~all~~is recorded as an equity method investment. The forecasted performance of ~~its outstanding 5.6% Cumulative Redeemable First Preferred Shares, Series 8 (Series 8 Shares)~~SESH was revised this quarter to reflect downward revisions to future negotiated rates as well as higher than expected available capacity levels, caused primarily by a significant contract expiry. An other than temporary impairment loss on our investment of $394 million for the three and nine months ended September 30, 2020 was recorded based on a discounted cash flow analysis. The carrying value of this investment as at September 30, 2020 and December 31, 2019 was $87 million and $484 million, respectively.

DCP Midstream, LLC

DCP Midstream, LLC (DCP Midstream), a 50% owned equity method investment of Enbridge, holds an equity interest in DCP Midstream, LP. A decline in the market price of ~~$25.00 per Series 7 Share~~DCP Midstream, LP’s publicly traded units during the first quarter of 2020 resulted in an other than temporary impairment loss on our investment in DCP Midstream of NaN and ~~$25.00 per Series 8 Share, respectively,~~$1.7 billion for ~~a total payment of $300 million.~~the three and nine months ended September 30, 2020, respectively. In addition, ~~payment~~we incurred losses of $4$324 million through our equity earnings pick up in relation to asset and goodwill impairment losses recorded by DCP Midstream, LP. The carrying value of our investment in DCP Midstream as at September 30, 2020 and December 31, 2019 was ~~made for all accrued~~$340 million and ~~unpaid dividends. As a result, we recorded a $300 million decrease in Noncontrolling interests.~~

$2.2 billion, respectively.

~~11.~~

Our investments in Steckman, SESH, and DCP Midstream form part of our Gas Transmission and Midstream segment. The impairment losses were recorded within Impairment of Equity Investments in the Consolidated Statements of Earnings.

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%~~3.0%.

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 September 30, ~~2019,~~2020, we do not have any pay floating-receive fixed interest rate swaps outstanding.

Our earnings and cash flows are also exposed to variability in longer term interest rates ahead of anticipated fixed rate term debt issuances. Forward starting interest rate swaps are used to hedge against the effect of future interest rate movements. We have established a program within some of our subsidiaries to mitigate our exposure to long-term interest rate variability on select forecast term debt issuances via execution of floating to fixed interest rate swaps with an average swap rate of ~~3.1%~~2.3%.

We also monitor our debt portfolio mix of fixed and variable rate debt instruments to manage a consolidated portfolio of floating rate debt within the Board of Directors approved policy limit of a maximum of 30% of floating rate debt as a percentage of total debt outstanding. We primarily use qualifying derivative instruments to manage interest rate risk.

Commodity Price Risk

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

Equity Price Risk

Equity price risk is the risk of earnings fluctuations due to changes in our share price. We have exposure to our own common share price through the issuance of various forms of stock-based compensation, which affect earnings through revaluation of the outstanding units every period. We use equity derivatives to manage the earnings volatility derived from 1 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.

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.

September 30, 2019
Derivative
Instruments
Used as
Cash Flow Hedges

Derivative
Instruments
Used as Net
Investment Hedges

Non-
Qualifying
Derivative Instruments

Total Gross
Derivative
Instruments as Presented

Amounts
Available for Offset

Total Net
Derivative Instruments

(millions of Canadian dollars)
Accounts receivable and other
Foreign exchange contracts —
—
76
76
(66 ) 10
Interest rate contracts 1
—
—
1
—
1
Commodity contracts —
—
185
185
(41 ) 144
1
—
261
262
(107 ) 155
Deferred amounts and other assets
Foreign exchange contracts 17
—
123
140
(62 ) 78
Commodity contracts —
—
35
35
(7 ) 28
Other contracts 1
—
1
2
(1 ) 1
18
—
159
177
(70 ) 107
Accounts payable and other
Foreign exchange contracts (5 ) (14 ) (534 ) (553 ) 66
(487 )
Interest rate contracts (258 ) —
—
(258 ) —
(258 )
Commodity contracts —
—
(140 ) (140 ) 41
(99 )
Other Contracts —
—
(1 ) (1 ) —
(1 )
(263 ) (14 ) (675 ) (952 ) 107
(845 )
Other long-term liabilities
Foreign exchange contracts —
—
(1,536 ) (1,536 ) 62
(1,474 )
Interest rate contracts (686 ) —
—
(686 ) —
(686 )
Commodity contracts (1 ) —
(97 ) (98 ) 7
(91 )
Other contracts (1 ) —
(1 ) (2 ) 1
(1 )
(688 ) —
(1,634 ) (2,322 ) 70
(2,252 )
Total net derivative asset/(liability)
Foreign exchange contracts 12
(14 ) (1,871 ) (1,873 ) —
(1,873 )
Interest rate contracts (943 ) —
—
(943 ) —
(943 )
Commodity contracts (1 ) —
(17 ) (18 ) —
(18 )
Other contracts —
—
(1 ) (1 ) —
(1 )
(932 ) (14 ) (1,889 ) (2,835 ) —
(2,835 )

December 31, 2018
Derivative
Instruments
Used as
Cash Flow Hedges

Derivative
Instruments
Used as Net
Investment Hedges

Non-
Qualifying
Derivative Instruments

Total Gross
Derivative
Instruments as Presented

Amounts
Available for Offset

Total Net
Derivative Instruments

(millions of Canadian dollars)
Accounts receivable and other
Foreign exchange contracts —
—
47
47
(37 ) 10
Interest rate contracts 22
—
—
22
(2 ) 20
Commodity contracts 2
—
427
429
(114 ) 315
24
—
474
498
(153 ) 345
Deferred amounts and other assets
Foreign exchange contracts 23
—
39
62
(39 ) 23
Interest rate contracts 5
—
—
5
—
5
Commodity contracts 19
—
33
52
(21 ) 31
47
—
72
119
(60 ) 59
Accounts payable and other
Foreign exchange contracts (5 ) —
(610 ) (615 ) 37
(578 )
Interest rate contracts (163 ) —
(178 ) (341 ) 2
(339 )
Commodity contracts —
—
(273 ) (273 ) 114
(159 )
Other contracts (1 ) —
(4 ) (5 ) —
(5 )
(169 ) —
(1,065 ) (1,234 ) 153
(1,081 )
Other long-term liabilities
Foreign exchange contracts (1 ) (15 ) (2,196 ) (2,212 ) 39
(2,173 )
Interest rate contracts (201 ) —
—
(201 ) —
(201 )
Commodity contracts —
—
(178 ) (178 ) 21
(157 )
Other contracts (1 ) —
(1 ) (2 ) —
(2 )
(203 ) (15 ) (2,375 ) (2,593 ) 60
(2,533 )
Total net derivative asset/(liability)
Foreign exchange contracts 17
(15 ) (2,720 ) (2,718 ) —
(2,718 )
Interest rate contracts (337 ) —
(178 ) (515 ) —
(515 )
Commodity contracts 21
—
9
30
—
30
Other contracts (2 ) —
(5 ) (7 ) —
(7 )
(301 ) (15 ) (2,894 ) (3,210 ) —
(3,210 )


September 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	0	0	4	52	56		(23)	33

Commodity contracts	1	0	0	158	159		(82)	77
	1	0	4	210	215	1	(105)	110
Deferred amounts and other assets
Foreign exchange contracts	19	0	23	184	226		(111)	115
Interest rate contracts	8	0	0	0	8		(3)	5
Commodity contracts	2	0	0	64	66		(29)	37

	29	0	23	248	300		(143)	157
Accounts payable and other
Foreign exchange contracts	(5)	0	(2)	(376)	(383)		23	(360)
Interest rate contracts	(167)	0	0	(5)	(172)		0	(172)
Commodity contracts	0	0	0	(160)	(160)		82	(78)
Other contracts	0	0	0	(2)	(2)		0	(2)
	(172)	0	(2)	(543)	(717)	2	105	(612)
Other long-term liabilities
Foreign exchange contracts	0	0	0	(1,140)	(1,140)		111	(1,029)
Interest rate contracts	(566)	0	0	(23)	(589)		3	(586)
Commodity contracts	0	0	0	(80)	(80)		29	(51)
Other contracts	(4)	0	0	(5)	(9)		0	(9)
	(570)	0	0	(1,248)	(1,818)		143	(1,675)
Total net derivative assets/(liabilities)
Foreign exchange contracts	14	0	25	(1,280)	(1,241)		—	(1,241)
Interest rate contracts	(725)	0	0	(28)	(753)		—	(753)
Commodity contracts	3	0	0	(18)	(15)		—	(15)
Other contracts	(4)	0	0	(7)	(11)		—	(11)
	(712)	0	25	(1,333)	(2,020)		—	(2,020)

1As at September 30, 2020, $215 million was reported within Accounts receivable and other and NaN within Accounts receivable from affiliates on the Consolidated Statements of Financial Position.

2As at September 30, 2020, $716 million was reported within Accounts payable and other and $1 million within Accounts payable to affiliates on the Consolidated Statements of Financial Position.


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	0	0	161	161		(78)	83
Commodity contracts	0	0	163	163		(47)	116
Other contracts	1	0	3	4		0	4
	1	0	327	328	1	(125)	203
Deferred amounts and other assets
Foreign exchange contracts	10	0	71	81		(42)	39
Commodity contracts	0	0	17	17		(2)	15
Other contracts	2	0	1	3		0	3
	12	0	89	101		(44)	57
Accounts payable and other
Foreign exchange contracts	(5)	(13)	(392)	(410)		78	(332)
Interest rate contracts	(353)	0	0	(353)		0	(353)
Commodity contracts	0	0	(173)	(173)		47	(126)
	(358)	(13)	(565)	(936)	2	125	(811)
Other long-term liabilities
Foreign exchange contracts	0	0	(934)	(934)		42	(892)
Interest rate contracts	(181)	0	0	(181)		0	(181)
Commodity contracts	(5)	0	(60)	(65)		2	(63)
	(186)	0	(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)	0	0	(534)		—	(534)
Commodity contracts	(5)	0	(53)	(58)		—	(58)
Other contracts	3	0	4	7		—	7
	(531)	(13)	(1,143)	(1,687)		—	(1,687)

1As 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.

2As 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.

The following table summarizes the maturity and notional principal or quantity outstanding related to our derivative ~~instruments:~~instruments.



September 30, 2020	2020	2021	2022	2023	2024	Thereafter		Total
Foreign exchange contracts - United States dollar forwards - purchase (millions of United States dollars)	1,117	500	1,750	0	0	0		3,367
Foreign exchange contracts - United States dollar forwards - sell (millions of United States dollars)	1,593	5,631	5,703	3,784	1,856	0		18,567
Foreign exchange contracts - British pound (GBP) forwards - sell (millions of GBP)	70	27	28	29	30	90		274

Foreign exchange contracts - Euro forwards - sell (millions of Euro)	23	94	94	92	91	514		908
Foreign exchange contracts - Japanese yen forwards - purchase (millions of yen)	0	0	72,500	0	0	0		72,500
Interest rate contracts - short-term pay fixed rate (millions of Canadian dollars)	1,265	4,129	407	48	35	121		6,005
Interest rate contracts - long-term debt pay fixed rate (millions of Canadian dollars)	508	1,584	2,035	1,368	0	0		5,495
Equity contracts (millions of Canadian dollars)	19	44	7	11	0	0		81
Commodity contracts - natural gas (billions of cubic feet)3	25	60	31	18	10	10		154
Commodity contracts - crude oil (millions of barrels)3	4	12	1	0	0	0		17

Commodity contracts - power (megawatt per hour) (MW/H)	65	(3)	(43)	(43)	(43)	(43)	1	(30)	2

September 30, 2019 2019
2020
2021
2022
2023
Thereafter¹

Foreign exchange contracts - United States dollar forwards - purchase (millions of United States dollars)
1,049
1
—
—
—
—
Foreign exchange contracts - United States dollar forwards - sell (millions of United States dollars)
1,218
5,355
4,946
5,182
1,804
1,856
Foreign exchange contracts - British pound (GBP) forwards - sell (millions of GBP)
6
94
27
28
29
120
Foreign exchange contracts - Euro forwards - purchase (millions of Euro)
51
—
—
—
—
—
Foreign exchange contracts - Euro forwards - sell (millions of Euro)
—
23
94
94
92
606
Foreign exchange contracts - Japanese yen forwards - purchase (millions of yen)
—
—
—
72,500
—
—
Interest rate contracts - short-term pay fixed rate (millions of Canadian dollars)
2,204
6,152
4,124
405
48
156
Interest rate contracts - long-term debt pay fixed rate (millions of Canadian dollars)
1,509
3,125
1,579
—
—
—
Equity contracts (millions of Canadian dollars)
29
20
34
—
—
—
Commodity contracts - natural gas (billions of cubic feet)
(3 ) (26 ) 3
21
4
—
Commodity contracts - crude oil (millions of barrels)
7
1
—
—
—
—
Commodity contracts - power (megawatt per hour) (MW/H))
90
80
(3 ) (43 ) (43 ) (43 )
1 Thereafter includes an average net purchase/(sale) of power of (43) MW/H for 2025.

2 Total is an average net purchase/(sale) of power.

3 Total is a net purchase/(sale) of underlying commodity.

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

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 Consolidated Statements of Comprehensive Income.


	Three months ended September 30,		Nine months ended September 30,
	2020	2019	2020	2019
(millions of Canadian dollars)
Unrealized gain/(loss) on derivative	(60)	0	25	0
Unrealized gain/(loss) on hedged item	59	0	(6)	0
Realized loss on derivative	0	0	(12)	0

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 September 30,		Nine months ended September 30,
	2020	2019	2020	2019
(millions of Canadian dollars)
Amount of unrealized gain/(loss) recognized in OCI
Cash flow hedges
Foreign exchange contracts	0	2	6	(11)
Interest rate contracts	41	(231)	(709)	(812)
Commodity contracts	(1)	(1)	8	(22)
Other contracts	0	1	(6)	6
Fair value hedges
Foreign exchange contracts	(1)	—	7	0
Net investment hedges
Foreign exchange contracts	17	(1)	13	1
	56	(230)	(681)	(838)
Amount of (gain)/loss reclassified from AOCI to earnings
Foreign exchange contracts1	1	2	3	4
Interest rate contracts2	76	36	179	108
Commodity contracts	(1)	—	(1)	—
Other contracts3	(1)	(1)	(1)	(4)
	75	37	180	108

Three months ended
September 30, Nine months ended
September 30,
2019
2018
2019
2018
(millions of Canadian dollars)
Amount of unrealized gain/(loss) recognized in OCI
Cash flow hedges
Foreign exchange contracts 2
(16 ) (11 ) 2
Interest rate contracts (231 ) 69
(812 ) 186
Commodity contracts (1 ) 4
(22 ) 1
Other contracts 1
(10 ) 6
(12 )
Net investment hedges
Foreign exchange contracts (1 ) 25
1
36
(230 ) 72
(838 ) 213
Amount of (gain)/loss reclassified from AOCI to earnings
Foreign exchange contracts¹
2
7
4
4
Interest rate contracts²
36
38
108
132
Commodity contracts³
—
—
—
(1 )
Other contracts⁴
(1 ) 7
(4 ) 10
37
52
108
145
1 Reported within Transportation and other services revenues and Net foreign currency gain/(loss) in the Consolidated Statements of Earnings.


1	~~Reported within Transportation and other services revenues and Net foreign currency gain/(loss) in the Consolidated Statements of Earnings.~~


2	Reported within Interest expense in the Consolidated Statements of Earnings. Effective January 1, 2019 hedge ineffectiveness will no longer be measured or recorded. See Note 2 Changes in Accounting Policies.


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


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

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 ~~$72~~$99 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 2739 months as at September 30, ~~2019.~~2020.

~~Fair Value Derivatives~~

For interest rate derivative instruments that are designated and qualify as fair value hedges, the gain or loss on the derivative as well as the offsetting loss or gain on the hedged item attributable to the hedged risk is included in Interest expense in the Consolidated Statements of Earnings.

Three months ended
September 30, Nine months ended
September 30,

2019¹

2018

2019¹

2018
(millions of Canadian dollars)
Unrealized gain/(loss) on derivative —
3
—
(9 )
Unrealized gain/(loss) on hedged item —
(3 ) —
8
Realized gain/(loss) on derivative —
(3 ) —
(4 )
Realized gain/(loss) on hedged item —
3
—
4
30

~~TEXAS EASTERN RATE CASE~~

On June 1, 2019, Texas Eastern put into effect its updated rates. These increased recourse rates are subject to refund and interest. Following extensive negotiations on the Texas Eastern rate case, we reached an agreement with shippers and filed the Stipulation and Agreement with the FERC on October 28, 2019. We expect an approval in the second quarter of 2020.

RESULTS OF OPERATIONS


	Three months ended September 30,		Nine months ended September 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	2,090	1,646	5,280	5,710
Gas Transmission and Midstream	334	772	230	2,733
Gas Distribution and Storage	298	252	1,285	1,304
Renewable Power Generation	93	82	376	300
Energy Services	(34)	91	(12)	318
Eliminations and Other	207	(40)	(498)	315
Earnings before interest, income taxes and depreciation and amortization	2,988	2,803	6,661	10,680
Depreciation and amortization	(935)	(844)	(2,766)	(2,526)
Interest expense	(718)	(644)	(2,105)	(1,966)
Income tax expense	(231)	(255)	(273)	(1,275)
Earnings attributable to noncontrolling interests	(20)	(15)	(25)	(50)
Preference share dividends	(94)	(96)	(284)	(287)
Earnings attributable to common shareholders	990	949	1,208	4,576
Earnings per common share attributable to common shareholders	0.49	0.47	0.60	2.27
Diluted earnings per common share attributable to common shareholders	0.49	0.47	0.60	2.27

Three months ended
September 30, Nine months ended
September 30,
2019
2018
2019
2018
(millions of Canadian dollars, except per share amounts)

Segment earnings/(loss) before interest, income taxes and depreciation and amortization
Liquids Pipelines 1,646
1,875
5,710
4,353
Gas Transmission and Midstream 772
(60 ) 2,733
1,080
Gas Distribution 252
256
1,304
1,262
Renewable Power Generation and Transmission 82
51
300
286
Energy Services 91
(96 ) 318
108
Eliminations and Other (40 ) 29
315
(368 )

Depreciation and amortization (844 ) (799 ) (2,526 ) (2,452 )
Interest expense (644 ) (696 ) (1,966 ) (2,042 )
Income tax expense (255 ) (347 ) (1,275 ) (177 )
Earnings attributable to noncontrolling interests and redeemable noncontrolling interests (15 ) (209 ) (50 ) (352 )
Preference share dividends (96 ) (94 ) (287 ) (272 )
Earnings/(loss) attributable to common shareholders 949
(90 ) 4,576
1,426
Earnings/(loss) per common share 0.47
(0.05 ) 2.27
0.84
Diluted earnings/(loss) per common share 0.47
(0.05 ) 2.27
0.84

EARNINGS ATTRIBUTABLE TO COMMON SHAREHOLDERS

Three months ended September 30, ~~2019,~~2020, compared with the three months ended September 30, ~~2018~~2019

Earnings ~~Attributable~~attributable to ~~Common Shareholders~~common shareholders were ~~net~~ positively impacted by ~~$848~~$204 million due to certain unusual, infrequent or other non-operating factors, primarily explained by the following:

the absence in 2019 of a goodwill impairment charge of $1,019 million after-tax attributable to us in 2018 resulting from the classification of our Canadian natural gas gathering and processing businesses as held for sale;

~~the absence in 2019 of a loss of $74 million ($117 million after-tax attributable to us) in 2018 resulting from the sale of Midcoast Operating, L.P. and its subsidiaries (together, MOLP); and~~

~~the absence in 2019 of asset monetization transaction costs of $45 million ($49 million after-tax attributable to us) recorded in 2018 attributable to divestiture activity in the quarter.~~

~~The positive factors above were partially offset by the following unusual, infrequent or other non-operating factors:~~

•a non-cash, unrealized derivative fair value ~~loss~~gain of ~~$79~~$569 million ($52427 million ~~after-tax attributable to us)~~after-tax) in ~~2019,~~2020, compared with a ~~gain~~loss of ~~$264~~$170 million ($~~150~~130 million ~~after-tax attributable to us)~~after-tax) in ~~2018,~~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 ~~and commodity prices~~ risks;

•the absence in 2020 of a loss of $62 million ($47 million ~~after-tax attributable to us)~~after-tax) in 2019 related to asset write-down and goodwill impairment losses atwithin our equity investee, DCP ~~Midstream, LLC.;~~Midstream; and

•the absence in 2020 of a loss of $105 million ($79 million ~~after-tax attributable to us)~~after-tax) in 2019 resulting from the write-off of project costs related to the Access Northeast ~~pipeline~~Pipeline project.

The factors above were partially offset by a combined loss of $615 million ($452 million after-tax) in 2020 resulting from impairments to the carrying value of our equity method investments in SESH and Steckman, refer to Part 1. Item 1. Financial Statements - Note 9. Impairment of Equity Investments.

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

After taking into consideration the factors above, the remaining ~~$191~~$163 million ~~increase~~decrease in ~~Earnings Attributable~~earnings attributable to ~~Common Shareholders~~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 in which Energy Services holds capacity obligations;

•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; and

•higher depreciation and amortization expense as a result of new assets placed into service throughout 2019 and the first half of 2020, primarily the Canadian Line 3 Replacement (L3R) Program.

The business factors above were partially offset by the following positive factors:

•stronger contributions from our Liquids Pipelines segment due to a higher International Joint Tariff (IJT) Benchmark ~~Toll and higher Mainline System ex-Gretna throughput driven by an increase in supply and continuous capacity optimization;~~Toll;

•increased earnings from our ~~Liquids Pipelines~~Gas Distribution and Storage segment due to higher ~~Flanagan South Pipeline, Seaway Crude Pipeline System~~distribution charges resulting from increases in rates and ~~Bakken Pipeline System throughput period-over-period;~~customer base;

~~contributions from new Gas Transmission and Midstream assets placed into service in the fourth quarter of 2018; and~~

~~lower earnings attributable to noncontrolling interests in 2019 following the completion of the buy-in of our sponsored vehicles in the fourth quarter of 2018.~~

~~The positive business factors above were partially offset by the following:~~

~~the absence in 2019 of~~•increased earnings from ~~MOLP and the provincially regulated portion of our Canadian gas gathering and processing businesses which were sold in the second half of 2018; and~~

~~higher operating costs on~~ our Gas Transmission and Midstream ~~assets primarily~~segment due to ~~higher pipeline integrity costs.~~

increased rates on Texas Eastern and Algonquin resulting from 2020 rate settlements;

•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 half of 2020; and

•lower operating and administrative costs in 2020 as a result of cost containment actions.

Nine months ended September 30, ~~2019,~~2020, compared with the nine months ended September 30, ~~2018~~2019

Earnings ~~Attributable~~attributable to ~~Common Shareholders~~common shareholders were ~~net positively~~negatively impacted by ~~$2,439 million~~$3.0 billion due to certain unusual, infrequent or other non-operating factors, primarily explained by the following:

•a combined loss of $2.1 billion ($1.6 billion after-tax) related to our equity method investment in DCP Midstream due to a loss of $1.7 billion ($1.3 billion after-tax) resulting from an impairment to the ~~absence~~carrying value of our investment and a loss of $324 million ($244 million after-tax) in 2020, compared with $62 million ($47 million after-tax) in 2019 ~~of a~~resulting from further asset and goodwill impairment ~~charge~~losses, refer to Part I. Item 1. Financial Statements - Note 9. Impairment of ~~$1,019~~Equity Investments;

•a combined loss of $615 million ~~after-tax attributable~~($452 million after-tax) in 2020 resulting from impairments to usthe carrying value of our equity method investments in ~~2018~~SESH and Steckman, refer to Part I. Item 1. Financial Statements - Note 9. Impairment of Equity Investments;

•a non-cash, unrealized derivative fair value loss of $201 million ($151 million after-tax) in 2020, compared with a gain of $854 million ($626 million after-tax) in 2019, reflecting changes in the mark-to-market value of derivative financial instruments used to manage foreign exchange risks;

•a loss of $159 million ($119 million after-tax) in 2020 resulting from the ~~classification~~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

•employee severance, transition and transformation costs of $318 million ($240 million after-tax) in 2020 compared with $88 million ($78 million after-tax) in 2019 primarily related to our voluntary workforce reduction program offered in the second quarter of 2020.

The factors above were partially offset in 2020 by the absence of the loss of $105 million ($79 million after-tax) that was incurred in 2019 resulting from the write-off of project costs related to the Access Northeast Pipeline project.

After taking into consideration the factors above, the remaining $351 million decrease in earnings attributable to common shareholders is primarily explained by the following significant business factors:

•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; and

•higher depreciation and amortization expense as ~~held for sale;~~


•	the absence in 2019 of a loss of $913 million ($701 million after-tax attributable to us) in 2018 on MOLP resulting from a revision to the fair value of the assets held for sale based on the sale price;

a result of new assets placed into service throughout 2019 and the ~~absence in 2019~~first half of 2020, primarily the Canadian L3R Program.

The business factors above were partially offset by the following positive factors:

•stronger contributions from our Liquids Pipelines segment due to a ~~loss of $74 million ($117 million after-tax attributable~~higher IJT Benchmark Toll;

•increased earnings from our Gas Transmission and Midstream segment due to ~~us) in 2018~~increased rates on Texas Eastern and Algonquin resulting from ~~the sale of MOLP;~~2020 rate settlements;

~~the absence in~~•increased earnings from new Liquids Pipelines, Gas Transmission and Midstream, and Renewable Power Generation assets that were placed into service throughout 2019 of a loss of $154 million ($95 million after-tax attributable to us) in 2018 related to the Line 10 crude oil pipeline, which is a component of our Mainline System, resulting from its classification as an asset held for sale and the ~~subsequent measurement~~first half of 2020;

•lower operating and administrative costs in 2020 as a result of cost containment actions; 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 $1.35 in 2020 compared with $1.33 in 2019.

BUSINESS SEGMENTS

LIQUIDS PIPELINES


	Three months ended September 30,		Nine months ended September 30,
	2020	2019	2020	2019
(millions of Canadian dollars)
Earnings before interest, income taxes and depreciation and amortization	2,090	1,646	5,280	5,710

Three months ended September 30, 2020, compared with the ~~lower of carrying value~~three months ended September 30, 2019

EBITDA was positively impacted by $538 million due to certain unusual, infrequent or ~~fair value less costs to sell;~~

other non-operating factors, primarily explained by a non-cash, unrealized ~~derivative fair value~~ gain of ~~$1,052~~$360 million ~~($779 million after-tax attributable to us)~~ in ~~2019,~~2020, compared with a loss of ~~$295~~$180 million ~~($146 million after-tax attributable to us)~~ in ~~2018,~~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 ~~and commodity prices risks;~~risks.

employee severance, transition and transformation costs of $88 million ($78 million after-tax attributable to us) in 2019, compared with $143 million ($137 million after-tax attributable to us) in 2018; and

~~the absence in 2019 of asset monetization transaction costs of $65 million ($64 million after-tax attributable to us) recorded in 2018 attributable to divestiture activity in the period.~~

~~The positive factors above were partially offset by the following unusual, infrequent or other non-operating factors:~~

a non-cash, write-down of crude oil and natural gas inventories to the lower of cost or market in our Energy Services business segment of $171 million ($131 million after-tax attributable to us) compared to $23 million ($17 million after-tax attributable to us) in 2018;

~~a loss of $62 million ($47 million after-tax attributable to us) in 2019 related to asset write-down and goodwill impairment losses at our equity investee, DCP Midstream, LLC.;~~

~~a loss of $105 million ($79 million after-tax attributable to us) in 2019 resulting from the write-off of project costs related to the Access Northeast pipeline project;~~

~~the absence in 2019 of a gain of $63 million after-tax in 2018 that resulted from the impact of the Tax Cuts and Jobs Act on our United States Renewable Power Generation and Transmission assets; and~~

the absence in 2019 of a deferred income tax recovery of $267 million ($196 million attributable to us) in 2018 related to a change in the assertion for the investment in Canadian renewable energy generation assets.

After taking into consideration the ~~factors~~factor above, the remaining ~~$711~~$94 million ~~increase in Earnings Attributable to Common Shareholders~~decrease is primarily explained by the following significant business factors:

~~stronger contributions from our Liquids Pipelines segment due to a higher IJT Benchmark Toll and higher~~•lower Mainline System ex-Gretna throughput ~~driven by an increase~~of 2,555 kbpd in 2020 compared with 2,714 kbpd in 2019 due to lower volume demand resulting from the COVID-19 pandemic impact on supply and ~~continuous capacity optimization;~~demand for crude oil and related products; and

~~increased earnings from~~•lower throughput on our ~~Liquids Pipelines segment due to higher Flanagan South~~Bakken Pipeline System and Seaway Crude Pipeline System ~~and Bakken Pipeline System throughput period-over-period;~~

~~contributions from new Gas Transmission and Midstream assets placed into service in~~driven by the ~~fourth quarter~~significant impact of ~~2018;~~

~~increased earnings from our Gas Distribution segment due to colder weather experienced in our franchise areas, higher distribution rates and customer base,~~lower crude oil prices and the ~~absence in 2019 of forecasted earnings sharing which was recorded in 2018;~~COVID-19 pandemic on supply and demand for crude oil and related products.

increased earnings from our Energy Services segment due to the widening of certain location differentials during the second half of 2018 and the first quarter of 2019, which increased opportunities to generate profitable transportation margins that were realized during 2019;

~~lower earnings attributable to noncontrolling interests in 2019 following the completion of the buy-in of our sponsored vehicles in the fourth quarter of 2018; and~~

the net favorable effect of translating United States dollar EBITDA at a higher Canadian to United States dollar average exchange rate (Average Exchange Rate) of $1.33 in 2019 compared with $1.29 in 2018, partially offset by realized losses arising from our foreign exchange risk management program.

The ~~positive~~ business factors above were partially offset by the ~~following:~~following positive factors:

•a higher IJT Benchmark Toll on our Mainline System of US$4.27 in 2020 compared with US$4.21 in 2019;

•contributions from the ~~absence in~~Canadian L3R Program that was placed into service on December 1, 2019 with an interim surcharge on Mainline System volumes of ~~earnings from MOLP~~US$0.20 per barrel for the IJT Benchmark Toll; and

•higher Flanagan South Pipeline throughput and the ~~provincially regulated portion~~collection of ~~our Canadian gas gathering and processing businesses which were sold in the second half of 2018;~~revenue on volumes nominated but not shipped.

~~higher operating costs on our Gas Transmission and Midstream assets primarily due to higher pipeline integrity costs; and~~

~~higher income tax expense due to higher earnings, the buy-in of our United States sponsored vehicles in the fourth quarter of 2018 and lower foreign tax rate differentials in 2019.~~

~~BUSINESS SEGMENTS~~

~~LIQUIDS PIPELINES~~

Three months ended
September 30, Nine months ended
September 30,
2019
2018
2019
2018
(millions of Canadian dollars)

Earnings before interest, income taxes and depreciation and amortization 1,646
1,875
5,710
4,353

~~Three~~Nine months ended September 30, ~~2019,~~2020, compared with the ~~three~~nine months ended September 30, ~~2018~~2019

EBITDA was negatively impacted by ~~$422~~$504 million due to certain unusual, infrequent or other non-operating factors, primarily explained by ~~the following:~~

a non-cash, unrealized loss of ~~$180~~$90 million in ~~2019~~2020, compared with a gain of ~~$211~~$390 million in ~~2018~~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 ~~and commodity price risks; and~~risks.

~~the absence in 2019 of a gain of $28 million in 2018 on the sale of pipe related to our Sandpiper Project.~~

After taking into consideration the ~~factors~~factor above, the remaining ~~$193~~$74 million increase is primarily explained by the following significant business factors:

•a higher IJT Benchmark Toll on our Mainline System of US$~~4.21~~4.23 in ~~2019~~2020 compared with US$~~4.15~~4.17 in ~~2018;~~2019;

~~higher~~•contributions from the Canadian L3R Program that was placed into service on December 1, 2019 with an interim surcharge on Mainline System ~~ex-Gretna throughput~~volumes of ~~2,714 thousands of barrels~~US$0.20 per ~~day (kbpd) in 2019 compared with 2,578 kbpd in 2018 driven by an increase in supply and continuous capacity optimization;~~barrel for the IJT Benchmark Toll;

•higher Flanagan South Pipeline ~~and Seaway Crude Pipeline System~~ throughput ~~period-over-period driven by strong Gulf Coast demand resulting from favorable price differentials; and~~

~~higher Bakken Pipeline System throughput period-over-period driven by strong production in the region.~~

The positive business factors above were partially offset by the unfavorable effect of a lower foreign exchange hedge rate used to lock-in United States dollar denominated Canadian Mainline revenues of US$1.19 in 2019 compared with US$1.26 in 2018.

~~Nine months ended September 30, 2019, compared with the nine months ended September 30, 2018~~

~~EBITDA was positively impacted by $925 million due to certain unusual, infrequent or other non-operating factors, primarily explained by the following:~~

a non-cash, unrealized gain of $390 million in 2019 compared with a loss of $362 million in 2018 reflecting net fair value gains and losses arising from changes in the mark-to-market value of derivative financial instruments used to manage foreign exchange and commodity price risks; and

~~the absence in 2019 of a loss of $154 million in 2018 related to Line 10, which is a component of our Mainline System, resulting from its classification as an asset held for sale~~ and the ~~subsequent measurement at the lower~~collection of ~~carrying value or fair value less costs to sell.~~revenue on volumes nominated but not shipped; and

~~The positive factors above were partially offset by the absence in 2019 of a gain of $28 million in 2018 on the sale of pipe related to our Sandpiper Project.~~

~~After taking into consideration the factors above, the remaining $432 million increase is primarily explained by the following significant business factors:~~

~~a higher IJT Benchmark Toll of US$4.17 in 2019 compared with US$4.10 in 2018;~~

~~higher Mainline System ex-Gretna throughput of 2,698 kbpd in 2019 compared with 2,613 kbpd in 2018 driven by an increase in supply and continuous capacity optimization;~~

higher Flanagan South Pipeline and Seaway Crude Pipeline System throughput period-over-period driven by the redirection of throughput to the Gulf Coast resulting from refinery outages in the United States Midwest in the first half of 2019 and strong Gulf Coast demand resulting from favorable price differentials;

~~higher Bakken Pipeline System throughput period-over-period driven by strong production in the region; and~~

•the net favorable effect of translating United States dollar EBITDA at a higher Average Exchange Rate of $1.35 in 2020 compared with $1.33 in ~~2019 compared with $1.29 in 2018.~~2019.

The positive business factors above were partially offset by:

•lower Mainline System ex-Gretna throughput of 2,612 kbpd in 2020 compared with 2,698 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;

•lower throughput on our Bakken Pipeline System and Seaway Crude Pipeline System driven by the ~~unfavorable effect~~significant impact of a lower ~~foreign exchange hedge rate used to lock-in United States dollar denominated Canadian Mainline revenues of US$1.19~~crude oil prices and the COVID-19 pandemic on supply and demand for crude oil and related products; and

•lower Regional Oil Sands throughput for contracts with make-up rights resulting in ~~2019 compared with US$1.26 in 2018.~~lower revenue recognized until the rights expire or are utilized.

GAS TRANSMISSION AND MIDSTREAM


	Three months ended September 30,		Nine months ended September 30,
	2020	2019	2020	2019
(millions of Canadian dollars)
Earnings before interest, income taxes and depreciation and amortization	334	772	230	2,733

Three months ended
September 30, Nine months ended
September 30,
2019
2018
2019
2018
(millions of Canadian dollars)
Earnings/(loss) before interest, income taxes and depreciation and amortization 772
(60 ) 2,733
1,080

Three months ended September 30, ~~2019,~~2020, compared with the three months ended September 30, ~~2018~~2019

EBITDA was negatively impacted by the absence of contributions in 2019 of approximately $85 million from the sale of MOLP on August 1, 2018 and the sale of the provincially regulated portion of our Canadian gas gathering and processing businesses on October 1, 2018.

~~EBITDA was positively impacted by $926~~$439 million due to certain unusual, infrequent or other non-operating factors, primarily explained by ~~the following:~~

~~the absence in 2019~~a combined loss of ~~a goodwill impairment charge of $1,019~~$615 million in ~~2018~~2020 resulting from impairments to the ~~classification~~carrying value of our ~~Canadian natural gas gathering~~equity method investments in SESH and ~~processing businesses as held for sale; and~~Steckman.

~~the absence in 2019 of a loss of $74 million in 2018 resulting from the sale of MOLP.~~

The ~~positive factors~~factor above ~~were~~was partially offset by the ~~following:~~following positive factors:

•the absence in 2020 of a loss of $62 million in 2019 related to asset write-down and goodwill impairment losses atwithin our equity investee, DCP ~~Midstream, LLC.;~~Midstream; and

•the absence in 2020 of a loss of $105 million in 2019 resulting from the write-off of project costs related to the Access Northeast ~~pipeline~~Pipeline project.

After taking into consideration the factors above, the remaining $9$1 million ~~decrease~~increase is primarily explained by the following significant business factors:

•higher ~~operating costs~~revenues from increased rates on ~~our US Gas Transmission assets primarily due to higher pipeline integrity costs;~~


•	~~lower revenues and higher operating costs from US Gas Transmission due to the Texas Eastern natural gas pipeline system incident in Lincoln County, Kentucky, refer to~~ ~~Recent Developments - Texas Eastern Pipeline Rupture;~~ Texas Eastern and Algonquin resulting from 2020 rate settlements; and

~~decreased fractionation margins at our Aux Sable joint venture driven by lower NGL prices.~~

•contributions from the second phase of the Atlantic Bridge project that was placed into service in the fourth quarter of 2019.

The ~~negative~~positive business factors above were partially offset by ~~contributions~~the following:

•the absence of earnings in 2020 from ~~Valley Crossing Pipeline~~the federally-regulated portion of our Canadian natural gas gathering and ~~certain other Offshore and~~processing businesses which were sold on December 31, 2019;

•lower revenues on our US Gas Transmission assets ~~that were placed into service during the fourth quarter of 2018.~~due to pressure restrictions on Texas Eastern; and

•lower commodity prices impacting our Aux Sable joint venture.

Nine months ended September 30, ~~2019,~~2020, compared with the nine months ended September 30, ~~2018~~2019

EBITDA was negatively impacted by the absence of contributions in 2019 of approximately $240 million from the sale of MOLP on August 1, 2018 and the sale of the provincially regulated portion of our Canadian gas gathering and processing businesses on October 1, 2018.

~~EBITDA was positively impacted by $1,849 million~~$2.6 billion due to certain unusual, infrequent or other non-operating factors, primarily explained by the following:

•a loss of $1.7 billion in 2020 resulting from an impairment to the ~~absence~~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 compared with $62 million in 2019 ~~of a~~resulting from further asset and goodwill impairment ~~charge~~losses within our equity method investee, DCP Midstream;

•a combined loss of ~~$1,019~~$615 million in ~~2018~~2020 resulting from impairments to the carrying value of our equity method investments in SESH and Steckman; and

•a loss of $159 million in 2020 resulting from the ~~classification of our Canadian natural gas gathering and processing businesses as held for sale;~~February 2020 Texas Eastern rate settlement that re-established the EDIT regulated liability that was previously eliminated in December 2018.

~~the absence in 2019 of a loss of $913 million in 2018 on MOLP resulting from a revision to the fair value of the assets held for sale based on the sale price; and~~

~~the absence in 2019 of a loss of $74 million in 2018 resulting from the sale of MOLP.~~

The ~~positive~~ factors above were partially offset by the ~~following unusual, infrequent or other non-operating factors:~~

~~a loss~~absence in 2020 of ~~$62 million in 2019 related to asset write-down and goodwill impairment losses at our equity investee, DCP Midstream, LLC.; and~~

a loss of $105 million in 2019 resulting from the write-off of project costs related to the Access Northeast ~~pipeline~~Pipeline project.

After taking into consideration the factors above, the remaining ~~$44~~$97 million increase is primarily explained by the following significant business factors:

•higher revenues from increased rates on Texas Eastern and Algonquin resulting from 2020 rate settlements;

•contributions from ~~Valley Crossing Pipeline~~the Stratton Ridge project and ~~certain other Offshore and US Gas Transmission assets~~the second phase of the Atlantic Bridge project that were placed into service ~~during~~in the second and fourth ~~quarter~~quarters of ~~2018;~~2019, respectively; and

•the net favorable effect of translating United States dollar EBITDA at a higher Average Exchange Rate of $1.35 in 2020 compared with $1.33 in ~~2019 compared with $1.29 in 2018.~~2019.

The positive business factors above were partially offset by the following:

~~higher operating costs~~•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;

•lower revenues on our US Gas Transmission assets ~~primarily~~ due to ~~higher pipeline integrity costs;~~pressure restrictions on Texas Eastern;


•	~~lower revenues and higher operating costs from US Gas Transmission due to the Texas Eastern natural gas pipeline system incident in Lincoln County, Kentucky, refer to~~ ~~Recent Developments - Texas Eastern Pipeline Rupture;~~ ~~and~~

~~decreased fractionation margins~~•narrowed AECO-Chicago basis at our Alliance Pipeline joint venture; and

•lower commodity prices impacting our Aux Sable joint ~~venture driven by lower NGL prices.~~venture.

GAS DISTRIBUTION AND STORAGE


	Three months ended September 30,		Nine months ended September 30,			Three months ended September 30,		Nine months ended September 30,
	2019	2018	2019	2018		2020	2019	2020	2019
(millions of Canadian dollars)					(millions of Canadian dollars)
Earnings before interest, income taxes and depreciation and amortization	252	256	1,304	1,262	Earnings before interest, income taxes and depreciation and amortization	298	252	1,285	1,304

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

EBITDA was negatively impacted by $14 million due to certain unusual, infrequent and other non-operating factors, explained by transition and transformation costs of $28 million in 2020 compared with $4 million in 2019 primarily related to the amalgamation of Enbridge Gas Distribution Inc. (EGD) and Union Gas Limited (Union Gas) ~~were amalgamated on January 1, 2019. The amalgamated company has been renamed EGI. Post amalgamation the financial results of EGI reflect the combined performance of EGD and Union Gas.~~

~~Three months ended September 30, 2019, compared with the three months ended September 30, 2018~~

~~EBITDA decreased by $4 million primarily explained by accelerated capital cost allowance deductions reflected as a pass through to customers.~~

. This ~~negative~~ factor was partially offset by ~~the following:~~

~~higher distribution charges primarily resulting from increases in distribution rates and customer base; and~~

~~synergy captures realized from the amalgamation of EGD and Union Gas.~~

~~Nine months ended September 30, 2019, compared with the nine months ended September 30, 2018~~

EBITDA was negatively impacted by $22 million due to certain unusual, infrequent or other non-operating factors, primarily explained by employee severance costs of $37 million in 2019 related to the amalgamation of EGD and Union Gas.

~~This negative factor was partially offset by the following unusual, infrequent or other non-operating factors:~~

a non-cash, unrealized gain of $9$11 million in ~~2019~~2020 compared with aan unrealized gain of $3$1 million in ~~2018~~2019 arising from the change in the mark-to-market value of ~~our equity investee's, Noverco Inc.'s~~Noverco's derivative financial ~~instruments; and~~instruments.

~~the absence in 2019 of a negative equity earnings adjustment of $9 million in 2018 at our equity investee, Noverco Inc., arising from the Tax Cuts and Jobs Act in the United States.~~

After taking into consideration the factors above, the remaining ~~$64~~$60 million increase is primarily explained by the following significant business factors:

~~increased earnings of $41 million resulting from colder weather experienced in our franchise service areas when compared to the corresponding period in 2018;~~

~~increased earnings from~~ •higher distribution charges ~~primarily~~ resulting from increases in ~~distribution~~ rates and customer base; and

~~the absence in 2019 of forecasted earnings sharing which was recorded in 2018 under EGD's previous incentive rate structure; and~~

•synergy ~~captures~~capture realized from the amalgamation of EGD and Union Gas.

The positive business factors above were partially offset by ~~accelerated capital cost allowance deductions reflected as a pass through to customers.~~the absence of earnings in 2020 from Enbridge Gas New Brunswick (EGNB) and St. Lawrence Gas Company, Inc. (St. Lawrence Gas) which were sold on October 1, 2019 and November 1, 2019, respectively.

~~RENEWABLE POWER GENERATION AND TRANSMISSION~~

~~Three~~Nine months ended September 30, ~~2019,~~2020, compared with the ~~three~~nine months ended September 30, ~~2018~~2019

EBITDA was ~~positively~~negatively impacted by ~~$22~~$11 million due to certain unusual, infrequent and other non-operating factors, primarily explained by ~~the absence~~a non-cash, unrealized gain of $2 million in 2020 compared with an unrealized gain of $9 million in 2019 ~~of a loss of $20 million in 2018 resulting~~arising from the ~~sale of 49% of our interest~~change in the ~~Hohe See Offshore wind facility and its subsequent expansion.~~mark-to-market value of Noverco's derivative financial instruments.

After taking into consideration the factor above, the remaining $8 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 $18 million while the colder weather in 2019 positively impacted 2019 EBITDA by approximately $51 million; and

•the absence of earnings in 2020 from EGNB and St. Lawrence Gas which were sold on October 1, 2019 and November 1, 2019, respectively.

The business factors above were partially offset by the following positive factors:

•higher distribution charges resulting from increases in rates and customer base; and

•synergy capture realized from the amalgamation of EGD and Union Gas.

RENEWABLE POWER GENERATION


	Three months ended September 30,		Nine months ended September 30,
	2020	2019	2020	2019
(millions of Canadian dollars)
Earnings before interest, income taxes and depreciation and amortization	93	82	376	300

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

EBITDA was positively impacted by $11 million primarily explained by 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. This positive business factor was partially offset by higher mechanical repair costs at certain United States wind facilities.

Nine months ended September 30, 2020, compared with the nine months ended September 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 $56 million increase is primarily explained by the following significant business factors:

•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;

•stronger wind resources at ~~Canadian and~~ United States wind facilities; and

~~higher contributions~~•reimbursements received at certain Canadian wind facilities resulting from ~~the Rampion Offshore Wind Project.~~a change in operator.

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

~~Nine months ended September 30, 2019, compared with the nine months ended September 30, 2018~~

~~EBITDA was positively impacted by $46 million due to certain unusual, infrequent and other non-operating factors, primarily explained by the following:~~

~~the absence in 2019 of a loss of $20 million in 2018 resulting from the sale of 49% of our interest in the Hohe See Offshore wind facility and its expansion;~~

the absence in 2019 of an asset impairment charge of $22 million in 2018 from our equity investment in NRGreen Power Limited Partnership related to the Chickadee Creek waste heat recovery facility in Alberta; and


▪	the absence in 2019 of a loss of $11 million in 2018 representing our share of losses incurred by our equity investee, Rampion Offshore Wind Limited, primarily due to the repair and restoration of damaged power transmission cables.

~~After taking into consideration the factors above, the remaining $32 million decrease is primarily explained by the following significant business factors:~~

~~weaker wind resources at United States wind facilities;~~

~~the absence in 2019 of $11 million in 2018 from a positive arbitration settlement related to our Canadian wind facilities; and~~

~~higher mechanical repair costs at certain United States wind facilities.~~

~~The negative business factors above were partially offset by the following:~~

~~higher contributions from the Rampion Offshore Wind Project which reached full operating capacity in the second quarter of 2018; and~~

~~stronger wind resources at Canadian wind facilities.~~

ENERGY SERVICES


	Three months ended September 30,			Nine months ended September 30,			Three months ended September 30,		Nine months ended September 30,
	2019	2018		2019	2018		2020	2019	2020	2019
(millions of Canadian dollars)						(millions of Canadian dollars)
Earnings/(loss) before interest, income taxes and depreciation and amortization	91	(96	)	318	108	Earnings/(loss) before interest, income taxes and depreciation and amortization	(34)	91	(12)	318

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

Three months ended September 30, ~~2019,~~2020, compared with the three months ended September 30, ~~2018~~2019

EBITDA was ~~net~~ positively impacted by ~~$170~~$12 million due to certain unusual, infrequent or other non-operating factors, ~~primarily~~ explained by the following:

•a non-cash, unrealized gain of ~~$91~~$73 million in ~~2019~~2020, compared with a ~~loss~~gain of ~~$99~~$66 million in ~~2018~~2019, reflecting the revaluation of derivatives used to manage the profitability of transportation and storage transactions, ~~and~~as well as manage the exposure to movements in commodity ~~prices. This positive factor was offset by~~ prices; and

•a non-cash, ~~write-down of~~net positive adjustment to crude oil and natural gas inventories ~~to the lower~~ of ~~cost or market of $27~~$3 million in ~~2019~~2020 compared with $7a net negative adjustment of $2 million in ~~2018.~~2019.

After taking into consideration the factors above, the remaining ~~$17~~$137 million ~~increase is primarily due to increased earnings from Energy Services' crude operations as a result~~decrease reflects the significant compression of ~~the widening of certain~~ location and quality differentials ~~during the second half of 2018~~in certain markets and ~~the first quarter of 2019, which increased~~fewer opportunities to ~~generate~~achieve profitable transportation margins ~~that were realized during 2019.~~on facilities in which Energy Services holds capacity obligations.

Nine months ended September 30, ~~2019,~~2020, compared with the nine months ended September 30, ~~2018~~2019

EBITDA was ~~positively~~negatively impacted by ~~$13~~$2 million due to certain unusual, infrequent ~~and~~or other non-operating factors, ~~primarily~~ explained by a non-cash, net positive adjustment to crude oil and natural gas inventories of $1 million in 2020 compared with a net positive adjustment of $83 million in 2019. This negative factor was partially offset by a non-cash, unrealized gain of ~~$198~~$24 million in ~~2019~~2020, compared with a ~~gain~~loss of ~~$37~~$56 million in ~~2018~~2019, reflecting the revaluation of derivatives used to manage the profitability of transportation and storage transactions, ~~and~~as well as manage the exposure to movements in commodity prices. ~~This positive factor was offset by a non-cash, write-down of crude oil and natural gas inventories to the lower of cost or market of $171 million in 2019 compared with $23 million in 2018.~~

After taking into consideration the factors above, the remaining ~~$197~~$328 million ~~increase is primarily due to increased earnings from Energy Services' crude operations as a result~~decrease reflects the significant compression of ~~the widening of certain~~ location and quality differentials ~~during the second half of 2018~~in certain markets and ~~the~~fewer opportunities to achieve profitable transportation margins on facilities in 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 ~~generate~~realize profitable ~~transportation margins that were realized during 2019.~~margins.

ELIMINATIONS AND OTHER


	Three months ended September 30,			Nine months ended September 30,				Three months ended September 30,		Nine months ended September 30,
	2019		2018	2019	2018			2020	2019	2020	2019
(millions of Canadian dollars)							(millions of Canadian dollars)
Earnings/(loss) before interest, income taxes and depreciation and amortization	(40	)	29	315	(368	)	Earnings/(loss) before interest, income taxes and depreciation and amortization	207	(40)	(498)	315

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 September 30, ~~2019,~~2020, compared with the three months ended September 30, ~~2018~~2019

EBITDA was ~~negatively~~positively impacted by ~~$98~~$199 million due to certain unusual, infrequent and other non-operating factors, primarily explained by a non-cash, unrealized gain of $9$198 million in ~~2019~~2020, compared with a gain of ~~$131~~$9 million in ~~2018~~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. ~~This negative factor was offset by the absence in 2019 of asset monetization transaction costs of $25 million in 2018.~~

After taking into consideration the ~~factors~~factor above, the remaining ~~$29~~$48 million increase is primarily explained by ~~the following significant business factors:~~

lower operating and administrative costs in 2020 as a result of cost containment actions and the ~~third quarter~~timing of ~~2019; and~~

~~a realized loss~~the recovery of ~~$50 million in 2019 compared with a loss of $59 million in 2018 related~~certain operating administrative costs allocated to ~~settlements under our foreign exchange risk management program, which partially offset~~ the ~~positive impact of a strengthening United States dollar on our United States~~ business segments.

Nine months ended September 30, ~~2019,~~2020, compared with the nine months ended September 30, ~~2018~~2019

EBITDA was ~~positively~~negatively impacted by ~~$592~~$909 million due to certain unusual, infrequent and other non-operating factors, primarily explained by the following:

•a non-cash, unrealized loss of $115 million in 2020, compared with a gain of $453 million in 2019, ~~compared with nil in 2018~~ reflecting ~~net fair value gains and losses arising from~~ the change in the mark-to-market value of derivative financial instruments used to manage foreign exchange risk;

•employee severance, transition and transformation costs of $262 million in 2020 compared with $45 million in 2019 ~~compared with $102~~primarily related to our voluntary workforce reduction program offered in the second quarter of 2020;

•a loss of $74 million in ~~2018;~~2020 from non-cash changes in a corporate guarantee obligation; and

~~the absence in 2019~~•a loss of ~~asset monetization transaction costs of $45~~$43 million in ~~2018.~~2020 from the write-down of certain investments in emerging energy and other technologies.

After taking into consideration the factors above, the remaining ~~$91~~$96 million increase is primarily explained by lower operating and administrative costs in ~~2019~~2020 as a result of cost containment actions and the timing of the recovery of certain operating ~~and~~ administrative costs allocated to the business ~~segments, which were more heavily weighted to the fourth quarter of 2018.~~

The positive business factor above was partially offset by a realized loss of $166 million in 2019 compared with a loss of $154 million in 2018 related to settlements under our foreign exchange risk management program, which partially offset the positive impact of a strengthening United States dollar on our United States business segments.

GROWTH PROJECTS – COMMERCIALLY SECURED PROJECTS

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

Enbridge's Ownership Interest

Estimated
Capital

Cost¹

Expenditures
to Date²

Status

Expected
In-Service
Date

Enbridge's Ownership Interest

Estimated
Capital

Cost1

Expenditures
to Date2

Status

Expected
In-Service
Date

(Canadian dollars, unless stated otherwise)

LIQUIDS PIPELINES

Other - Canada³

100

$0.3 billion

Complete

In-service

United States Line 3 Replacement Program

100

US$2.9 billion

US$1.7 billion

Various Stages

Under review3

Gray Oak Pipeline Project

22.8

US$0.7 billion

US$0.4 billion

Under construction

Q4 - 2019

Southern Access Expansion

100

US$0.5 billion

Under construction

Under review4

Canadian Line 3 Replacement Program

100

$5.3 billion

$4.8 billion

Substantially complete

Q4 - 2019

Other - United States

100

US$0.1 billion

Under construction

1H - 2021

GAS TRANSMISSION AND MIDSTREAM

U.S. Line 3 Replacement Program

100

US$2.9 billion

US$1.2 billion

Pre-construction

2H - 2020⁴

T-South Reliability & Expansion Program

100

$1.0 billion

$0.7 billion

Under construction

2H - 2021

Other - United States⁵

100

US$0.6 billion

US$0.5 billion

Various stages

2020 - 2021

Spruce Ridge Project5

100

$0.5 billion

$0.2 billion

Under construction

2H - 2021

GAS TRANSMISSION AND MIDSTREAM

Atlantic Bridge

100

US$0.6 billion

US$0.5 billion

Various stages

2019 - 2020

Other - United States6

Various

US$1.0 billion

US$0.4 billion

Various stages

2020 - 2023

GAS DISTRIBUTION AND STORAGE

Spruce Ridge Project

100

$0.5 billion

$0.2 billion

Pre-construction

2H - 2021

System Modernization - Windsor & Owen Sound

100

$0.2 billion

$0.1 billion

Under construction

Q4 - 2020

T-South Reliability & Expansion Program

100

$1.0 billion

$0.3 billion

Pre-construction

2H - 2021

London Line Replacement Project

100

$0.2 billion

No significant expenditures to date

Pre-construction

2H - 2021

Other - United States⁶

Various

US$1.2 billion

US$0.5 billion

Various stages

2019 - 2023

Utility Growth Capital & Storage Enhancements

100

$0.3 billion

No significant expenditures to date

Pre-construction

2021 - 2023

GAS DISTRIBUTION

RENEWABLE POWER GENERATION

10.

Other - Canada

100

$0.2 billion

No significant expenditures to date

Pre-construction

2H - 2020

10.

East-West Tie Line

25.0

$0.2 billion

$0.1 billion

Under construction

1H - 2022

11.

Dawn-Parkway Expansion

100

$0.2 billion

No significant expenditures to date

Pre-construction

2H - 2021

11.

Saint-Nazaire France Offshore Wind Project7

25.5

$0.9 billion

$0.1 billion

Under construction

2H - 2022

RENEWABLE POWER GENERATION AND TRANSMISSION

11.

Saint-Nazaire France Offshore Wind Project7

25.5

(€0.6 billion)

(€0.1 billion)

Under construction

2H - 2022

Hohe See Offshore Wind Project and Expansion

td.1 billion

$0.8 billion

Substantially complete

Q4 - 2019

$0.7 billion

No significant expenditures to date

12.

(€0.67 billion)

(€0.5 billion)

12.

Fécamp Offshore Wind Project8

17.9

(€0.5 billion)

Under construction

2023

Other - Canada

$0.2 billion

No significant expenditures to date

Under construction

2H - 2021

14.

Saint-Nazaire France Offshore Wind Project

td.8 billion

No significant expenditures to date

Under construction

2H - 2022

(€1.2 billion)

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

2 Expenditures to date reflect total cumulative expenditures incurred from inception of the project up to September 30, ~~2019.~~2020.

3 ~~Athabasca Oil Corporation Lateral Acquisition closed in the first quarter of 2019.~~

4 Update to in-service date pending ~~MNPUC review~~receipt of ~~FEIS remediation.~~all permits required to complete construction.

~~5 Includes the Lakehead System Mainline Expansion - Line 61.~~4 Estimated in-service date will be adjusted to coincide with the in-service date of the U.S. L3R Program.

~~6 Includes the US$0.2 billion Stratton Ridge Project placed into service~~5 Expenditures were revised in the second quarter of ~~2019 and~~2020 due to scope modifications.

6 Includes the US$0.1 billion ~~Generation Pipeline Acquisition closed~~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 ~~third~~fourth quarter of ~~2019.~~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.

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

~~LIQUIDS PIPELINES~~

•

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


•	~~Canadian Line 3 Replacement Program -~~ ~~on August 30, 2019, we announced that we have reached a commercial agreement with shippers to place the Canadian L3R Program into service on December 1, 2019. Refer to~~ ~~Recent Developments - Canadian Line 3 Replacement Program to be placed into service.~~

GAS TRANSMISSION AND MIDSTREAM

•

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


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

•

~~T-South Reliability & Expansion Program~~ - a natural gas pipeline expansion of Westcoast Energy Inc.'s BC Pipeline in southern BC that will provide improved compressor reliability and additional capacity of approximately 190 mmcf/d into the Huntington/Sumas market at the United States/Canada border. The projects were approved by the CER in September 2019 and have an expected in-service date in the second half of 2021.

•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


•	~~Dawn-Parkway Expansion~~ - the expansion of the existing Dawn to Parkway gas transmission system, which provides transportation service from Dawn to the Greater Toronto Area. The project will provide additional capacity of approximately 83 mmcf/d with an expected in-service date by the end of 2021.

•Dawn-Parkway Expansion - an expansion of the existing Dawn to Parkway gas transmission system, which provides transportation service from Dawn, Ontario to the Greater Toronto Area.In October 2020, due to changes in demand and uncertainties resulting from the COVID-19 pandemic, Enbridge Gas withdrew the leave to construct application with the OEB. Enbridge Gas will continue to assess demand requirements for the expansion and refile as needed in the future.

•London Line Replacement Project - a project that will replace the two current pipelines known collectively as the London Line and includes the construction of approximately 90.5-kilometers of natural gas pipeline and ancillary facilities in southern Ontario.

•Utility Growth Capital & Storage Enhancements - utility growth capital expenditures including regulated rate base system reinforcements and an enhancement of our unregulated storage facilities at Dawn, Ontario.

RENEWABLE POWER GENERATION ~~AND TRANSMISSION~~

•

~~Hohe See Offshore Wind Project and Expansion~~ - a wind project located in the North Sea, off the coast of Germany that will generate approximately 497-MW, with an additional 112-MW from the expansion. The Hohe See Project and Expansion is backed by a government legislated 20-year revenue support mechanism. The project generated first power in July 2019 and full operating capacity was reached in October 2019. The project expansion is expected to be placed into service by the end of the year.

•

~~Saint Nazaire France Offshore Wind Project -~~ a wind project located off the west coast of France that will generate approximately 480 megawatts. We hold an effective 50% interest with EDF Renouvelables. Project revenues are backed by a 20-year fixed price power purchase agreement with added power production protection. Our share of the total investment in the project is $1.8 billion, with an equity contribution of $0.3 billion. The remainder of the construction will be financed through non-recourse project level debt. The project is expected to be placed into service in the second half of 2022.

•East-West Tie Line - a transmission project that will parallel an existing double-circuit, 230 kilovolt transmission line that connects the Wawa Transformer Station to the Lakehead Transformer Station near Thunder Bay, Ontario, including a connection midway in Marathon, Ontario. Due to a construction stoppage caused by the COVID-19 pandemic, the revised expected in-service date is the first half of 2022.

•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. 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 second 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 EIS and the MNPUC’s restored grant of the Certificate of Need and Route Permit. On June ~~3, 2019, the Minnesota Court of Appeals rendered a decision on the MNPUC's adequacy determination of the FEIS~~1, 2020, Enbridge and various supporting parties filed responses to those filed petitions for the U.S. L3R Program. While denying eight of the nine issues on appeal, the Minnesota Court of Appeals identified one issue that led them to reverse the adequacy determination. The Minnesota Court of Appeals remanded and directedreconsideration. On June 25, 2020 the MNPUC to perform spill modeling analysis within the Lake Superior Watershed. On July 3, 2019, certain project opponents sought further appellate review from the Minnesota Supreme Court. On September 17, 2019, based on the respective responses of the MNPUC and the Company, the Minnesota Supreme Court denied ~~the opponents’~~all petitions ~~thus restoring the MNPUC with jurisdiction. At a hearing on October 1, 2019, the MNPUC directed the Department of Commerce to submit a revised FEIS by December 9, 2019.~~for reconsideration reaffirming its prior decisions in all three dockets.

As for environmental permits, ~~the spill modeling required by the Minnesota Court of Appeals is a prerequisite to finalizing other state permits. On September 27, 2019,~~ the Minnesota Pollution Control Agency (MPCA) ~~issued~~released a ~~denial without prejudice~~draft of the ~~U.S. L3R Program's~~revised 401 Water Quality ~~Certification (WQC). This action was expected since~~Certificate in February 2020. Following a public comment period, the MPCA ~~is prohibited by State law from issuing a final 401 WQC until the FEIS has been revised to reflect the~~announced on June 3, ~~2019 Minnesota Court~~2020 that it would conduct a contested case hearing regarding the 401 Water Quality Certificate. After an Administrative Law Judge (ALJ) was assigned to the case, the contested case hearing schedule was established on June 23, 2020. The MPCA's contested case hearing is now complete and on October 16, 2020, the MPCA received a favorable recommendation from the ALJ on all five of ~~Appeals~~the issues considered. This recommendation will inform the MPCA Commissioner's decision ~~requiring additional spill modelling.~~on the 401 Water Quality Certificate which we anticipate by the statutory deadline of November 14, 2020.

~~The MNPUC’s statement on July 3, 2019 indicated that~~During the ~~agency will seek public comment~~third quarter, the necessary construction stormwater permit was issued by the MPCA and ~~work expeditiously~~subsequent to ~~address~~ the ~~FEIS deficiency. Additionally,~~third quarter, we received two of our required permits from the ~~State permitting agencies’ previously stated their permitting efforts would continue in parallel with the MNPUC process and that work continues to advance accordingly. Following the~~Minnesota Department of ~~Commerce’s completion~~Natural Resources (DNR). The remaining United States Army Corps of ~~its spill modelling analysis, we expect further details regarding the MNPUC’s process~~Engineers (Army Corps) and ~~timelines, after which we expect~~DNR permitting ~~agencies~~processes are ongoing and continue to ~~re-align their timelines to the MNPUC process.~~ progress in parallel.

At this time, we cannot determine when all necessary permits to commence construction will be ~~issued pending receipt of further information~~issued. Once we receive all necessary permits and the Authorization to Construct from the MNPUC, ~~on a timeline~~we expect Minnesota construction to ~~complete~~take 6 to 9 months. At this ~~work.~~

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

OTHER ANNOUNCED PROJECTS UNDER DEVELOPMENT

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

~~LIQUIDS PIPELINES~~RENEWABLE POWER GENERATION

•

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

~~GAS TRANSMISSION AND MIDSTREAM~~•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. Closing of the transaction is subject to customary regulatory approvals and is expected to occur in the fourth quarter of 2020. CPP Investments will fund their 49% share of all ongoing future development capital. 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 both projects are now considered to be commercially secured. The remaining project, Courseulles, is expected to reach a final investment decision in 2021.

•

~~Rio Bravo Pipeline~~- the Rio Bravo Pipeline (Rio Bravo) and other natural gas pipelines in South Texas will transport natural gas to NextDecade's Rio Grande LNG project located in Brownsville, Texas. Rio Bravo is designed to transport 4.5 billion cubic feet per day of natural gas from the Agua Dulce area to Rio Grande LNG. Along with NextDecade Corporation, we announced a Memorandum of Understanding (MOU) to jointly pursue this development and we anticipate finalizing definitive documentation reflecting the terms of the MOU in the fourth quarter of 2019.

•

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

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

LIQUIDITY AND CAPITAL RESOURCES

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

Our financing plan is regularly updated to reflect evolving capital requirements and financial market conditions and identifies a variety of potential sources of debt and equity funding alternatives. Our current financing plan does not ~~require the use~~include any issuances of additional common equity ~~funding alternatives~~ and was the ~~leading principle behind~~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.

CAPITAL MARKET ACCESS

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

Credit Facilities and Liquidity

To ensure ongoing liquidity and to mitigate the risk of capital market disruption, we maintain ready access to funds through committed bank credit facilities and actively manage our bank funding sources to optimize pricing and other terms. The following table provides details of our committed credit facilities as at September 30, ~~2019:~~2020:


	Maturity Dates	Total Facilities	Draws¹	Available		Maturity Dates	Total Facilities	Draws1	Available
(millions of Canadian dollars)					(millions of Canadian dollars)
Enbridge Inc.	2021-2024	7,024	6,400	624	Enbridge Inc.	2021-2024	11,980	6,420	5,560
Enbridge (U.S.) Inc.	2021-2024	7,282	2,680	4,602	Enbridge (U.S.) Inc.	2022-2024	7,347	995	6,352
Enbridge Pipelines Inc.	2021	3,000	2,555	445	Enbridge Pipelines Inc.	20222	3,000	1,938	1,062
Enbridge Gas Inc.	2019-2021	2,017	1,280	737	Enbridge Gas Inc.	20222	2,000	969	1,031
Total committed credit facilities		19,323	12,915	6,408	Total committed credit facilities		24,327	10,322	14,005


	Three months ended September 30,		Nine months ended September 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	64,763	64,732	64,746	64,677
Shares issued on exercise of stock options	1	3	18	58
Balance at end of period	64,764	64,735	64,764	64,735
Additional paid-in capital
Balance at beginning of period	207	194	187	0
Stock-based compensation	6	7	25	28
Options exercised	(1)	(2)	(19)	(51)
Change in reciprocal interest	54	0	66	109
Repurchase of noncontrolling interest	0	0	0	65
Other	(1)	7	6	55
Balance at end of period	265	206	265	206
Deficit
Balance at beginning of period	(7,797)	(3,392)	(6,314)	(5,538)
Earnings attributable to controlling interests	1,084	1,045	1,492	4,863
Preference share dividends	(94)	(96)	(284)	(287)
Dividends paid to reciprocal shareholder	4	5	14	14
Common share dividends declared	(1,640)	(1,493)	(3,281)	(2,993)
Modified retrospective adoption of ASU 2016-13 Financial Instruments - Credit Losses (Note 2)	0	—	(66)	—
Other	1	(1)	(3)	9
Balance at end of period	(8,442)	(3,932)	(8,442)	(3,932)
Accumulated other comprehensive income/(loss) (Note 8)
Balance at beginning of period	1,753	124	(272)	2,672
Other comprehensive income/(loss) attributable to common shareholders, net of tax	(854)	465	1,171	(2,138)
Other	0	(7)	0	48
Balance at end of period	899	582	899	582
Reciprocal shareholding
Balance at beginning of period	(47)	(51)	(51)	(88)
Change in reciprocal interest	18	0	22	37
Balance at end of period	(29)	(51)	(29)	(51)
Total Enbridge Inc. shareholders’ equity	65,204	69,287	65,204	69,287
Noncontrolling interests
Balance at beginning of period	3,315	3,451	3,364	3,965
Earnings attributable to noncontrolling interests	20	15	25	50
Other comprehensive income/(loss) attributable to noncontrolling interests, net of tax
Change in unrealized loss on cash flow hedges	0	(1)	(3)	(6)
Foreign currency translation adjustments	(36)	27	57	(67)

	(36)	26	54	(73)
Comprehensive income/(loss) attributable to noncontrolling interests	(16)	41	79	(23)
Contributions	1	1	21	10
Distributions	(68)	(94)	(232)	(194)
Repurchase of noncontrolling interest	0	0	0	(65)
Redemption of preferred shares held by subsidiary	0	0	0	(300)
Other	(1)	(10)	(1)	(4)
Balance at end of period	3,231	3,389	3,231	3,389
Total equity	68,435	72,676	68,435	72,676
Dividends paid per common share	0.810	0.738	2.430	2.214
Earnings per common share attributable to common shareholders (Note 5)	0.49	0.47	0.60	2.27
Diluted earnings per common share attributable to common shareholders (Note 5)	0.49	0.47	0.60	2.27


	Nine months ended September 30,					Nine months ended September 30,
	2019		2018				2020	2019
(unaudited; millions of Canadian dollars)					(unaudited; millions of Canadian dollars)
Operating activities					Operating activities
Earnings	4,913		2,050		Earnings		1,517	4,913
Adjustments to reconcile earnings to net cash provided by operating activities:					Adjustments to reconcile earnings to net cash provided by operating activities:
Depreciation and amortization	2,526		2,452		Depreciation and amortization		2,766	2,526
Deferred income tax (recovery)/expense	983		(51	)	Deferred income tax (recovery)/expense		(82)	983
Changes in unrealized (gain)/loss on derivative instruments, net (Note 11)	(1,005	)	319
Changes in unrealized (gain)/loss on derivative instruments, net (Note 10)					Changes in unrealized (gain)/loss on derivative instruments, net (Note 10)		200	(1,005)
Earnings from equity investments	(1,159	)	(1,076	)	Earnings from equity investments		(805)	(1,159)
Distributions from equity investments	1,442		1,090		Distributions from equity investments		1,145	1,442
Impairment of equity investments (Note 9)					Impairment of equity investments (Note 9)		2,351	0
Impairment of long-lived assets	105		1,076		Impairment of long-lived assets		0	105
Impairment of goodwill	—		1,019
Loss on dispositions	—		76

Other	51		101		Other		222	51
Changes in operating assets and liabilities	(451	)	943		Changes in operating assets and liabilities		213	(451)
Net cash provided by operating activities	7,405		7,999		Net cash provided by operating activities		7,527	7,405
Investing activities					Investing activities
Capital expenditures	(3,928	)	(4,584	)	Capital expenditures		(3,790)	(3,928)
Long-term investments and restricted long-term investments	(1,018	)	(1,091	)	Long-term investments and restricted long-term investments		(413)	(1,018)
Distributions from equity investments in excess of cumulative earnings	285		1,243		Distributions from equity investments in excess of cumulative earnings		438	285
Additions to intangible assets	(136	)	(491	)	Additions to intangible assets		(154)	(136)
Proceeds from dispositions	—		1,913		Proceeds from dispositions		265	0
Other	—		(12	)
Affiliate loans, net	(232	)	(50	)
Loans to affiliates, net					Loans to affiliates, net		10	(232)
Net cash used in investing activities	(5,029	)	(3,072	)	Net cash used in investing activities		(3,644)	(5,029)
Financing activities					Financing activities
Net change in short-term borrowings	245		(196	)	Net change in short-term borrowings		71	245
Net change in commercial paper and credit facility draws	3,365		(2,358	)	Net change in commercial paper and credit facility draws		231	3,365
Debenture and term note issues, net of issue costs	2,553		3,537		Debenture and term note issues, net of issue costs		4,834	2,553
Debenture and term note repayments	(2,994	)	(3,757	)	Debenture and term note repayments		(3,517)	(2,994)
Sale of noncontrolling interests in subsidiaries	—		1,289
Contributions from noncontrolling interests	10		23		Contributions from noncontrolling interests		21	10
Distributions to noncontrolling interests	(194	)	(637	)	Distributions to noncontrolling interests		(232)	(194)
Contributions from redeemable noncontrolling interests	—		62
Distributions to redeemable noncontrolling interests	—		(264	)
Common shares issued	18		17		Common shares issued		3	18
Preference share dividends	(287	)	(268	)	Preference share dividends		(284)	(287)
Common share dividends	(4,480	)	(2,254	)	Common share dividends		(4,920)	(4,480)
Redemption of preferred shares held by subsidiary (Note 10)	(300	)	—
Redemption of preferred shares held by subsidiary					Redemption of preferred shares held by subsidiary		0	(300)
Other	(60	)	(5	)	Other		(52)	(60)
Net cash used in financing activities	(2,124	)	(4,811	)	Net cash used in financing activities		(3,845)	(2,124)
Effect of translation of foreign denominated cash and cash equivalents and restricted cash	(17	)	23		Effect of translation of foreign denominated cash and cash equivalents and restricted cash		(22)	(17)
Net increase in cash and cash equivalents and restricted cash	235		139		Net increase in cash and cash equivalents and restricted cash		16	235
Cash and cash equivalents and restricted cash at beginning of period	637		587		Cash and cash equivalents and restricted cash at beginning of period		676	637
Cash and cash equivalents and restricted cash at end of period	872		726		Cash and cash equivalents and restricted cash at end of period		692	872


	September 30, 2019		December 31, 2018			September 30, 2020	December 31, 2019
(unaudited; millions of Canadian dollars; number of shares in millions)					(unaudited; millions of Canadian dollars; number of shares in millions)
Assets					Assets
Current assets					Current assets
Cash and cash equivalents	815		518		Cash and cash equivalents	657	648
Restricted cash	57		119		Restricted cash	35	28
Accounts receivable and other	5,833		6,517		Accounts receivable and other	4,333	6,781
Accounts receivable from affiliates	89		79		Accounts receivable from affiliates	31	69
Inventory	1,261		1,339		Inventory	1,368	1,299
	8,055		8,572			6,424	8,825
Property, plant and equipment, net	94,379		94,540		Property, plant and equipment, net	95,990	93,723
Long-term investments	16,831		16,707		Long-term investments	14,513	16,528
Restricted long-term investments	413		323		Restricted long-term investments	527	434
Deferred amounts and other assets	9,866		8,558		Deferred amounts and other assets	8,089	7,433
Intangible assets, net	2,216		2,372		Intangible assets, net	2,122	2,173
Goodwill	33,668		34,459		Goodwill	33,832	33,153
Deferred income taxes	1,213		1,374		Deferred income taxes	991	1,000
Total assets	166,641		166,905		Total assets	162,488	163,269

Liabilities and equity					Liabilities and equity
Current liabilities					Current liabilities
Short-term borrowings	1,269		1,024		Short-term borrowings	969	898
Accounts payable and other	7,130		9,863		Accounts payable and other	6,381	10,063
Accounts payable to affiliates	47		40		Accounts payable to affiliates	4	21
Interest payable	566		669		Interest payable	628	624
Current portion of long-term debt	4,536		3,259		Current portion of long-term debt	3,616	4,404
	13,548		14,855			11,598	16,010
Long-term debt	60,879		60,327		Long-term debt	62,967	59,661
Other long-term liabilities	9,433		8,834		Other long-term liabilities	9,253	8,324
Deferred income taxes	10,105		9,454		Deferred income taxes	10,235	9,867
	93,965		93,470			94,053	93,862
Contingencies (Note 15)
Contingencies (Note 13)					Contingencies (Note 13)
Equity					Equity
Share capital					Share capital
Preference shares	7,747		7,747		Preference shares	7,747	7,747
Common shares (2,024 and 2,022 outstanding at September 30, 2019 and December 31, 2018, respectively)	64,735		64,677
Common shares (2,025 outstanding at September 30, 2020 and December 31, 2019)					Common shares (2,025 outstanding at September 30, 2020 and December 31, 2019)	64,764	64,746
Additional paid-in capital	206		—		Additional paid-in capital	265	187
Deficit	(3,932	)	(5,538	)	Deficit	(8,442)	(6,314)
Accumulated other comprehensive income (Note 9)	582		2,672
Accumulated other comprehensive income/(loss) (Note 8)					Accumulated other comprehensive income/(loss) (Note 8)	899	(272)
Reciprocal shareholding	(51	)	(88	)	Reciprocal shareholding	(29)	(51)
Total Enbridge Inc. shareholders’ equity	69,287		69,470		Total Enbridge Inc. shareholders’ equity	65,204	66,043
Noncontrolling interests	3,389		3,965		Noncontrolling interests	3,231	3,364
	72,676		73,435			68,435	69,407
Total liabilities and equity	166,641		166,905		Total liabilities and equity	162,488	163,269


	Liquids Pipelines	Gas Transmission and Midstream	Gas Distribution and Storage	Renewable Power Generation	Energy Services	Eliminations and Other	Consolidated
Nine months ended September 30, 2020
(millions of Canadian dollars)
Transportation revenues	6,815	3,458	494	0	0	0	10,767
Storage and other revenues	72	209	154	0	0	0	435
Gas gathering and processing revenues	0	19	0	0	0	0	19
Gas distribution revenue	0	0	2,551	0	0	0	2,551
Electricity and transmission revenues	0	0	0	150	0	0	150

Total revenue from contracts with customers	6,887	3,686	3,199	150	0	0	13,922
Commodity sales	0	0	0	0	14,920	0	14,920
Other revenues1,2	(59)	35	(1)	279	1	(18)	237
Intersegment revenues	424	1	8	0	22	(455)	—
Total revenues	7,252	3,722	3,206	429	14,943	(473)	29,079



		Dividend per share
Common Shares1		$0.81000	~~$0.73800~~
Preference Shares, Series A		$0.34375	~~$0.34375~~
Preference Shares, Series B		$0.21340	~~$0.21340~~
Preference Shares, Series C¹2		$0.15975	~~$0.25243~~
Preference Shares, Series D		$0.27875	~~$0.27875~~
Preference Shares, Series F		$0.29306	~~$0.29306~~
Preference Shares, Series H		$0.27350	~~$0.27350~~
Preference Shares, Series J		US$0.30540	~~US$0.30540~~
Preference Shares, Series L		US$0.30993	~~US$0.30993~~
Preference Shares, Series N		$0.31788	~~$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 P11²3		$0.24613	~~$0.27369~~
Preference Shares, Series R13³4		$0.19019	~~$0.25456~~
~~Preference Shares, Series 1~~	~~US$0.37182~~
Preference Shares, Series 315⁴5		$0.18644	~~$0.23356~~
Preference Shares, Series 517⁵		$0.32188	~~US$0.33596~~
Preference Shares, Series 719⁶		$0.30625	~~$0.27806~~
~~Preference Shares, Series 9~~	~~$0.27500~~
~~Preference Shares, Series 11~~	~~$0.27500~~
~~Preference Shares, Series 13~~	~~$0.27500~~
~~Preference Shares, Series 15~~	~~$0.27500~~
~~Preference Shares, Series 17~~	~~$0.32188~~
~~Preference Shares, Series 19~~	~~$0.30625~~


3	~~The quarterly dividend per share paid on Series R was increased to $0.25456 from $0.25000 on June 1, 2019, due to the reset of the annual dividend on June 1, 2019, and every five years thereafter.~~


4	The quarterly dividend per share paid on Series 3 was decreased to $0.23356 from $0.25000 on September 1, 2019, due to the reset of the annual dividend on September 1, 2019, and every five year thereafter.



	September 30, 2019		December 31, 2018
(millions of Canadian dollars)
Accounts receivable and other (current assets held for sale)	72		117
Deferred amounts and other assets (long-term assets held for sale)¹	2,473		2,383
Accounts payable and other (current liabilities held for sale)	(47	)	(63	)
Other long-term liabilities (long-term liabilities held for sale)	(90	)	(96	)
Net assets held for sale	2,408		2,341


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


	Maturity	Total Facilities	Draws¹	Available		Maturity	Total Facilities	Draws1	Available
(millions of Canadian dollars)					(millions of Canadian dollars)
Enbridge Inc.	2021-2024	7,024	6,400	624	Enbridge Inc.	2021-2024	11,980	6,420	5,560
Enbridge (U.S.) Inc.	2021-2024	7,282	2,680	4,602	Enbridge (U.S.) Inc.	2022-2024	7,347	995	6,352
Enbridge Pipelines Inc.	2021	3,000	2,555	445	Enbridge Pipelines Inc.	20222	3,000	1,938	1,062
Enbridge Gas Inc.	2019-2021	2,017	1,280	737	Enbridge Gas Inc.	20222	2,000	969	1,031
Total committed credit facilities		19,323	12,915	6,408	Total committed credit facilities		24,327	10,322	14,005


	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)	0	(317)	1,396	67	(345)	(272)
Other comprehensive income/(loss) retained in AOCI	(696)	7	(228)	1,760	8	—	851
Other comprehensive (income)/loss reclassified to earnings
Interest rate contracts1	179	—	—	—	—	—	179
Commodity contracts2	(1)	—	—	—	—	—	(1)
Foreign exchange contracts3	3	—	—	—	—	—	3
Other contracts4	(1)	—	—	—	—	—	(1)
Amortization of pension and other postretirement benefits (OPEB) actuarial loss and prior service costs5	—	—	—	—	—	13	13
	(516)	7	(228)	1,760	8	13	1,044
Tax impact
Income tax on amounts retained in AOCI	167	0	7	0	(2)	0	172
Income tax on amounts reclassified to earnings	(42)	0	0	0	0	(3)	(45)
	125	0	7	0	(2)	(3)	127

Balance as at September 30, 2020	(1,464)	7	(538)	3,156	73	(335)	899



	Three months ended September 30,			Nine months ended September 30,
	2019¹	2018		2019¹	2018
(millions of Canadian dollars)
Unrealized gain/(loss) on derivative	—	3		—	(9	)
Unrealized gain/(loss) on hedged item	—	(3	)	—	8
Realized gain/(loss) on derivative	—	(3	)	—	(4	)
Realized gain/(loss) on hedged item	—	3		—	4


1	~~For the three and nine months ended September 30, 2019, there are 0 outstanding fair value hedges.~~


1	For the respective nine months ended periods, reported within Transportation and other services revenues (2019 - $366 million gain; 2018 - $346 million loss) and Net foreign currency gain/(loss) (2019 - $483 million gain; 2018 - $10 million loss) in the Consolidated Statements of Earnings.


2	~~Reported as an (increase)/decrease within Interest expense in the Consolidated Statements of Earnings.~~


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



September 30, 2019	Level 1		Level 2		Level 3		Total Gross Derivative Instruments
(millions of Canadian dollars)
Financial assets
Current derivative assets
Foreign exchange contracts	—		76		—		76
Interest rate contracts	—		1		—		1
Commodity contracts	9		44		132		185
	9		121		132		262
Long-term derivative assets
Foreign exchange contracts	—		140		—		140
Commodity contracts	—		23		12		35
Other contracts	—		2		—		2
	—		165		12		177
Financial liabilities
Current derivative liabilities
Foreign exchange contracts	—		(553	)	—		(553	)
Interest rate contracts	—		(258	)	—		(258	)
Commodity contracts	(2	)	(21	)	(117	)	(140	)
Other contracts	—		(1	)	—		(1	)
	(2	)	(833	)	(117	)	(952	)
Long-term derivative liabilities
Foreign exchange contracts	��		(1,536	)	—		(1,536	)
Interest rate contracts	—		(686	)	—		(686	)
Commodity contracts	—		(7	)	(91	)	(98	)
Other contracts	—		(2	)	—		(2	)
	—		(2,231	)	(91	)	(2,322	)
Total net financial liabilities
Foreign exchange contracts	—		(1,873	)	—		(1,873	)
Interest rate contracts	—		(943	)	—		(943	)
Commodity contracts	7		39		(64	)	(18	)
Other contracts	—		(1	)	—		(1	)
	7		(2,778	)	(64	)	(2,835	)


September 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	(5)	Forward gas price	2.00	5.51	3.53	$/mmbtu2
Crude	13	Forward crude price	24.11	54.70	39.72	$/barrel

Power	(49)	Forward power price	21.76	65.93	53.79	$/MW/H
Commodity contracts - physical1
Natural gas	4	Forward gas price	1.04	6.77	3.52	$/mmbtu2
Crude	(29)	Forward crude price	35.01	57.60	42.50	$/barrel
NGL	2	Forward NGL price	0.26	1.32	0.61	$/gallon
	(64)


1	~~Financial and physical forward commodity contracts are valued using a market approach valuation technique.~~



	September 30, 2019		January 1, 2019
(millions of Canadian dollars, except lease term and discount rate)
Operating leases
Operating lease right-of-use assets, net¹	733		771

Operating lease liabilities - current²	99		86
Operating lease liabilities - long-term³	705		770
Total operating lease liabilities	804		856

Weighted average remaining lease term
Operating leases	13 years		14 years

Weighted average discount rate
Operating leases	4.3	%	4.3	%


1	~~Right-of-use assets are reported under Deferred amounts and other assets in the Consolidated Statements of Financial Position.~~


2	~~Current lease liabilities are reported under Accounts payable and other in the Consolidated Statements of Financial Position.~~


3	~~Long-term lease liabilities are reported under Other long-term liabilities in the Consolidated Statements of Financial Position.~~


1	~~For the three months remaining in the 2019 fiscal year.~~



	Three months ended September 30, 2019	Nine months ended September 30, 2019
(millions of Canadian dollars)
Operating lease income	67	196
Variable lease income	77	262
Total lease income	144	458



~~SEP Notes~~¹	~~EEP Notes~~²
~~Floating Rate Senior Notes due 2020~~	~~5.200% Notes due 2020~~
~~4.600% Senior Notes due 2021~~	~~4.375% Notes due 2020~~
~~4.750% Senior Notes due 2024~~	~~4.200% Notes due 2021~~
~~3.500% Senior Notes due 2025~~	~~5.875% Notes due 2025~~
~~3.375% Senior Notes due 2026~~	~~5.950% Notes due 2033~~
~~5.950% Senior Notes due 2043~~	~~6.300% Notes due 2034~~
~~4.500% Senior Notes due 2045~~	~~7.500% Notes due 2038~~
	~~5.500% Notes due 2040~~
	~~7.375% Notes due 2045~~


1	~~As at September 30, 2019, the aggregate outstanding principal amount of SEP notes was approximately US$3.9 billion.~~



~~USD Denominated~~¹	~~CAD Denominated~~²
~~Senior Floating Rate Notes due 2020~~	~~4.530% Senior Notes due 2020~~
~~Senior Floating Rate Notes due 2020~~	~~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~~
~~4.250% Senior Notes due 2026~~	~~3.190% Senior Notes due 2022~~
~~3.700% Senior Notes due 2027~~	~~3.940% Senior Notes due 2023~~
~~4.500% Senior Notes due 2044~~	~~3.940% Senior Notes due 2023~~
~~5.500% Senior Notes due 2046~~	~~3.950% Senior Notes due 2024~~
	~~3.200% Senior Notes due 2027~~
	~~6.100% Senior Notes due 2028~~
	~~7.220% Senior Notes due 2030~~
	~~7.200% Senior Notes due 2032~~
	~~5.570% Senior Notes due 2035~~
	~~5.750% Senior Notes due 2039~~
	~~5.120% Senior Notes due 2040~~
	~~4.240% Senior Notes due 2042~~
	~~4.570% Senior Notes due 2044~~
	~~4.870% Senior Notes due 2044~~
	~~4.560% Senior Notes due 2064~~


5.	~~Consolidating and elimination entries required to consolidate the Parent Issuer and Guarantor and its subsidiaries, including the Subsidiary Issuers and Guarantors, and~~


6.	~~Enbridge Inc. and subsidiaries on a consolidated basis.~~



	Parent Issuer and Guarantor		Subsidiary Issuer and Guarantor - SEP		Subsidiary Issuer and Guarantor - EEP		Subsidiary Non-Guarantors		Consolidating and elimination adjustments		Consolidated - Enbridge
(millions of Canadian dollars)
Operating revenues
Commodity sales	—		—		—		7,396		—		7,396
Gas distribution sales	—		—		—		454		—		454
Transportation and other services	—		—		—		3,748		—		3,748
Total operating revenues	—		—		—		11,598		—		11,598
Operating Expenses
Commodity costs	—		—		—		7,216		—		7,216
Gas distribution costs	—		—		—		104		—		104
Operating and administrative	69		1		1		1,670		—		1,741
Depreciation and amortization	15		—		—		829		—		844
Impairment of long-lived assets	—		—		—		105		—		105
Total operating expenses	84		1		1		9,924		—		10,010
Operating income/(loss)	(84	)	(1	)	(1	)	1,674		—		1,588
Income from equity investments	2		35		—		297		(1	)	333
Equity earnings from consolidated subsidiaries	1,109		284		296		451		(2,140	)	—
Other
Net foreign currency gain/(loss)	(163	)	—		—		1		119		(43	)
Other, including other income from affiliates	512		—		46		177		(654	)	81
Interest expense	(299	)	(79	)	(139	)	(786	)	659		(644	)
Earnings before income taxes	1,077		239		202		1,814		(2,017	)	1,315
Income tax (expense)/recovery	(32	)	10		—		(325	)	92		(255	)
Earnings	1,045		249		202		1,489		(1,925	)	1,060
Earnings attributable to noncontrolling interests and redeemable noncontrolling interests	—		—		—		—		(15	)	(15	)
Earnings attributable to controlling interests	1,045		249		202		1,489		(1,940	)	1,045
Preference share dividends	(96	)	—		—		—		—		(96	)
Earnings attributable to common shareholders	949		249		202		1,489		(1,940	)	949
Earnings	1,045		249		202		1,489		(1,925	)	1,060
Total other comprehensive income/(loss)	465		(46	)	8		162		(98	)	491
Comprehensive income	1,510		203		210		1,651		(2,023	)	1,551
Comprehensive income attributable to noncontrolling interests	—		—		—		—		(41	)	(41	)
Comprehensive income attributable to controlling interests	1,510		203		210		1,651		(2,064	)	1,510


•	~~The factor above was partially offset by stronger contributions from our operating segments and contributions from new assets placed into service~~ •The factor above was partially offset by the impact of certain unusual, infrequent or other non-operating factors as discussed under Results of Operations. ~~Results of Operations~~.


•	~~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.~~


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

Receivables

Contract Assets

Contract Liabilities

(millions of Canadian dollars)

Balance as at December 31, 2018

Balance as at September 30, 2019