enb-20230630

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549


FORM			10-Q


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

For the quarterly period ended June 30, 2023


☐						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 001-15254



ENBRIDGE INC.
(Exact Name of Registrant as Specified in Its Charter)


Canada						98-0377957
(State or Other Jurisdiction of Incorporation or Organization)						(I.R.S. Employer Identification No.)

200, 425 - 1st Street S.W.

Calgary, Alberta, Canada T2P 3L8

(Address of Principal Executive Offices) (Zip Code)

(403) 231-3900

(Registrant’s Telephone Number, Including Area Code)

_______________________________

Securities registered pursuant to Section 12(b) of the Act:

Title of each class

Trading Symbol(s)

Name of each exchange on which registered

Common Shares

ENB

New York Stock Exchange

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 2,022,660,553 common shares outstanding as at July 28, 2023.


	PART I	PAGE

Item 1.	Financial Statements	6
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	35
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	55
Item 4.	Controls and Procedures	56

	PART II

Item 1.	Legal Proceedings	57
Item 1A.	Risk Factors	57
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	57
Item 3.	Defaults Upon Senior Securities	58
Item 4.	Mine Safety Disclosures	58
Item 5.	Other Information	58
Item 6.	Exhibits	58
	Signatures	59

GLOSSARY


AG			Attorney General
AOCI			Accumulated other comprehensive income/(loss)



Aux Sable			Aux Sable Canada LP, Aux Sable Liquid Products LP and Aux Sable Midstream LLC
CER			Canada Energy Regulator


DCP			DCP Midstream, LP
EBITDA			Earnings before interest, income taxes and depreciation and amortization

EEP			Enbridge Energy Partners, L.P.




Enbridge			Enbridge Inc.
Enbridge Gas			Enbridge Gas Inc.


Exchange Act			United States Securities Exchange Act of 1934, as amended















NCIB			Normal course issuer bid


OCI			Other comprehensive income/(loss)


OPEB			Other postretirement benefits




SEP			Spectra Energy Partners, LP









Texas Eastern			Texas Eastern Transmission, LP
the Band			Bad River Band of the Lake Superior Tribe of Chippewa Indians
the Court			United States District Court for the Western District Wisconsin

the Partnerships			Spectra Energy Partners, LP (SEP) and Enbridge Energy Partners, L.P. (EEP)
the Reservation			Bad River Reservation
Tres Palacios			Tres Palacios Holdings LLC
US			United States

CONVENTIONS

The terms "we", "our", "us" and "Enbridge" as used in this report refer collectively to Enbridge Inc. and its subsidiaries 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 "$" are to Canadian dollars and all references to "US$" are to United States (US) 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; expected supply of, demand for, exports of and prices of crude oil, natural gas, natural gas liquids (NGL), liquified natural gas (LNG) and renewable energy; energy transition and lower-carbon energy, and our approach thereto; environmental, social and governance goals, practices and performance; industry and market conditions; anticipated utilization of our assets; dividend growth and payout policy; 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, benefits and in-service dates related to announced projects and projects under construction; expected capital expenditures; investable capacity and capital allocation priorities; share repurchases under our normal course issuer bid (NCIB); expected equity funding requirements for our commercially secured growth program; expected future growth, development and expansion opportunities; expected optimization and efficiency opportunities; expectations about our joint venture partners’ ability to complete and finance projects under construction; expected closing of acquisitions and dispositions and the timing thereof; expected benefits of transactions; expected future actions of regulators and courts, and the timing and impact thereof; toll and rate cases discussions and proceedings and anticipated timeline and impact therefrom, including Mainline Tolling and those relating to the Gas Transmission and Midstream and Gas Distribution and Storage businesses; operational, industry, regulatory, climate change and other risks associated with our businesses; and our assessment of the potential impact of the various risk factors identified herein.

Although we believe these forward-looking statements are reasonable based on the information available on the date such statements are made and processes used to prepare the information, such statements are not guarantees of future performance and readers are cautioned against placing undue reliance on forward-looking statements. By their nature, these statements involve a variety of assumptions, known and unknown risks and uncertainties and other factors, which may cause actual results, levels of activity and achievements to differ materially from those expressed or implied by such statements. Material assumptions include assumptions about the following: the expected supply of, demand for, export of and prices of crude oil, natural gas, NGL, LNG and renewable energy; anticipated utilization of assets; exchange rates; inflation; interest rates; availability and price of labor and construction materials; the stability of our supply chain; operational reliability; 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 of transactions; governmental legislation; litigation; estimated future dividends and impact of our dividend policy on our future cash flows; our credit ratings; capital project funding; hedging program; expected earnings before interest, income taxes and depreciation and amortization (EBITDA); expected earnings/(loss); expected future cash flows; and expected distributable cash flow. Assumptions regarding the expected supply of and demand for crude oil, natural gas, NGL, LNG 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. The most relevant assumptions associated with forward-looking statements regarding announced projects and projects under construction, including estimated completion dates and expected capital expenditures, include the following: the availability and price of labor and construction materials; the stability of

our supply chain; the effects of inflation and foreign exchange rates on labor and material costs; the effects of interest rates on borrowing costs; and the impact of weather and customer, government, court and regulatory approvals on construction and in-service schedules and cost recovery regimes.

Our forward-looking statements are subject to risks and uncertainties pertaining to the successful execution of our strategic priorities, operating performance; legislative and regulatory parameters; litigation; acquisitions, dispositions and other transactions and the realization of anticipated benefits therefrom; operational dependence on third parties; 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; exchange rates; inflation; interest rates; commodity prices; access to and cost of capital; political decisions; global geopolitical conditions; and the supply of, demand for and prices of commodities and other alternative energy, 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 US securities regulators. The impact of any one assumption, 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 assumes no obligation to publicly update or revise any forward-looking statement made in this quarterly report on Form 10-Q or otherwise, whether as a result of new information, future events or otherwise. All forward-looking statements, whether written or oral, attributable to us or persons acting on our behalf, are expressly qualified in their entirety by these cautionary statements.

NON-GAAP AND OTHER FINANCIAL MEASURES

Part I. Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations (MD&A) in this quarterly report on Form 10-Q makes reference to non-GAAP and other financial measures, including EBITDA. EBITDA is defined as earnings before interest, income taxes and depreciation and amortization. Management uses EBITDA to assess performance of Enbridge and to set targets. Management believes the presentation of EBITDA gives useful information to investors as it provides increased transparency and insight into the performance of Enbridge.

The non-GAAP and other financial measures are not measures that have a standardized meaning prescribed by the accounting principles generally accepted in the United States of America (US GAAP) and are not US GAAP measures. Therefore, these measures may not be comparable with similar measures presented by other issuers. A reconciliation of historical non-GAAP and other financial measures to the most directly comparable GAAP measures is set out in this MD&A and is available on our website. Additional information on non-GAAP and other financial measures may be found on our website, www.sedar.com or www.sec.gov.

PART I - FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

ENBRIDGE INC.

CONSOLIDATED STATEMENTS OF EARNINGS


	Three months ended June 30,		Six months ended June 30,
	2023	2022	2023	2022
(unaudited; millions of Canadian dollars, except per share amounts)
Operating revenues
Commodity sales	4,679	8,108	9,462	16,433
Gas distribution sales	792	905	3,071	3,003
Transportation and other services	4,961	4,202	9,974	8,876
Total operating revenues (Note 2)	10,432	13,215	22,507	28,312
Operating expenses
Commodity costs	4,549	8,181	9,185	16,472
Gas distribution costs	368	456	1,962	1,912
Operating and administrative	2,028	1,994	4,065	3,869
Depreciation and amortization	1,137	1,064	2,283	2,119

Total operating expenses	8,082	11,695	17,495	24,372
Operating income	2,350	1,520	5,012	3,940
Income from equity investments	478	510	995	1,001

Other income/(expense) (Note 10)	575	(499)	677	(41)
Interest expense	(883)	(791)	(1,788)	(1,510)
Earnings before income taxes	2,520	740	4,896	3,390
Income tax expense	(519)	(133)	(1,029)	(726)
Earnings	2,001	607	3,867	2,664
Earnings attributable to noncontrolling interests	(66)	(12)	(115)	(40)
Earnings attributable to controlling interests	1,935	595	3,752	2,624
Preference share dividends	(87)	(145)	(171)	(247)
Earnings attributable to common shareholders	1,848	450	3,581	2,377
Earnings per common share attributable to common shareholders (Note 4)	0.91	0.22	1.77	1.17
Diluted earnings per common share attributable to common shareholders (Note 4)	0.91	0.22	1.77	1.17

The accompanying notes are an integral part of these interim consolidated financial statements.

ENBRIDGE INC.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME


	Three months ended June 30,		Six months ended June 30,
	2023	2022	2023	2022
(unaudited; millions of Canadian dollars)
Earnings	2,001	607	3,867	2,664
Other comprehensive income/(loss), net of tax
Change in unrealized gain on cash flow hedges	166	352	121	646
Change in unrealized gain/(loss) on net investment hedges	385	(386)	400	(253)

Excluded components of fair value hedges	2	(4)	9	(5)
Reclassification to earnings of loss on cash flow hedges	12	52	19	109
Reclassification to earnings of pension and other postretirement benefits (OPEB) amounts	(4)	(3)	(8)	(5)

Foreign currency translation adjustments	(1,458)	1,881	(1,517)	1,173
Other comprehensive income/(loss), net of tax	(897)	1,892	(976)	1,665
Comprehensive income	1,104	2,499	2,891	4,329
Comprehensive income attributable to noncontrolling interests	(34)	(58)	(98)	(71)
Comprehensive income attributable to controlling interests	1,070	2,441	2,793	4,258
Preference share dividends	(87)	(145)	(171)	(247)
Comprehensive income attributable to common shareholders	983	2,296	2,622	4,011

The accompanying notes are an integral part of these interim consolidated financial statements.

ENBRIDGE INC.

CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY


	Three months ended June 30,		Six months ended June 30,
	2023	2022	2023	2022
(unaudited; millions of Canadian dollars, except per share amounts)
Preference shares
Balance at beginning of period	6,818	7,010	6,818	7,747
Redemption of preference shares	—	(192)	—	(929)
Balance at end of period	6,818	6,818	6,818	6,818
Common shares
Balance at beginning of period	64,774	64,801	64,760	64,799
Shares issued on exercise of stock options	—	12	2	48
Shares issued on vesting of restricted stock units (RSU)	—	—	12	—
Share purchases at stated value	(80)	(58)	(80)	(88)
Other	—	—	—	(4)
Balance at end of period	64,694	64,755	64,694	64,755
Additional paid-in capital
Balance at beginning of period	274	316	275	365
Stock-based compensation	18	5	18	18
Options exercised	(1)	(11)	(2)	(45)

Other	—	(5)	—	(33)
Balance at end of period	291	305	291	305
Deficit
Balance at beginning of period	(13,753)	(9,082)	(15,486)	(10,989)
Earnings attributable to controlling interests	1,935	595	3,752	2,624
Preference share dividends	(87)	(145)	(171)	(247)
Common share dividends declared	(1,796)	(1,743)	(1,796)	(1,743)

Share purchases in excess of stated value	(45)	(43)	(45)	(63)

Balance at end of period	(13,746)	(10,418)	(13,746)	(10,418)
Accumulated other comprehensive income/(loss) (Note 7)
Balance at beginning of period	3,426	(1,308)	3,520	(1,096)
Other comprehensive income/(loss) attributable to common shareholders, net of tax	(865)	1,846	(959)	1,634
Balance at end of period	2,561	538	2,561	538




Total Enbridge Inc. shareholders’ equity	60,618	61,998	60,618	61,998
Noncontrolling interests
Balance at beginning of period	3,486	2,536	3,511	2,542
Earnings attributable to noncontrolling interests	66	12	115	40
Other comprehensive income/(loss) attributable to noncontrolling interests, net of tax
Change in unrealized gain/(loss) on cash flow hedges	1	(8)	18	(6)
Foreign currency translation adjustments	(33)	54	(35)	37
	(32)	46	(17)	31
Comprehensive income attributable to noncontrolling interests	34	58	98	71
Distributions	(103)	(67)	(195)	(127)
Contributions	4	2	8	8

Other	(1)	10	(2)	45
Balance at end of period	3,420	2,539	3,420	2,539
Total equity	64,038	64,537	64,038	64,537
Dividends paid per common share	0.89	0.86	1.78	1.72

The accompanying notes are an integral part of these interim consolidated financial statements.

ENBRIDGE INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS


	Six months ended June 30,
	2023	2022
(unaudited; millions of Canadian dollars)
Operating activities
Earnings	3,867	2,664
Adjustments to reconcile earnings to net cash provided by operating activities:
Depreciation and amortization	2,283	2,119
Deferred income tax expense	919	469
Unrealized derivative fair value (gain)/loss, net (Note 8)	(1,135)	415
Income from equity investments	(995)	(1,001)
Distributions from equity investments	1,066	878




Other	72	67
Changes in operating assets and liabilities	1,228	(138)
Net cash provided by operating activities	7,305	5,473
Investing activities
Capital expenditures	(2,093)	(2,002)
Long-term investments and restricted long-term investments	(472)	(388)
Distributions from equity investments in excess of cumulative earnings	752	296
Additions to intangible assets	(104)	(91)
Acquisitions	(487)	—


Affiliate loans, net	71	65

Net cash used in investing activities	(2,333)	(2,120)
Financing activities
Net change in short-term borrowings	(1,148)	105
Net change in commercial paper and credit facility draws	(2,847)	1,031
Debenture and term note issues, net of issue costs	5,598	2,642
Debenture and term note repayments	(2,281)	(1,333)
Contributions from noncontrolling interests	8	8
Distributions to noncontrolling interests	(195)	(127)
Common shares issued	—	3
Common shares repurchased	(125)	(151)
Preference share dividends	(171)	(173)
Common share dividends	(3,595)	(3,485)
Redemption of preference shares	—	(1,003)
Affiliate loans, net	50	—
Other	(64)	(122)
Net cash used in financing activities	(4,770)	(2,605)
Effect of translation of foreign denominated cash and cash equivalents and restricted cash	(19)	20
Net change in cash and cash equivalents and restricted cash	183	768
Cash and cash equivalents and restricted cash at beginning of period	907	320
Cash and cash equivalents and restricted cash at end of period	1,090	1,088

The accompanying notes are an integral part of these interim consolidated financial statements.

ENBRIDGE INC.

CONSOLIDATED STATEMENTS OF FINANCIAL POSITION


	June 30, 2023	December 31, 2022
(unaudited; millions of Canadian dollars; number of shares in millions)
Assets
Current assets
Cash and cash equivalents	1,030	861
Restricted cash	60	46
Trade receivables and unbilled revenues	3,725	5,616
Other current assets	2,775	3,255
Accounts receivable from affiliates	167	114
Inventory	1,211	2,255
	8,968	12,147
Property, plant and equipment, net	103,955	104,460
Long-term investments	15,258	15,936
Restricted long-term investments	664	593
Deferred amounts and other assets	9,185	9,542
Intangible assets, net	3,764	4,018
Goodwill	31,886	32,440
Deferred income taxes	262	472
Total assets	173,942	179,608

Liabilities and equity
Current liabilities
Short-term borrowings	848	1,996
Trade payables and accrued liabilities	3,660	6,172
Other current liabilities	2,559	5,220
Accounts payable to affiliates	48	105
Interest payable	824	763
Current portion of long-term debt	6,086	6,045
	14,025	20,301
Long-term debt	72,530	72,939
Other long-term liabilities	8,847	9,189
Deferred income taxes	14,502	13,781
	109,904	116,210
Contingencies (Note 11)
Equity
Share capital
Preference shares	6,818	6,818
Common shares (2,023 and 2,025 outstanding at June 30, 2023 and December 31, 2022, respectively)	64,694	64,760
Additional paid-in capital	291	275
Deficit	(13,746)	(15,486)
Accumulated other comprehensive income (Note 7)	2,561	3,520

Total Enbridge Inc. shareholders’ equity	60,618	59,887
Noncontrolling interests	3,420	3,511
	64,038	63,398
Total liabilities and equity	173,942	179,608

The accompanying notes are an integral part of these interim consolidated financial statements.

NOTES TO THE INTERIM CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

1. BASIS OF PRESENTATION

The accompanying unaudited interim consolidated financial statements of Enbridge Inc. ("we", "our", "us" and "Enbridge") have been prepared in accordance with generally accepted accounting principles in the United States of America (US GAAP) and Regulation S-X for interim consolidated financial information. They do not include all of the information and notes required by US GAAP for annual consolidated financial statements and should therefore be read in conjunction with our audited consolidated financial statements and notes for the year ended December 31, 2022. In the opinion of management, the interim consolidated financial statements contain all normal recurring adjustments necessary to present fairly our financial position, results of operations and cash flows for the interim periods reported. These interim consolidated financial statements follow the same significant accounting policies as those included in our audited consolidated financial statements for the year ended December 31, 2022. Amounts are stated in Canadian dollars unless otherwise noted.

Our operations and earnings for interim periods can be affected by seasonal fluctuations within the gas distribution utility businesses, as well as other factors such as supply of and demand for crude oil and natural gas, and may not be indicative of annual results.

Certain comparative figures in our interim consolidated financial statements have been reclassified to conform to the current year's presentation.

2. REVENUES

REVENUE FROM CONTRACTS WITH CUSTOMERS

Major Products and Services


Three months ended June 30, 2023	Liquids Pipelines	Gas Transmission and Midstream	Gas Distribution and Storage	Renewable Power Generation	Energy Services	Eliminations and Other	Consolidated
(millions of Canadian dollars)
Transportation revenue	3,002	1,290	169	—	—	—	4,461
Storage and other revenue	62	113	85	—	—	—	260

Gas distribution revenue	—	—	796	—	—	—	796
Electricity revenue	—	—	—	75	—	—	75

Total revenue from contracts with customers	3,064	1,403	1,050	75	—	—	5,592
Commodity sales	—	—	—	—	4,679	—	4,679
Other revenue1,2	79	7	(1)	76	—	—	161
Intersegment revenue	127	—	1	(1)	—	(127)	—
Total revenue	3,270	1,410	1,050	150	4,679	(127)	10,432


Three months ended June 30, 2022	Liquids Pipelines	Gas Transmission and Midstream	Gas Distribution and Storage	Renewable Power Generation	Energy Services	Eliminations and Other	Consolidated
(millions of Canadian dollars)
Transportation revenue	2,565	1,200	157	—	—	—	3,922
Storage and other revenue	64	83	99	—	—	—	246
Gas gathering and processing revenue	—	6	—	—	—	—	6
Gas distribution revenue	—	—	919	—	—	—	919
Electricity revenue	—	—	—	81	—	—	81

Total revenue from contracts with customers	2,629	1,289	1,175	81	—	—	5,174
Commodity sales	—	—	—	—	8,108	—	8,108
Other revenue1,2	(145)	11	(37)	74	30	—	(67)
Intersegment revenue	154	1	—	—	—	(155)	—
Total revenue	2,638	1,301	1,138	155	8,138	(155)	13,215


Six months ended June 30, 2023	Liquids Pipelines	Gas Transmission and Midstream	Gas Distribution and Storage	Renewable Power Generation	Energy Services	Eliminations and Other	Consolidated
(millions of Canadian dollars)
Transportation revenue	5,944	2,674	445	—	—	—	9,063
Storage and other revenue	126	208	184	—	—	—	518

Gas distribution revenue	—	—	3,083	—	—	—	3,083
Electricity revenue	—	—	—	141	—	—	141

Total revenue from contracts with customers	6,070	2,882	3,712	141	—	—	12,805
Commodity sales	—	—	—	—	9,462	—	9,462
Other revenue1,2	109	18	(41)	154	—	—	240
Intersegment revenue	256	1	4	(1)	18	(278)	—
Total revenue	6,435	2,901	3,675	294	9,480	(278)	22,507

Six months ended June 30, 2022	Liquids Pipelines	Gas Transmission and Midstream	Gas Distribution and Storage	Renewable Power Generation	Energy Services	Eliminations and Other	Consolidated
(millions of Canadian dollars)
Transportation revenue	5,250	2,394	408	—	—	—	8,052
Storage and other revenue	115	167	146	—	—	—	428
Gas gathering and processing revenue	—	21	—	—	—	—	21
Gas distribution revenue	—	—	3,017	—	—	—	3,017
Electricity revenue	—	—	—	143	—	—	143

Total revenue from contracts with customers	5,365	2,582	3,571	143	—	—	11,661
Commodity sales	—	—	—	—	16,433	—	16,433
Other revenue1,2	33	18	(33)	168	32	—	218
Intersegment revenue	295	1	11	—	10	(317)	—
Total revenue	5,693	2,601	3,549	311	16,475	(317)	28,312

1Includes realized and unrealized gains and losses from our hedging program which for the three months ended June 30, 2023 were a net $3 million gain (2022 - $198 million loss) and for the six months ended June 30, 2023 were a net $52 million loss (2022 - $104 million loss).

2Includes revenues from lease contracts for the three months ended June 30, 2023 and 2022 of $136 million and $143 million, respectively, and for the six months ended June 30, 2023 and 2022 of $280 million and $307 million, respectively.

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

Contract Balances


	Contract Receivables	Contract Assets	Contract Liabilities
(millions of Canadian dollars)
Balance as at June 30, 2023	2,182	229	2,283
Balance as at December 31, 2022	3,183	230	2,241

Contract receivables represent the amount of receivables derived from contracts with customers.

Contract assets represent the amount of revenues which has been recognized in advance of payments received for performance obligations we have fulfilled (or have partially fulfilled) and prior to the point in time at which our right to payment is unconditional. Amounts included in contract assets are transferred to accounts receivable when our right to receive the consideration becomes unconditional.

Contract liabilities represent payments received for performance obligations which have not been fulfilled. Contract liabilities primarily relate to make-up rights and deferred revenues. Revenue recognized during the three and six months ended June 30, 2023 included in contract liabilities at the beginning of the period was $53 million and $89 million, respectively. Increases in contract liabilities from cash received, net of amounts recognized as revenues, during the three and six months ended June 30, 2023 were $43 million and $167 million, respectively.

Performance Obligations

There were no material revenues recognized in the three and six months ended June 30, 2023 from performance obligations satisfied in previous periods.

Revenues to be Recognized from Unfulfilled Performance Obligations

Total revenues from performance obligations expected to be fulfilled in future periods is $57.9 billion, of which $3.9 billion and $6.7 billion are expected to be recognized during the remaining six months ending December 31, 2023 and the year ending December 31, 2024, respectively.

The revenues excluded from the amounts above based on optional exemptions available under Accounting Standards Codification 606, as explained below, represent a significant portion of our overall revenues and revenues from contracts with customers. Certain revenues such as flow-through operating costs charged to shippers are recognized at the amount for which we have the right to invoice our customers and are excluded from the amounts for revenues to be recognized in the future from unfulfilled performance obligations above. Variable consideration is excluded from the amounts above due to the uncertainty of the associated consideration, which is generally resolved when actual volumes and prices are determined. For example, we consider interruptible transportation service revenues to be variable revenues since volumes cannot be estimated. Additionally, the effect of escalation on certain tolls which are contractually escalated for inflation has not been reflected in the amounts above as it is not possible to reliably estimate future inflation rates. Revenues for periods extending beyond the current rate settlement term for regulated contracts where the tolls are periodically reset by the regulator are excluded from the amounts above since future tolls remain unknown. Finally, revenues from contracts with customers which have an original expected duration of one year or less are excluded from the amounts above.

Variable Consideration

During the three and six months ended June 30, 2023, revenue for the Canadian Mainline has been recognized in accordance with the terms of the Competitive Tolling Settlement (CTS), which expired on June 30, 2021. The tolls in place on June 30, 2021 continued on an interim basis until July 1, 2023 when new interim tolls took effect. Until a new commercial arrangement is approved, the tolls are subject to finalization and adjustment applicable to the interim period, if any. Due to the uncertainty of adjustment to tolling pursuant to a Canada Energy Regulator (CER) decision and potential customer negotiations, interim toll revenue recognized during the three and six months ended June 30, 2023 is considered variable consideration.

Recognition and Measurement of Revenues


Three months ended June 30, 2023	Liquids Pipelines	Gas Transmission and Midstream	Gas Distribution and Storage	Renewable Power Generation	Consolidated
(millions of Canadian dollars)
Revenues from products transferred at a point in time	—	—	37	—	37
Revenues from products and services transferred over time1	3,064	1,403	1,013	75	5,555
Total revenue from contracts with customers	3,064	1,403	1,050	75	5,592

Three months ended June 30, 2022	Liquids Pipelines	Gas Transmission and Midstream	Gas Distribution and Storage	Renewable Power Generation	Consolidated
(millions of Canadian dollars)
Revenues from products transferred at a point in time	—	—	20	—	20
Revenues from products and services transferred over time1	2,629	1,289	1,155	81	5,154
Total revenue from contracts with customers	2,629	1,289	1,175	81	5,174

Six months ended June 30, 2023	Liquids Pipelines	Gas Transmission and Midstream	Gas Distribution and Storage	Renewable Power Generation	Consolidated
(millions of Canadian dollars)
Revenues from products transferred at a point in time	—	—	67	—	67
Revenues from products and services transferred over time1	6,070	2,882	3,645	141	12,738
Total revenue from contracts with customers	6,070	2,882	3,712	141	12,805

Six months ended June 30, 2022	Liquids Pipelines	Gas Transmission and Midstream	Gas Distribution and Storage	Renewable Power Generation	Consolidated
(millions of Canadian dollars)
Revenues from products transferred at a point in time	—	—	36	—	36
Revenues from products and services transferred over time1	5,365	2,582	3,535	143	11,625
Total revenue from contracts with customers	5,365	2,582	3,571	143	11,661

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

3. SEGMENTED INFORMATION


	Liquids Pipelines	Gas Transmission and Midstream	Gas Distribution and Storage	Renewable Power Generation	Energy Services	Eliminations and Other	Consolidated
Three months ended June 30, 2023
(millions of Canadian dollars)
Operating revenues	3,270	1,410	1,050	150	4,679	(127)	10,432
Commodity and gas distribution costs	—	—	(371)	(2)	(4,648)	104	(4,917)
Operating and administrative	(1,083)	(588)	(325)	(62)	(12)	42	(2,028)


Income/(loss) from equity investments	254	199	1	27	—	(3)	478


Other income	10	21	12	16	3	513	575
Earnings before interest, income taxes and depreciation and amortization	2,451	1,042	367	129	22	529	4,540
Depreciation and amortization							(1,137)
Interest expense							(883)
Income tax expense							(519)
Earnings							2,001
Capital expenditures1	237	343	346	23	—	27	976


	Liquids Pipelines	Gas Transmission and Midstream	Gas Distribution and Storage	Renewable Power Generation	Energy Services	Eliminations and Other	Consolidated
Three months ended June 30, 2022
(millions of Canadian dollars)
Operating revenues	2,638	1,301	1,138	155	8,138	(155)	13,215
Commodity and gas distribution costs	(16)	—	(463)	(4)	(8,305)	151	(8,637)
Operating and administrative	(976)	(545)	(281)	(53)	(11)	(128)	(1,994)


Income/(loss) from equity investments	153	335	1	23	—	(2)	510

Other income/(expense)	19	28	22	1	1	(570)	(499)
Earnings/(loss) before interest, income taxes and depreciation and amortization	1,818	1,119	417	122	(177)	(704)	2,595
Depreciation and amortization							(1,064)
Interest expense							(791)
Income tax expense							(133)
Earnings							607
Capital expenditures1	273	333	334	11	—	12	963


Six months ended June 30, 2023	Liquids Pipelines	Gas Transmission and Midstream	Gas Distribution and Storage	Renewable Power Generation	Energy Services	Eliminations and Other	Consolidated
(millions of Canadian dollars)
Operating revenues	6,435	2,901	3,675	294	9,480	(278)	22,507
Commodity and gas distribution costs	—	—	(1,983)	(6)	(9,430)	272	(11,147)
Operating and administrative	(2,206)	(1,137)	(634)	(115)	(30)	57	(4,065)


Income/(loss) from equity investments	502	437	1	62	—	(7)	995


Other income	83	46	24	30	3	491	677
Earnings before interest, income taxes and depreciation and amortization	4,814	2,247	1,083	265	23	535	8,967
Depreciation and amortization							(2,283)
Interest expense							(1,788)
Income tax expense							(1,029)
Earnings							3,867
Capital expenditures1	517	870	610	68	—	52	2,117


Six months ended June 30, 2022	Liquids Pipelines	Gas Transmission and Midstream	Gas Distribution and Storage	Renewable Power Generation	Energy Services	Eliminations and Other	Consolidated
(millions of Canadian dollars)
Operating revenues	5,693	2,601	3,549	311	16,475	(317)	28,312
Commodity and gas distribution costs	(27)	—	(1,931)	(8)	(16,732)	314	(18,384)
Operating and administrative	(1,923)	(1,075)	(580)	(101)	(25)	(165)	(3,869)


Income/(loss) from equity investments	368	556	1	78	—	(2)	1,001

Other income/(expense)	36	51	43	4	4	(179)	(41)
Earnings/(loss) before interest, income taxes and depreciation and amortization	4,147	2,133	1,082	284	(278)	(349)	7,019
Depreciation and amortization							(2,119)
Interest expense							(1,510)
Income tax expense							(726)
Earnings							2,664
Capital expenditures1	818	562	600	17	—	24	2,021

1Includes allowance for equity funds used during construction.

4. EARNINGS PER COMMON SHARE AND DIVIDENDS PER SHARE

BASIC

Earnings per common share is calculated by dividing earnings attributable to common shareholders by the weighted average number of common shares outstanding.

DILUTED

The treasury stock method is used to determine the dilutive impact of stock options and RSUs. This method assumes any proceeds from the exercise of stock options and vesting of RSUs would be used to purchase common shares at the average market price during the period.

Weighted average shares outstanding used to calculate basic and diluted earnings per share are as follows:


	Three months ended June 30,		Six months ended June 30,
	2023	2022	2023	2022
(number of shares in millions)
Weighted average shares outstanding	2,024	2,026	2,025	2,026
Effect of dilutive options and RSUs	3	4	3	4
Diluted weighted average shares outstanding	2,027	2,030	2,028	2,030

For the three months ended June 30, 2023 and 2022, 16.3 million and 3.2 million, respectively, of anti-dilutive stock options with a weighted average exercise price of $55.46 and $59.29, respectively, were

excluded from the diluted earnings per common share calculation.

For the six months ended June 30, 2023 and 2022, 16.5 million and 8.0 million, respectively, of anti-dilutive stock options with a weighted average exercise price of $55.54 and $56.72, respectively, were excluded from the diluted earnings per common share calculation.

DIVIDENDS PER SHARE

On July 31, 2023, our Board of Directors declared the following quarterly dividends. All dividends are payable on September 1, 2023 to shareholders of record on August 15, 2023.


			Dividend per share
Common Shares			$0.88750
Preference Shares, Series A			$0.34375
Preference Shares, Series B			$0.32513
Preference Shares, Series D			$0.33825
Preference Shares, Series F1			$0.34613
Preference Shares, Series G2			$0.43858
Preference Shares, Series H			$0.27350
Preference Shares, Series L			US$0.36612
Preference Shares, Series N			$0.31788
Preference Shares, Series P			$0.27369
Preference Shares, Series R			$0.25456
Preference Shares, Series 13			US$0.41898
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 11			$0.24613
Preference Shares, Series 13			$0.19019
Preference Shares, Series 15			$0.18644
Preference Shares, Series 19			$0.38825

1The quarterly dividend per share paid on Preference Shares, Series F was increased to $0.34613 from $0.29306 on June 1, 2023 due to reset of the annual dividend on June 1, 2023.

2The first quarterly dividend on Preference Shares, Series G will be paid on September 1, 2023. On June 1, 2023, 1,827,695 of the outstanding Preference Shares, Series F were converted into Preference Shares, Series G.

3The quarterly dividend per share paid on Preference Shares, Series 1 was increased to US$0.41898 from US$0.37182 on June 1, 2023 due to reset of the annual dividend on June 1, 2023.

5. ACQUISITION

TRES PALACIOS HOLDINGS LLC

We allocated assets with a fair value of US$588 million to Property, plant and equipment, net, of which US$189 million relates to storage cavern right-of-use assets, and recorded the related lease liabilities of US$5 million and US$184 million to Current portion of long-term debt and Long-term debt, respectively, in the Consolidated Statements of Financial Position. The acquired assets are included in our Gas Transmission and Midstream segment.

6. DEBT

CREDIT FACILITIES

The following table provides details of our committed credit facilities as at June 30, 2023:


	Maturity1	Total Facilities	Draws2	Available
(millions of Canadian dollars)
Enbridge Inc.	2024-2027	8,860	4,341	4,519
Enbridge (U.S.) Inc.	2024-2027	8,403	4,260	4,143
Enbridge Pipelines Inc.	2024	2,000	930	1,070
Enbridge Gas Inc.	2024	2,500	850	1,650
Total committed credit facilities		21,763	10,381	11,382

1Maturity date is inclusive of the one-year term out option for certain credit facilities.

2Includes facility draws and commercial paper issuances that are back-stopped by credit facilities.

In March 2023, Enbridge Gas Inc. (Enbridge Gas) increased its 364-day extendible credit facility from $2.0 billion to $2.5 billion and in July 2023, the facility's maturity date was extended to July 2025, which includes a one-year term out provision from July 2024.

In July 2023, Enbridge Pipelines Inc. extended the maturity date of its 364-day extendible credit facility to July 2025, which includes a one-year term out provision from July 2024.

In July 2023, we renewed approximately $6.8 billion of our 364-day extendible credit facilities, extending the maturity dates to July 2025, which includes a one-year term out provision from July 2024. We also renewed approximately $7.6 billion of our five-year credit facilities, extending the maturity dates to July 2028. Further, we extended our three-year credit facilities, extending the maturity dates to July 2026.

In addition to the committed credit facilities noted above, we maintain $1.3 billion of uncommitted demand letter of credit facilities, of which $723 million was unutilized as at June 30, 2023. As at December 31, 2022, we had $1.3 billion of uncommitted demand letter of credit facilities, of which $689 million was unutilized.

Our credit facilities carry a weighted average standby fee of 0.1% per annum on the unused portion and draws bear interest at market rates. Certain credit facilities serve as a back-stop to the commercial paper programs and we have the option to extend such facilities, which are currently scheduled to mature from 2024 to 2027.

As at June 30, 2023 and December 31, 2022, commercial paper and credit facility draws, net of short-term borrowings and non-revolving credit facilities that mature within one year, of $9.5 billion and $10.5 billion, respectively, were supported by the availability of long-term committed credit facilities and, therefore, have been classified as long-term debt.

LONG-TERM DEBT ISSUANCES

During the six months ended June 30, 2023, we completed the following long-term debt issuances totaling US$3.0 billion and $1.5 billion:

Company

Issue Date

Principal Amount

(millions of Canadian dollars, unless otherwise stated)

Enbridge Inc.

March 2023

5.70%

sustainability-linked senior notes due March 20331

US$2,300

March 2023

5.97%

senior notes due March 20262

US$700

May 2023

4.90%

medium-term notes due May 2028

$600

May 2023

5.36%

sustainability-linked medium-term notes due May 20333

$400

May 2023

5.76%

medium-term notes due May 2053

$500

1The sustainability-linked senior notes are subject to a sustainability performance target of 35% reduction in emissions intensity from 2018 levels at an observation date of December 31, 2030. If the target is not met, on September 8, 2031, the interest rate will be set to equal 5.70% plus a margin of 50 basis points.

2We have the option to call the notes at par after one year from issuance. Refer to Note 8 - Risk Management and Financial Instruments.

3The sustainability-linked senior notes are subject to a sustainability performance target of 35% reduction in emissions intensity from 2018 levels at an observation date of December 31, 2030. If the target is not met, on November 26, 2031, the interest rate will be set to equal 5.36% plus a margin of 50 basis points.

LONG-TERM DEBT REPAYMENTS

During the six months ended June 30, 2023, we completed the following long-term debt repayments totaling US$1.2 billion and $0.7 billion:

Company

Repayment Date

Principal Amount

(millions of Canadian dollars, unless otherwise stated)

Enbridge Inc.

January 2023

3.94

medium-term notes

$275

February 2023

Floating rate notes1

US$500

April 2023

6.38

fixed-to-floating rate subordinated notes2

US$600

June 2023

3.94

medium-term notes

$450

Enbridge Pipelines (Southern Lights) L.L.C.

June 2023

3.98

senior notes

US$38

Enbridge Southern Lights LP

June 2023

4.01

senior notes

Tri Global Energy, LLC

January 2023

10.00

senior notes

US$4

January 2023

14.00

senior notes

US$9

1The notes carried an interest rate set to equal the Secured Overnight Financing Rate plus a margin of 40 basis points.

2The five-year callable notes, with an original maturity date of April 2078, were all redeemed at par.

SUBORDINATED TERM NOTES

As at June 30, 2023 and December 31, 2022, our fixed-to-floating rate and fixed-to-fixed rate subordinated term notes had a principal value of $9.4 billion and $10.3 billion, respectively.

FAIR VALUE ADJUSTMENT

As at June 30, 2023 and December 31, 2022, the net fair value adjustments to total debt assumed in a historical acquisition were $565 million and $608 million, respectively. Amortization of the fair value adjustment is recorded as a reduction to Interest expense in the Consolidated Statements of Earnings:


	Three months ended June 30,		Six months ended June 30,
	2023	2022	2023	2022
(millions of Canadian dollars)
Amortization of fair value adjustment	11	11	22	22

DEBT COVENANTS

Our credit facility agreements and term debt indentures include standard events of default and covenant provisions whereby accelerated repayment and/or termination of the agreements may result if we were to default on payment or violate certain covenants. As at June 30, 2023, we were in compliance with all covenant provisions.

7. COMPONENTS OF ACCUMULATED OTHER COMPREHENSIVE INCOME/(LOSS)

Changes in Accumulated other comprehensive income/(loss) (AOCI) attributable to our common shareholders for the six months ended June 30, 2023 and 2022 are as follows:


	Cash Flow Hedges	Excluded Components of Fair Value Hedges	Net Investment Hedges	Cumulative Translation Adjustment	Equity Investees	Pension and OPEB Adjustment	Total
(millions of Canadian dollars)
Balance as at January 1, 2023	121	(35)	(1,137)	4,348	5	218	3,520
Other comprehensive income/(loss) retained in AOCI	126	9	400	(1,482)	—	—	(947)
Other comprehensive loss/(income) reclassified to earnings
Interest rate contracts1	23	—	—	—	—	—	23
Commodity contracts2	(1)	—	—	—	—	—	(1)

Other contracts3	1	—	—	—	—	—	1
Amortization of pension and OPEB actuarial gain4	—	—	—	—	—	(10)	(10)

	149	9	400	(1,482)	—	(10)	(934)
Tax impact
Income tax on amounts retained in AOCI	(23)	—	—	—	—	—	(23)
Income tax on amounts reclassified to earnings	(4)	—	—	—	—	2	(2)
	(27)	—	—	—	—	2	(25)

Balance as at June 30, 2023	243	(26)	(737)	2,866	5	210	2,561


	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, 2022	(897)	—	(166)	56	(5)	(84)	(1,096)
Other comprehensive income/(loss) retained in AOCI	854	(5)	(253)	1,136	—	—	1,732
Other comprehensive loss/(income) reclassified to earnings
Interest rate contracts1	142	—	—	—	—	—	142

Foreign exchange contracts5	(4)	—	—	—	—	—	(4)
Other contracts3	2	—	—	—	—	—	2
Amortization of pension and OPEB actuarial gain4	—	—	—	—	—	(6)	(6)

	994	(5)	(253)	1,136	—	(6)	1,866
Tax impact
Income tax on amounts retained in AOCI	(202)	—	—	—	—	—	(202)
Income tax on amounts reclassified to earnings	(31)	—	—	—	—	1	(30)
	(233)	—	—	—	—	1	(232)

Balance as at June 30, 2022	(136)	(5)	(419)	1,192	(5)	(89)	538

1Reported within Interest expense in the Consolidated Statements of Earnings.

2Reported within Transportation and other services revenues in the Consolidated Statements of Earnings.

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

4These components are included in the computation of net periodic benefit credit and are reported within Other income/(expense) in the Consolidated Statements of Earnings.

5Reported within Transportation and other services revenues and Other income/(expense) in the Consolidated Statements of Earnings.

8. RISK MANAGEMENT AND FINANCIAL INSTRUMENTS

MARKET RISK

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

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

Foreign Exchange Risk

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

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

The foreign exchange risks inherent within the CTS framework are not present in the negotiated settlement. Accordingly, our foreign exchange hedging program related to the Canadian Mainline will no longer be required, and the related derivatives were terminated in the first quarter of 2023 for a realized loss of $638 million.

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 hedging program to partially mitigate the impact of short-term interest rate volatility on interest expense via the execution of floating-to-fixed interest rate swaps. These hedges have an average fixed rate of 4.1%.

On March 8, 2023, we issued US$700 million three-year fixed rate notes, which include the right for us to call at par after the first year. A corresponding fix-to-floating cancellable swap was also executed which gives the swap counterparty a similar right to cancel the swap after the first year. This swap has a fixed rate of 6.0%. This instrument was our only pay floating-receive fixed interest rate swap outstanding as at June 30, 2023.

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 including some of our subsidiaries to partially mitigate our exposure to long-term interest rate variability on forecasted term debt issuances via the execution of floating-to-fixed interest rate swaps with an average swap rate of 2.6%.

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 natural gas liquids (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 the revaluation of outstanding units every period. We use equity derivatives to manage the earnings volatility derived from one form of stock-based compensation, RSUs. We use a combination of qualifying and non-qualifying derivative instruments to manage equity price risk.

TOTAL DERIVATIVE INSTRUMENTS

We generally have a policy of entering into individual International Swaps and Derivatives Association, Inc. (ISDA) 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 Consolidated Statements of Financial Position location and carrying value of our derivative instruments, as well as the maximum potential settlement amounts, in the event of the specific circumstances described above. All amounts are presented gross in the Consolidated Statements of Financial Position.


June 30, 2023	Derivative Instruments Used as Cash Flow 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)
Other current assets
Foreign exchange contracts	—	40	89	129	(16)	113
Interest rate contracts	205	—	58	263	(2)	261
Commodity contracts	—	—	239	239	(130)	109
Other contracts	—	—	1	1	—	1
	205	40	387	632	(148)	484
Deferred amounts and other assets
Foreign exchange contracts	—	17	161	178	(117)	61
Interest rate contracts	198	—	15	213	(5)	208
Commodity contracts	—	—	68	68	(41)	27

	198	17	244	459	(163)	296
Other current liabilities
Foreign exchange contracts	—	(47)	(39)	(86)	16	(70)
Interest rate contracts	—	—	(2)	(2)	2	—
Commodity contracts	(37)	—	(223)	(260)	130	(130)

	(37)	(47)	(264)	(348)	148	(200)
Other long-term liabilities
Foreign exchange contracts	—	(29)	(587)	(616)	117	(499)
Interest rate contracts	(4)	—	(5)	(9)	5	(4)
Commodity contracts	(12)	—	(101)	(113)	41	(72)

	(16)	(29)	(693)	(738)	163	(575)
Total net derivative asset/(liability)
Foreign exchange contracts	—	(19)	(376)	(395)	—	(395)
Interest rate contracts	399	—	66	465	—	465
Commodity contracts	(49)	—	(17)	(66)	—	(66)
Other contracts	—	—	1	1	—	1
	350	(19)	(326)	5	—	5


December 31, 2022	Derivative Instruments Used as Cash Flow 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)
Other current assets
Foreign exchange contracts	—	—	46	46	(41)	5
Interest rate contracts	649	—	11	660	—	660
Commodity contracts	—	—	302	302	(182)	120
Other contracts	—	—	7	7	—	7
	649	—	366	1,015	(223)	792
Deferred amounts and other assets
Foreign exchange contracts	—	156	153	309	(138)	171
Interest rate contracts	254	—	—	254	—	254
Commodity contracts	—	—	61	61	(25)	36
Other contracts	1	—	2	3	—	3
	255	156	216	627	(163)	464
Other current liabilities
Foreign exchange contracts	—	(42)	(524)	(566)	41	(525)

Commodity contracts	(48)	—	(284)	(332)	182	(150)

	(48)	(42)	(808)	(898)	223	(675)
Other long-term liabilities
Foreign exchange contracts	—	—	(1,116)	(1,116)	138	(978)
Interest rate contracts	(3)	—	(1)	(4)	—	(4)
Commodity contracts	(37)	—	(133)	(170)	25	(145)

	(40)	—	(1,250)	(1,290)	163	(1,127)
Total net derivative asset/(liability)
Foreign exchange contracts	—	114	(1,441)	(1,327)	—	(1,327)
Interest rate contracts	900	—	10	910	—	910
Commodity contracts	(85)	—	(54)	(139)	—	(139)
Other contracts	1	—	9	10	—	10
	816	114	(1,476)	(546)	—	(546)

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


June 30, 2023	2023	2024	2025	2026	2027	Thereafter	Total
Foreign exchange contracts - US dollar forwards - purchase (millions of US dollars)	535	1,000	500	—	—	—	2,035
Foreign exchange contracts - US dollar forwards - sell (millions of US dollars)	3,052	4,708	4,763	4,157	3,131	2,010	21,821
Foreign exchange contracts - British pound (GBP) forwards - sell (millions of GBP)	17	30	30	28	32	—	137

Foreign exchange contracts - Euro forwards - sell (millions of Euro)	46	91	86	85	81	262	651
Foreign exchange contracts - Japanese yen forwards - purchase (millions of yen)	—	—	84,800	—	—	—	84,800
Interest rate contracts - short-term debt pay fixed rate (millions of Canadian dollars)	5,267	4,028	1,072	891	67	39	11,364
Interest rate contracts - short-term debt receive fixed rate (millions of Canadian dollars)	448	926	926	175	—	—	2,475
Interest rate contracts - long-term debt pay fixed rate (millions of Canadian dollars)	3,304	1,478	581	—	—	—	5,363
Equity contracts (millions of Canadian dollars)	—	32	12	—	—	—	44
Commodity contracts - natural gas (billions of cubic feet)	15	39	25	6	3	—	88
Commodity contracts - crude oil (millions of barrels)	7	(4)	—	—	—	—	3

Commodity contracts - power (megawatt per hour) (MW/H)	98	2	(22)	3	(3)	—	7	1

1Total is an average net purchase/(sale) of power.

Fair Value Derivatives

For foreign exchange derivative instruments that are designated and qualify as fair value hedges, the gain or loss on the derivative is included in Other income/(expense) or Interest expense in the Consolidated Statements of Earnings. The offsetting loss or gain on the hedged item attributable to the hedged risk is included in Other income/(expense) in the Consolidated Statements of Earnings. Any excluded components are included in the Consolidated Statements of Comprehensive Income.


	Three months ended June 30,		Six months ended June 30,
	2023	2022	2023	2022
(millions of Canadian dollars)
Unrealized gain/(loss) on derivative	(131)	23	(142)	99
Unrealized gain/(loss) on hedged item	130	(2)	141	(89)
Realized loss on derivative	(12)	(21)	(23)	(96)
Realized gain on hedged item	—	—	—	85

The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income

The following table presents the effect of cash flow hedges and fair value hedges on our consolidated earnings and consolidated comprehensive income, before the effect of income taxes:


	Three months ended June 30,		Six months ended June 30,
	2023	2022	2023	2022
(millions of Canadian dollars)
Amount of unrealized gain/(loss) recognized in OCI
Cash flow hedges
Foreign exchange contracts	—	—	—	2
Interest rate contracts	215	480	110	857
Commodity contracts	2	(15)	36	(11)
Other contracts	—	(3)	(2)	—
Fair value hedges
Foreign exchange contracts	2	(4)	9	(5)


	219	458	153	843
Amount of (gain)/loss reclassified from AOCI to earnings
Foreign exchange contracts1	—	—	—	13
Interest rate contracts2	15	66	23	142
Commodity contracts3	(1)	—	(1)	—
Other contracts4	—	—	1	2
	14	66	23	157

1Reported within Transportation and other services revenues and Other income/(expense) in the Consolidated Statements of Earnings.

2Reported within Interest expense in the Consolidated Statements of Earnings.

3Reported within Transportation and other services in the Consolidated Statements of Earnings.

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

We estimate that a gain of $16 million from AOCI related to cash flow hedges will be reclassified to earnings in the next 12 months. Actual amounts reclassified to earnings depend on the foreign exchange rates, interest rates and commodity prices in effect when derivative contracts that are currently outstanding mature. For all forecasted transactions, the maximum term over which we are hedging exposures to the variability of cash flows is 30 months as at June 30, 2023.

Non-Qualifying Derivatives

The following table presents the unrealized gains and losses associated with changes in the fair value of our non-qualifying derivatives:


	Three months ended June 30,		Six months ended June 30,
	2023	2022	2023	2022
(millions of Canadian dollars)
Foreign exchange contracts1	509	(806)	1,065	(373)
Interest rate contracts2	45	(16)	55	(16)
Commodity contracts3	62	38	23	(30)
Other contracts4	(1)	—	(8)	4
Total unrealized derivative fair value gain/(loss), net	615	(784)	1,135	(415)

1For the respective six months ended periods, reported within Transportation and other services revenues (2023 - $645 million gain; 2022 - $65 million loss) and Other income/(expense) (2023 - $420 million gain; 2022 - $308 million loss) in the Consolidated Statements of Earnings.

2Reported as an increase within Interest expense in the Consolidated Statements of Earnings.

3For the respective six months ended periods, reported within Transportation and other services revenues (2023 - $8 million gain; 2022 - $25 million gain), Commodity sales (2023 - $96 million gain; 2022 - $109 million gain), Commodity costs (2023 - $51 million loss; 2022 - $167 million loss) and Operating and administrative expense (2023 - $30 million loss; 2022 - $3 million gain) in the Consolidated Statements of Earnings.

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

LIQUIDITY RISK

Liquidity risk is the risk that we will not be able to meet our financial obligations, including commitments and guarantees, as they become due. In order to mitigate this risk, we forecast cash requirements over a 12-month rolling time period to determine whether sufficient funds will be available and maintain substantial capacity under our committed bank lines of credit to address any contingencies. Our primary sources of liquidity and capital resources are funds generated from operations, the issuance of commercial paper and draws under committed credit facilities and long-term debt, which includes debentures and medium-term notes. Our shelf prospectuses with securities regulators enable ready access to either the Canadian or US public capital markets, subject to market conditions. In addition, we maintain sufficient liquidity through committed credit facilities with a diversified group of banks and institutions which, if necessary, enables us to fund all anticipated requirements for approximately one year without accessing the capital markets. We were in compliance with all the terms and conditions of our committed credit facility agreements and term debt indentures as at June 30, 2023. As a result, all credit facilities are available to us and the banks are obligated to fund us under the terms of the facilities.

CREDIT RISK

Entering into derivative instruments may result in exposure to credit risk from the possibility that a counterparty will default on its contractual obligations. In order to mitigate this risk, we enter into risk management transactions primarily with institutions that possess strong investment grade credit ratings. Credit risk relating to derivative counterparties is mitigated through the maintenance and monitoring of credit exposure limits and contractual requirements, netting arrangements and ongoing monitoring of counterparty credit exposure using external credit rating services and other analytical tools.

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


	June 30, 2023	December 31, 2022
(millions of Canadian dollars)
Canadian financial institutions	499	644
US financial institutions	136	277
European financial institutions	214	334
Asian financial institutions	109	224
Other1	89	105
	1,047	1,584

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

As at June 30, 2023, we did not provide any letters of credit in lieu of providing cash collateral to our counterparties pursuant to the terms of the relevant ISDA agreements. We held no cash collateral on derivative asset exposures as at June 30, 2023 and December 31, 2022.

Gross derivative balances have been presented without the effects of collateral posted. Derivative assets are adjusted for non-performance risk of our counterparties using their credit default swap spread rates and are reflected at fair value. For derivative liabilities, our non-performance risk is considered in the valuation.

Credit risk also arises from trade and other long-term receivables, and is mitigated through credit exposure limits and contractual requirements, the assessment of credit ratings and netting arrangements. Within Enbridge Gas, credit risk is mitigated by the utility's large and diversified customer base and the ability to recover an estimate for expected credit losses through the ratemaking process. We actively monitor the financial strength of large industrial customers and, in select cases, have obtained additional security to minimize the risk of default on receivables. Generally, we utilize a loss allowance matrix which contemplates historical credit losses by age of receivables, adjusted for any forward-looking information and management expectations to measure lifetime expected credit losses of receivables. The maximum exposure to credit risk related to non-derivative financial assets is their carrying value.

FAIR VALUE MEASUREMENTS

Our financial assets and liabilities measured at fair value on a recurring basis include derivatives and other financial instruments. We also disclose the fair value of other financial instruments not measured at fair value. The fair value of financial instruments reflects our best estimates of market value based on generally accepted valuation techniques or models and is supported by observable market prices and rates. When such values are not available, we use discounted cash flow analysis from applicable yield curves based on observable market inputs to estimate fair value.

FAIR VALUE OF FINANCIAL INSTRUMENTS

We categorize our financial instruments measured at fair value into one of three different levels depending on the observability of the inputs employed in the measurement.

Level 1

Level 1 includes financial instruments measured at fair value based on unadjusted quoted prices for identical assets and liabilities in active markets that are accessible at the measurement date. An active market for a financial instrument is considered to be a market where transactions occur with sufficient frequency and volume to provide pricing information on an ongoing basis. Our Level 1 instruments consist primarily of exchange-traded derivatives used to mitigate the risk of crude oil price fluctuations, US and Canadian treasury bills, investments in exchange-traded equity funds held by our captive insurance subsidiaries, as well as restricted long-term investments in Canadian equity securities that are held in trust in accordance with the CER's regulatory requirements under the Land Matters Consultation Initiative (LMCI).

Level 2

Level 2 includes financial instrument valuations determined using directly or indirectly observable inputs other than quoted prices included within Level 1. Financial instruments in this category are valued using models or other industry standard valuation techniques derived from observable market data. Such valuation techniques include inputs such as quoted forward prices, time value, volatility factors and broker quotes that can be observed or corroborated in the market for the entire duration of the financial instrument. Derivatives valued using Level 2 inputs include non-exchange traded derivatives such as over-the-counter foreign exchange forward and cross-currency swap contracts, interest rate swaps, physical forward commodity contracts, as well as commodity swaps and options for which observable inputs can be obtained.

We have also categorized the fair value of our long-term debt, investments in debt securities held by our captive insurance subsidiaries, and restricted long-term investments in Canadian government bonds held in accordance with the CER's regulatory requirements under the LMCI as Level 2. The fair value of our long-term debt is based on quoted market prices for instruments of similar yield, credit risk and tenor. When possible, the fair value of our restricted long-term investments is based on quoted market prices for similar instruments and, if not available, based on broker quotes.

Level 3

Level 3 includes derivative valuations based on inputs which are less observable, unavailable or where the observable data does not support a significant portion of the derivatives' fair value. Generally, Level 3 derivatives are longer dated transactions, occur in less active markets, occur at locations where pricing information is not available or have no binding broker quote to support Level 2 classification. We have developed methodologies, benchmarked against industry standards, to determine fair value for these derivatives based on the extrapolation of observable future prices and rates. Derivatives valued using Level 3 inputs primarily include long-dated derivative power, NGL and natural gas contracts, basis swaps, commodity swaps, and power and energy swaps, as well as physical forward commodity contracts. We do not have any other financial instruments categorized in Level 3.

We use the most observable inputs available to estimate the fair value of our derivatives. When possible, we estimate the fair value of our derivatives based on quoted market prices. If quoted market prices are not available, we use estimates from third party brokers. For non-exchange traded derivatives classified in Levels 2 and 3, we use standard valuation techniques to calculate the estimated fair value. These methods include discounted cash flows for forwards and swaps and Black-Scholes-Merton pricing models for options. Depending on the type of derivative and nature of the underlying risk, we use observable market prices (interest, foreign exchange, commodity and share price) and volatility as primary inputs to these valuation techniques. Finally, we consider our own credit default swap spread, as well as the credit default swap spreads associated with our counterparties, in our estimation of fair value.

We have categorized our derivative assets and liabilities measured at fair value as follows:


June 30, 2023	Level 1	Level 2	Level 3	Total Gross Derivative Instruments
(millions of Canadian dollars)
Financial assets
Current derivative assets
Foreign exchange contracts	—	129	—	129
Interest rate contracts	—	263	—	263
Commodity contracts	43	47	149	239
Other contracts	—	1	—	1
	43	440	149	632
Long-term derivative assets
Foreign exchange contracts	—	178	—	178
Interest rate contracts	—	213	—	213
Commodity contracts	—	17	51	68

	—	408	51	459
Financial liabilities
Current derivative liabilities
Foreign exchange contracts	—	(86)	—	(86)
Interest rate contracts	—	(2)	—	(2)
Commodity contracts	(21)	(39)	(200)	(260)

	(21)	(127)	(200)	(348)
Long-term derivative liabilities
Foreign exchange contracts	—	(616)	—	(616)
Interest rate contracts	—	(9)	—	(9)
Commodity contracts	—	(26)	(87)	(113)

	—	(651)	(87)	(738)
Total net financial asset/(liability)
Foreign exchange contracts	—	(395)	—	(395)
Interest rate contracts	—	465	—	465
Commodity contracts	22	(1)	(87)	(66)
Other contracts	—	1	—	1
	22	70	(87)	5


December 31, 2022	Level 1	Level 2	Level 3	Total Gross Derivative Instruments
(millions of Canadian dollars)
Financial assets
Current derivative assets
Foreign exchange contracts	—	46	—	46
Interest rate contracts	—	660	—	660
Commodity contracts	65	90	147	302
Other contracts	—	7	—	7
	65	803	147	1,015
Long-term derivative assets
Foreign exchange contracts	—	309	—	309
Interest rate contracts	—	254	—	254
Commodity contracts	—	17	44	61
Other contracts	—	3	—	3
	—	583	44	627
Financial liabilities
Current derivative liabilities
Foreign exchange contracts	—	(566)	—	(566)

Commodity contracts	(60)	(77)	(195)	(332)

	(60)	(643)	(195)	(898)
Long-term derivative liabilities
Foreign exchange contracts	—	(1,116)	—	(1,116)
Interest rate contracts	—	(4)	—	(4)
Commodity contracts	—	(38)	(132)	(170)

	—	(1,158)	(132)	(1,290)
Total net financial asset/(liability)
Foreign exchange contracts	—	(1,327)	—	(1,327)
Interest rate contracts	—	910	—	910
Commodity contracts	5	(8)	(136)	(139)
Other contracts	—	10	—	10
	5	(415)	(136)	(546)

The significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments were as follows:


June 30, 2023	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	(16)	Forward gas price	1.59	8.82	4.48	$/mmbtu2
Crude	(8)	Forward crude price	70.23	90.70	81.07	$/barrel

Power	(91)	Forward power price	25.85	255.75	63.34	$/MW/H
Commodity contracts - physical1
Natural gas	(12)	Forward gas price	1.66	23.07	4.65	$/mmbtu2
Crude	(3)	Forward crude price	73.18	116.60	86.60	$/barrel

Power	43	Forward power price	24.26	96.39	55.05	$/MW/H
	(87)

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

2One million British thermal units (mmbtu).

If adjusted, the significant unobservable inputs disclosed in the table above would have a direct impact on the fair value of our Level 3 derivative instruments. The significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments include forward commodity prices. Changes in forward commodity prices could result in significantly different fair values for our Level 3 derivatives.

Changes in net fair value of derivative assets and liabilities classified as Level 3 in the fair value hierarchy were as follows:


	Six months ended June 30,
	2023	2022
(millions of Canadian dollars)
Level 3 net derivative liability at beginning of period	(136)	(108)
Total gain/(loss)
Included in earnings1	11	14
Included in OCI	35	(11)
Settlements	3	(2)
Level 3 net derivative liability at end of period	(87)	(107)

1Reported within Transportation and other services revenues, Commodity costs and Operating and administrative expense in the Consolidated Statements of Earnings.

There were no transfers into or out of Level 3 as at June 30, 2023 or December 31, 2022.

NET INVESTMENT HEDGES

We currently have designated a portion of our US dollar-denominated debt as a hedge of our net investment in US dollar-denominated investments and subsidiaries.

During the six months ended June 30, 2023 and 2022, we recognized unrealized foreign exchange gains of $444 million and losses of $257 million, respectively, on the translation of US dollar-denominated debt, in OCI. No unrealized gains or losses on the change in fair value of our outstanding foreign exchange forward contracts were recognized in OCI during the six months ended June 30, 2023 and 2022. No realized gains or losses associated with the settlement of foreign exchange forward contracts were recognized in OCI during the six months ended June 30, 2023 and 2022. During the six months ended June 30, 2023 and 2022, we recognized a realized loss of $44 million and nil, respectively, associated with the settlement of US dollar-denominated debt that had matured during the period, in OCI.

FAIR VALUE OF OTHER FINANCIAL INSTRUMENTS

Certain long-term investments in other entities with no actively quoted prices are classified as Fair Value Measurement Alternative (FVMA) investments and are recorded at cost less impairment. The carrying value of FVMA investments totaled $207 million and $102 million as at June 30, 2023 and December 31, 2022, respectively.

As at June 30, 2023, we had investments with a fair value of $664 million included in Restricted long-term investments in the Consolidated Statements of Financial Position (December 31, 2022 - $593 million). These securities are classified as available-for-sale and represent restricted funds which are collected from customers and held in trust for the purpose of funding pipeline abandonment in accordance with the CER's regulatory requirements.

We had restricted long-term investments held in trust totaling $252 million as at June 30, 2023, which are classified as Level 1 in the fair value hierarchy (December 31, 2022 - $236 million). We also had restricted long-term investments held in trust totaling $412 million (cost basis - $463 million) and $357 million (cost basis - $437 million) as at June 30, 2023 and December 31, 2022, respectively, which are classified as Level 2 in the fair value hierarchy. There were unrealized holding gains of $3 million and $37 million on these investments for the three and six months ended June 30, 2023, respectively (2022 - losses of $71 million and $131 million, respectively).

We have wholly-owned captive insurance subsidiaries whose principal activity is providing insurance and reinsurance coverage for certain insurable property and casualty risk exposures of our operating subsidiaries and certain equity investments. As at June 30, 2023, the fair value of investments in equity funds and debt securities held by our captive insurance subsidiaries was $354 million and $323 million, respectively (December 31, 2022 - $335 million and $298 million, respectively). Our investments in debt securities had a cost basis of $314 million as at June 30, 2023 (December 31, 2022 - $295 million). These investments in equity funds and debt securities are recognized at fair value, classified as Level 1 and Level 2 in the fair value hierarchy, respectively, and are recorded in Other current assets and Long-term investments in the Consolidated Statements of Financial Position. There were unrealized holding gains of $7 million and $22 million for the three and six months ended June 30, 2023, respectively (2022 - losses of $19 million and $27 million, respectively).

As at June 30, 2023 and December 31, 2022, our long-term debt had a carrying value of $78.7 billion and $79.3 billion, respectively, before debt issuance costs and a fair value of $73.8 billion and $73.5 billion, respectively. We also have non-current notes receivable carried at book value and recorded in Deferred amounts and other assets in the Consolidated Statements of Financial Position. As at June 30, 2023 and December 31, 2022, the non-current notes receivable had a carrying value of $680 million and $752 million, respectively, which also approximates their fair value.

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

9. INCOME TAXES

The effective income tax rates for the three months ended June 30, 2023 and 2022 were 20.6% and 18.0%, respectively, and for the six months ended June 30, 2023 and 2022 were 21.0% and 21.4%, respectively.

The period-over-period changes in the effective income tax rates are due to the effects of rate-regulated accounting for income taxes, higher investment tax credits available on certain capital projects in the US and an increase in earnings attributable to non-controlling interests, relative to higher earnings in the 2023 periods.

10. OTHER INCOME


	Three months ended June 30,		Six months ended June 30,
	2023	2022	2023	2022
(millions of Canadian dollars)
Gain/(loss) on dispositions	8	1	11	(1)
Realized foreign currency gain	1	2	146	4
Unrealized foreign currency gain/(loss)	492	(583)	304	(216)
Net defined pension and OPEB credit	34	59	67	117
Other	40	22	149	55
	575	(499)	677	(41)

11. CONTINGENCIES

LITIGATION

We and our subsidiaries are subject to various legal and regulatory actions and proceedings which arise in the normal course of business, including interventions in regulatory proceedings and challenges to regulatory approvals and permits. While the final outcome of such actions and proceedings cannot be predicted with certainty, management believes that the resolution of such actions and proceedings will not have a material impact on our interim consolidated financial position or results of operations.

TAX MATTERS

We and our subsidiaries maintain tax liabilities related to uncertain tax positions. While fully supportable in our view, these tax positions, if challenged by tax authorities, may not be fully sustained on review.

INSURANCE

We maintain an insurance program for us, our subsidiaries and certain of our affiliates to mitigate a certain portion of our risks. However, not all potential risks arising from our operations are insurable, or are insured by us as a result of availability, high premiums and for various other reasons. We self-insure a significant portion of certain risks through our wholly-owned captive insurance subsidiaries, and our insurance coverage is subject to terms and conditions, exclusions and large deductibles or self-insured retentions which may reduce or eliminate coverage in certain circumstances.

Our insurance policies are generally renewed on an annual basis and, depending on factors such as market conditions, the premiums, terms, policy limits and/or deductibles, can vary substantially. We can give no assurance that we will be able to maintain adequate insurance in the future at rates or on other terms we consider commercially reasonable. In such case, we may decide to self-insure additional risks.

In the unlikely event multiple insurable incidents occur which exceed coverage limits within the same insurance period, the total insurance coverage will be allocated among entities on an equitable basis based on an insurance allocation agreement we have entered into with us and other subsidiaries. Insurance estimates include certain assumptions and management judgments regarding the frequency and severity of claims, claim development and settlement practices and the selection of estimated loss among estimates derived using different methods.

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

INTRODUCTION

The following discussion and analysis of our financial condition and results of operations is based on and should be read in conjunction with our interim consolidated financial statements and the accompanying notes included in Part I. Item 1. Financial Statements of this quarterly report on Form 10-Q and our consolidated financial statements and the accompanying notes included in Part II. Item 8. Financial Statements and Supplementary Data of our annual report on Form 10-K for the year ended December 31, 2022.

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

RECENT DEVELOPMENTS

MAINLINE TOLLING AGREEMENT

Enbridge Inc. (Enbridge) has reached an agreement in principle on a negotiated settlement (the settlement) with shippers for tolls on its Mainline pipeline system. The settlement covers both the Canadian and US portions of the Mainline and would see the Mainline continuing to operate as a common carrier system available to all shippers on a monthly nomination basis. The settlement is subject to regulatory and other approvals and the term is seven and a half years through the end of 2028, with new interim tolls effective on July 1, 2023.

The settlement includes:

•an International Joint Toll (IJT), for heavy crude oil movements from Hardisty to Chicago, comprised of a Canadian Mainline Toll of $1.65 per barrel plus a Lakehead System Toll of US$2.57 per barrel, plus the applicable Line 3 Replacement surcharge;

•toll escalation for operation, administration, and power costs tied to US consumer price and power indices;

•tolls will continue to be distance and commodity adjusted, and will utilize a dual currency IJT; and

•a financial performance collar providing incentives for Enbridge to optimize throughput and cost, but also providing downside protection in the event of extreme supply or demand disruptions or unforeseen operating cost exposure. This performance collar is intended to ensure the Mainline will earn 11% to 14.5% returns, on a deemed 50% equity capitalization, which is similar to the returns earned on average during the previous tolling agreement.

Approximately 70% of Mainline deliveries are tolled under this settlement, while approximately 30% of deliveries are tolled on a full path basis to markets downstream of the Mainline. The other continuing feature is that the Mainline toll will flex up or down US$0.035 per barrel for 50,000 barrel per day changes in throughput.

The expected financial outcome from this settlement is in line with previously reported financial results after taking into consideration the previously recognized provision, inflationary cost adjustments and increased volumes. Enbridge expects to file the settlement with the Canada Energy Regulator (CER) in October 2023.

On May 24, 2023, Enbridge filed an Offer of Settlement with the Federal Energy Regulatory Commission (FERC) for the Lakehead System. In addition to resolving litigation related to the Index portion of the Lakehead System rate, the Settlement also includes a depreciation truncation date of December 31, 2048 for the rate base applicable to the Index and Facilities Surcharge and agreement on the terms for future recovery through the Facilities Surcharge of costs related to two Line 5 projects: the Wisconsin Relocation Project and the Straits of Mackinac Tunnel. The Settlement Judge certified the settlement on June 23, 2023 and the Settlement is awaiting approval by the Commissioners. Lakehead System tolls will be updated to reflect the new Settlement pending approval by the FERC.

ACQUISITIONS

Tres Palacios Holdings LLC

On April 3, 2023, we acquired Tres Palacios Holdings LLC (Tres Palacios) for US$335 million of cash. Tres Palacios is a natural gas storage facility located in the US Gulf Coast and its infrastructure serves Texas gas-fired power generation and liquefied natural gas exports, as well as Mexico pipeline exports. Tres Palacios is comprised of three natural gas storage salt caverns with a total FERC-certificated working gas capacity of approximately 35 billion cubic feet (bcf) and also owns an integrated 62-mile natural gas header pipeline system, with eleven inter- and intrastate natural gas pipeline connections.

Aitken Creek Gas Storage

On May 1, 2023, we announced that Enbridge has entered into a definitive agreement to acquire a 93.8% interest in Aitken Creek Gas Storage Facility and a 100% interest in Aitken Creek North Gas Storage Facility (collectively, Aitken Creek) for $400 million of cash plus payment for derivative contracts and gas inventory, subject to other customary closing adjustments. Aitken Creek is a natural gas storage facility located in British Columbia, Canada with a working gas capacity of approximately 77 bcf. The transaction is expected to close later in 2023, subject to receipt of customary regulatory approvals and closing conditions.

GAS TRANSMISSION AND MIDSTREAM RATE PROCEEDINGS

Texas Eastern Transmission

The Stipulation and Agreement for Texas Eastern Transmission, LP’s (Texas Eastern) consolidated 2021 rate cases was approved by the FERC on November 30, 2022, and became effective on January 1, 2023. Texas Eastern received FERC approval on April 3, 2023 to implement the settled rates and other settlement provisions.

Maritimes & Northeast Pipeline

The current toll settlement agreement for the Canadian portion of Maritimes & Northeast (M&N) Pipeline expires in December 2023. Settlement negotiations with M&N Pipeline shippers are planned in the third quarter of 2023 with the objective of reaching a toll settlement which would be effective January 1, 2024. It is expected that a settlement agreement will be filed in the fourth quarter of 2023 with the CER for review and approval. A CER decision is expected in the first quarter of 2024.

GAS DISTRIBUTION AND STORAGE RATE APPLICATIONS

Incentive Regulation Rate Application

In October 2022, Enbridge Gas Inc. (Enbridge Gas) filed its application with the Ontario Energy Board (OEB) to establish a 2024 through 2028 Incentive Regulation (IR) rate setting framework. The application and framework seeks approval in two phases to establish 2024 base rates (Phase 1) on a cost-of-service basis and to establish a price cap rate setting mechanism (Phase 2) to be used for the remainder of the IR term (2025 – 2028).

On June 28, 2023, we filed a Phase 1 Partial Settlement Proposal with the OEB for final review and approval. Items resolved in whole or in part include:

•Indigenous engagement;

•additions to the rate base up to and including 2022;

•capital structure cost rates;

•deferral and variance accounts; and

•rate implementation approach for 2024.

A Phase 1 oral hearing began on July 13, 2023 to further examine issues in our application that were not resolved as part of the Partial Settlement Proposal.

Purchase Gas Variance

The Purchase Gas Variance Account (PGVA) captures the difference between actual and forecasted natural gas prices reflected in rates. Account balances are typically recovered or refunded over a prospective 12-month period through Quarterly Rate Adjustment Mechanism (QRAM) applications.

In March 2023, the April 1, 2023 QRAM application was filed and approved by the OEB, which included an adjustment to the prior mitigation approved as part of the July 1, 2022 QRAM. The recovery of the outstanding PGVA balance from the extended recovery period approved as part of the July 1, 2022 QRAM will now be completed by March 31, 2024. The July 1, 2023 QRAM application was filed and approved by the OEB with no adjustments to the prior period rate mitigation plans and it did not include any additional rate mitigation measures.

As at June 30, 2023, Enbridge Gas' PGVA receivable balance was $337 million.

FINANCING UPDATE

In March 2023, we closed a two-tranche US debt offering consisting of three-year senior notes, callable at par after one year at our option, and 10-year sustainability-linked senior notes, for an aggregate principal amount of US$3.0 billion, which mature in March 2026 and March 2033, respectively.

In March 2023, Enbridge Gas increased its 364-day extendible credit facility from $2.0 billion to $2.5 billion and in July 2023, the facility's maturity date was extended to July 2025, which includes a one-year term out provision from July 2024.

On April 15, 2023 call date, we redeemed at par all of the outstanding US$600 million five-year callable, 6.38% fixed-to-floating rate subordinated notes that carried an original maturity date of April 2078.

In May 2023, we closed a three-tranche debt offering consisting of five-year medium-term notes, 10-year sustainability-linked medium-term notes, and 30-year medium-term notes for an aggregate principal amount of $1.5 billion, which mature in May 2028, May 2033 and May 2053, respectively.

In July 2023, Enbridge Pipelines Inc. extended the maturity date of its 364-day extendible credit facility to July 2025, which includes a one-year term out provision from July 2024.

These financing activities, in combination with the financing activities executed in 2022, provide significant liquidity that we expect will enable us to fund our current portfolio of capital projects and other operating working capital requirements without requiring access to the capital markets for the next 12 months, should market access be restricted or pricing be unattractive. Refer to Liquidity and Capital Resources.

As at June 30, 2023, after adjusting for the impact of floating-to-fixed interest rate swap hedges, less than 5% of our total debt is exposed to floating rates. Refer to Part I. Item 1. Financial Statements - Note 8 - Risk Management and Financial Instruments for more information on our interest rate hedging program.

RESULTS OF OPERATIONS


	Three months ended June 30,		Six months ended June 30,
	2023	2022	2023	2022
(millions of Canadian dollars, except per share amounts)
Segment earnings/(loss) before interest, income taxes and depreciation and amortization1
Liquids Pipelines	2,451	1,818	4,814	4,147
Gas Transmission and Midstream	1,042	1,119	2,247	2,133
Gas Distribution and Storage	367	417	1,083	1,082
Renewable Power Generation	129	122	265	284
Energy Services	22	(177)	23	(278)
Eliminations and Other	529	(704)	535	(349)
Earnings before interest, income taxes and depreciation and amortization1	4,540	2,595	8,967	7,019
Depreciation and amortization	(1,137)	(1,064)	(2,283)	(2,119)
Interest expense	(883)	(791)	(1,788)	(1,510)
Income tax expense	(519)	(133)	(1,029)	(726)
Earnings attributable to noncontrolling interests	(66)	(12)	(115)	(40)
Preference share dividends	(87)	(145)	(171)	(247)
Earnings attributable to common shareholders	1,848	450	3,581	2,377
Earnings per common share attributable to common shareholders	0.91	0.22	1.77	1.17
Diluted earnings per common share attributable to common shareholders	0.91	0.22	1.77	1.17

1Non-GAAP financial measure. Please refer to Non-GAAP and Other Financial Measures.

EARNINGS ATTRIBUTABLE TO COMMON SHAREHOLDERS

Three months ended June 30, 2023, compared with the three months ended June 30, 2022

Earnings attributable to common shareholders were positively impacted by $1,368 million due to certain infrequent or other non-operating factors, primarily explained by the following:

•a non-cash, net unrealized derivative fair value gain of $550 million ($422 million after-tax) in 2023, compared to a net loss of $866 million ($663 million after-tax) in 2022, reflecting changes in the mark-to-market value of derivative financial instruments used to manage foreign exchange and interest rate risks;

•the absence in 2023 of a $100 million ($77 million after-tax) restructuring expense associated with our enterprise insurance strategy;

•a net positive adjustment to crude oil and natural gas inventories of $7 million ($6 million after-tax) in 2023, compared with a net negative adjustment of $62 million ($48 million after-tax) in 2022;

•a non-cash, net unrealized gain of $45 million ($34 million after-tax) in 2023, compared to a net loss of $16 million ($12 million after-tax) in 2022, reflecting the revaluation of derivatives used to manage the profitability of transportation and storage transactions, and exposure to movements in commodity prices;

•the absence in 2023 of an asset impairment loss of $40 million ($31 million after-tax) relating to the MacKay River line within our Alberta Regional Oil Sands System; and

•a net unrealized gain of $9 million ($8 million after-tax) in 2023, compared with a net unrealized loss of $27 million ($23 million after-tax) in 2022 reflecting changes in the mark-to-market value of equity fund investments held by our wholly-owned captive insurance subsidiaries; partially offset by

•the absence in 2023 of a net positive adjustment of $22 million ($17 million after-tax) relating to our share of changes in the mark-to-market value of derivative financial instruments of our equity method investees, DCP Midstream, LP (DCP) and Aux Sable Canada LP, Aux Sable Liquid Products LP and Aux Sable Midstream LLC (collectively, Aux Sable).

The non-cash, unrealized derivative fair value gains and losses discussed above generally arise as a result of our comprehensive economic hedging program to mitigate foreign exchange and commodity price risks. This program creates volatility in reported short-term earnings through the recognition of unrealized non-cash gains and losses on 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 $30 million increase in earnings attributable to common shareholders is primarily explained by:

•higher contributions from the Mainline System and Line 9 in our Liquids Pipelines segment driven by increased volumes due to increased crude demand and the recognition of a lower provision against the interim Mainline IJT, net of a lower Line 3 Replacement (L3R) surcharge; and

•higher contributions from our Liquids Pipelines segment due to increased ownership of the Gray Oak Pipeline and Cactus II Pipeline acquired in the second half of 2022 and higher volumes from the Flanagan South Pipeline and the Enbridge Ingleside Energy Center (EIEC) due to higher demand; partially offset by

•a reduction in earnings from our Gas Transmission and Midstream segment primarily due to our decreased interest in DCP as a result of a joint venture merger transaction with Phillips 66 that closed in the third quarter in 2022;

•higher power costs as a result of increased volumes and power prices in our Liquids Pipelines segment;

•lower commodity prices impacting the DCP and Aux Sable joint ventures in our Gas Transmission and Midstream segment; and

•higher interest expense primarily due to higher interest rates and higher average principal.

Six months ended June 30, 2023, compared with the six months ended June 30, 2022

Earnings attributable to common shareholders were positively impacted by $1,153 million due to certain infrequent or other non-operating factors, primarily explained by the following:

•a non-cash, net unrealized derivative fair value gain of $1,091 million ($828 million after-tax) in 2023, compared with a net unrealized loss of $433 million ($332 million after-tax) in 2022, reflecting changes in the mark-to-market value of derivative financial instruments used to manage foreign exchange and interest rate risks;

•the absence in 2023 of restructuring expense of $100 million ($77 million after-tax) associated with our enterprise insurance strategy;

•a non-cash, net unrealized gain of $53 million ($40 million after-tax) in 2023, compared to a net loss of $36 million ($27 million after-tax) in 2022, reflecting the revaluation of derivatives used to manage the profitability of transportation and storage transactions, as well as manage the exposure to movements in commodity prices;

•a net positive adjustment to crude oil and natural gas inventories in our Energy Services business segment of $6 million ($5 million after-tax) in 2023, compared with a net negative adjustment of $72 million ($55 million after-tax) in 2022;

•the receipt of a litigation claim settlement of $68 million ($52 million after-tax) in 2023;

•a net unrealized gain of $22 million ($19 million after-tax) in 2023, compared with a net loss of $27 million ($23 million after-tax) in 2022, reflecting changes in the mark-to-market value of equity fund investments held by our wholly-owned captive insurance subsidiaries;

•the absence in 2023 of an impairment of $44 million ($34 million after-tax) for lease assets due to office relocation plans;

•a non-cash, net positive equity earnings adjustment of $8 million ($6 million after-tax) in 2023, compared to a net negative adjustment of $34 million ($26 million after-tax) in 2022 relating to our share of changes in the mark-to-market value of derivative financial instruments of our equity method investees, DCP and Aux Sable; and

•the absence in 2023 of an asset impairment loss of $40 million ($31 million after-tax) relating to the MacKay River line within our Alberta Regional Oil Sands System; partially offset by

•a realized loss of $638 million ($479 million after-tax) due to termination of foreign exchange hedges, reflecting changes in the key settlement terms under the Competitive Toll Settlement (CTS).

After taking into consideration the factors above, the remaining $51 million increase in earnings attributable to common shareholders is primarily explained by the following significant business factors:

•higher contributions from the Mainline System and Line 9 in our Liquids Pipelines segment driven by increased volumes due to increased crude demand, net of a lower L3R surcharge;

•recognition of revenues in our Gas Transmission and Midstream segment attributable to the Texas Eastern rate case settlement;

•higher contributions from our Energy Services segment primarily due to the expiration of transportation commitments and favorable margins realized on facilities; and

•the favorable effect of translating US dollar earnings at a higher average exchange rate in 2023, compared to the same period in 2022; partially offset by

•higher power costs as a result of increased volumes and power prices in our Liquids Pipeline segment;

•lower commodity prices impacting the DCP and Aux Sable joint ventures in our Gas Transmission and Midstream segment;

•higher interest expense primarily due to higher interest rates and higher average principal; and

•higher depreciation and amortization due to assets placed into service in the second half of 2022.

BUSINESS SEGMENTS

LIQUIDS PIPELINES


	Three months ended June 30,		Six months ended June 30,
	2023	2022	2023	2022
(millions of Canadian dollars)
Earnings before interest, income taxes and depreciation and amortization	2,451	1,818	4,814	4,147

Three months ended June 30, 2023, compared with the three months ended June 30, 2022

EBITDA was positively impacted by $257 million due to certain infrequent or other non-operating factors, primarily explained by:

•a non-cash, net unrealized gain of $17 million in 2023, compared with a net unrealized loss of $196 million in 2022, reflecting changes in the mark-to-market value of derivative financial instruments used to manage foreign exchange risks; and

•the absence in 2023 of an asset impairment loss of $40 million relating to the MacKay River line within our Alberta Regional Oil Sands System.

After taking into consideration the factors above, the remaining $376 million increase is primarily explained by the following significant business factors:

•higher Mainline System ex-Gretna average throughput of 3.0 million barrels per day (mmbpd) in 2023 as compared to 2.8 mmbpd in 2022, higher Line 9 deliveries to eastern Canada driven by increased crude demand and the recognition of a lower provision against the interim Mainline IJT, net of a lower L3R surcharge;

•higher contributions from the Gulf Coast and Mid-Continent System due primarily to increased ownership of the Gray Oak Pipeline and Cactus II Pipeline acquired in the second half of 2022 and higher volumes from the Flanagan South Pipeline and the EIEC due to higher demand; and

•the favorable effect of translating US dollar earnings at a higher average exchange rate in 2023, compared to the same period in 2022; partially offset by

•higher power costs as a result of increased volumes and power prices.

Six months ended June 30, 2023, compared with the six months ended June 30, 2022

EBITDA was positively impacted by $154 million due to certain infrequent or other non-operating factors, primarily explained by the following:

•a non-cash, net unrealized gain of $630 million in 2023, compared with a net unrealized loss of $74 million in 2022, reflecting net fair value gains and losses arising from changes in the mark-to-market value of derivative financial instruments used to manage foreign exchange risks;

•the receipt of a litigation claim settlement of $68 million in 2023; and

•the absence in 2023 of an asset impairment loss of $40 million relating to the MacKay River line within our Alberta Regional Oil Sands System; partially offset by

•a realized loss of $638 million due to termination of foreign exchange hedges, reflecting changes in

the key settlement terms under the CTS.

After taking into consideration the factors above, the remaining $513 million increase is primarily explained by the following significant business factors:

•higher Mainline System ex-Gretna average throughput of 3.1 mmbpd in 2023 as compared to 2.9 mmbpd in 2022, and higher Line 9 deliveries to eastern Canada driven by increased crude demand, net of a lower L3R surcharge;

•the favorable effect of translating US dollar earnings at a higher average exchange rate in 2023, compared to the same period in 2022; partially offset by

•higher power costs as a result of increased volumes and power prices.

GAS TRANSMISSION AND MIDSTREAM


	Three months ended June 30,		Six months ended June 30,
	2023	2022	2023	2022
(millions of Canadian dollars)
Earnings before interest, income taxes and depreciation and amortization	1,042	1,119	2,247	2,133

Three months ended June 30, 2023, compared with the three months ended June 30, 2022

EBITDA was negatively impacted by $26 million due to certain infrequent or other non-operating factors, primarily explained by the absence in 2023 of a net positive adjustment of $22 million relating to our share of changes in the mark-to-market value of derivative financial instruments of our equity method investees, DCP and Aux Sable.

The remaining $51 million decrease is primarily explained by the following significant business factors:

•a reduction in earnings from our investment in DCP as a result of our decreased interest due to the joint venture merger transaction with Phillips 66 that closed during the third quarter in 2022;

•lower commodity prices impacting our DCP and Aux Sable joint ventures; and

•higher operating and administrative costs; partially offset by

•the favorable effect of translating US dollar earnings at a higher average exchange rate in 2023, compared to the same period in 2022;

•favorable contracting on our US Gas Transmission and Storage assets; and

•contributions from the Tres Palacios acquisition in the second quarter of 2023.

Six months ended June 30, 2023, compared with the six months ended June 30, 2022

EBITDA was positively impacted by $34 million due to certain infrequent or other non-operating factors, primarily explained by a non-cash, net positive equity earnings adjustment of $8 million in 2023, compared to a net negative adjustment of $34 million in 2022 relating to our share of changes in the mark-to-market value of derivative financial instruments of our equity method investees, DCP and Aux Sable.

The remaining $80 million increase is primarily explained by the following significant business factors:

•the recognition of revenues attributable to the Texas Eastern rate case settlement;

•the favorable effect of translating US dollar earnings at a higher average exchange rate in 2023, compared to the same period in 2022;

•favorable contracting on our US Gas Transmission and Storage assets; and

•contributions from the Tres Palacios acquisition in the second quarter of 2023; partially offset by

•a reduction in earnings from our investment in DCP as a result of our decreased interest due to the joint venture merger transaction with Phillips 66 that closed during the third quarter in 2022;

•lower commodity prices impacting our DCP and Aux Sable joint ventures; and

•higher operating and administrative costs.

GAS DISTRIBUTION AND STORAGE


	Three months ended June 30,		Six months ended June 30,
	2023	2022	2023	2022
(millions of Canadian dollars)
Earnings before interest, income taxes and depreciation and amortization	367	417	1,083	1,082

Three months ended June 30, 2023, compared with the three months ended June 30, 2022

EBITDA was negatively impacted by $50 million primarily explained by the following significant business factors:

•higher storage demand and transportation costs of $33 million which represents a partial reversal of previously favorable timing of recognition of these costs; and

•higher operating and administrative costs primarily due to higher costs for line locates and higher integrity spend; partially offset by

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

Six months ended June 30, 2023, compared with the six months ended June 30, 2022

EBITDA was positively impacted by $1 million primarily explained by the following significant business factors:

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

•favorable timing of recognition of storage demand and transportation costs of $30 million, which will be reversed over the remainder of 2023; offset by

•weather, when compared with the normal weather forecast embedded in rates, was warmer in 2023 and colder in 2022, resulting in a negative EBITDA impact of approximately $67 million year-over- year; and

•higher operating and administrative costs primarily due to higher costs for line locates and higher integrity spend.

RENEWABLE POWER GENERATION


	Three months ended June 30,		Six months ended June 30,
	2023	2022	2023	2022
(millions of Canadian dollars)
Earnings before interest, income taxes and depreciation and amortization	129	122	265	284

Three months ended June 30, 2023, compared with the three months ended June 30, 2022

EBITDA was positively impacted by $7 million primarily due to the following significant business factors:

•contributions from the Saint-Nazaire Offshore Wind Project, which reached full operating capacity in December 2022; partially offset by

•weaker wind resources at North American wind facilities; and

•lower energy pricing at European offshore wind facilities.

Six months ended June 30, 2023, compared with the six months ended June 30, 2022

EBITDA was negatively impacted by $19 million primarily due to the following significant business factors:

•weaker wind resources at North American wind facilities; and

•lower energy pricing at European offshore wind facilities; partially offset by

•contributions from the Saint-Nazaire Offshore Wind Project, which reached full operating capacity in December 2022.

ENERGY SERVICES


	Three months ended June 30,		Six months ended June 30,
	2023	2022	2023	2022
(millions of Canadian dollars)
Earnings/(loss) before interest, income taxes and depreciation and amortization	22	(177)	23	(278)

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

Three months ended June 30, 2023, compared with the three months ended June 30, 2022

EBITDA was positively impacted by $130 million due to certain non-operating factors, primarily explained by:

•a non-cash, net unrealized gain of $45 million in 2023, compared with a net loss of $16 million in 2022, reflecting the revaluation of derivatives used to manage the profitability of transportation and storage transactions, as well as to manage the exposure to movements in commodity prices; and

•a net positive adjustment to crude oil and natural gas inventories of $7 million in 2023, compared with a net negative adjustment of $62 million in 2022.

After taking into consideration the factors above, the remaining $69 million increase is primarily explained by:

•less pronounced market structure backwardation as compared to the same period of 2022;

•expiration of transportation commitments; and

•favorable margins realized on facilities where we hold capacity obligations and storage opportunities.

Six months ended June 30, 2023, compared with the six months ended June 30, 2022

EBITDA was positively impacted by $167 million due to certain non-operating factors, primarily explained by:

•a non-cash, unrealized gain of $53 million in 2023, compared with an unrealized loss of $36 million in 2022, reflecting the revaluation of derivatives used to manage the profitability of transportation and storage transactions, as well as manage the exposure to movements in commodity prices; and

•a net positive adjustment to crude oil and natural gas inventories of $6 million in 2023, compared with a net negative adjustment of $72 million in 2022.

After taking into consideration the factors above, the remaining $134 million increase is primarily explained by the same significant business factors as discussed in the three months ended June 30, 2023 results.

ELIMINATIONS AND OTHER


	Three months ended June 30,		Six months ended June 30,
	2023	2022	2023	2022
(millions of Canadian dollars)
Earnings/(loss) before interest, income taxes and depreciation and amortization	529	(704)	535	(349)

Eliminations and Other includes operating and administrative costs that are not allocated to business segments, and the impact of foreign exchange hedge settlements and the activities of our wholly-owned captive insurance subsidiaries. Eliminations and Other also includes the impact of new business development activities and corporate investments.

Three months ended June 30, 2023, compared with the three months ended June 30, 2022

EBITDA was positively impacted by $1,284 million due to certain infrequent or non-operating factors, primarily explained by:

•a non-cash, net unrealized gain of $485 million in 2023, compared with a net loss of $656 million in 2022, reflecting changes in the mark-to-market value of derivative financial instruments used to manage foreign exchange risk;

•the absence in 2023 of a $100 million restructuring expense associated with our enterprise insurance strategy; and

•a net unrealized gain of $9 million in 2023, compared with a net unrealized loss of $27 million in 2022 reflecting changes in the mark-to-market value of equity fund investments held by our wholly-owned captive insurance subsidiaries.

After taking into consideration the non-operating factors above, the remaining $51 million decrease is primarily explained by lower realized foreign exchange gains on hedge settlements in 2023.

Six months ended June 30, 2023, compared with the six months ended June 30, 2022

EBITDA was positively impacted by $968 million due to certain infrequent or non-operating factors, primarily explained by:

•a non-cash, unrealized gain of $403 million in 2023, compared with an unrealized loss of $347 million in 2022, reflecting the change in the mark-to-market value of derivative financial instruments used to manage foreign exchange risk;

•the absence in 2023 of $100 million restructuring expense associated with our enterprise insurance strategy;

•a net unrealized gain of $22 million in 2023, compared with a net loss of $27 million in 2022, reflecting changes in the mark-to-market value of equity fund investments held by our wholly-owned captive insurance subsidiaries; and

•the absence in 2023 of an impairment of $44 million for lease assets due to office relocation plans.

After taking into consideration the non-operating factors above, the remaining $84 million decrease is primarily explained by lower realized foreign exchange gains on hedge settlements in 2023.

GROWTH PROJECTS - COMMERCIALLY SECURED PROJECTS

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


		Enbridge's Ownership Interest		Estimated Capital Cost1	Expenditures to Date2	Status2	Expected In-Service Date
(Canadian dollars, unless stated otherwise)


GAS TRANSMISSION AND MIDSTREAM
1.	Texas Eastern Venice Extension	100	%	US$391 million	US$93 million	Pre-construction	2023 - 2024
2.	Texas Eastern Modernization	100	%	US$394 million	US$21 million	Pre-construction	2024 - 2025
3.	T-North Expansion3	100	%	$1.2 billion	$14 million	Pre-construction	2026
4.	Rio Bravo Pipeline	100	%	US$1.2 billion4	US$37 million	Pre-construction	2026
5.	Woodfibre LNG5	30	%	US$1.5 billion	US$210 million	Pre-construction	2027
6.	T-South Expansion3	100	%	$3.6 billion	$17 million	Pre-construction	2028


RENEWABLE POWER GENERATION
7.	Fécamp Offshore Wind6	17.9	%	$692 million	$445 million	Under construction	1Q - 2024
				(€471 million)	(€306 million)
8.	Calvados Offshore Wind7	21.7	%	$954 million	$286 million	Under construction	2025
				(€645 million)	(€197 million)

1These 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.

2Expenditures to date and status of the project are determined as at June 30, 2023.

3Capital cost estimates will be updated prior to filing the regulatory applications.

4Rio Grande LNG has reached a final investment decision for three liquefaction trains. Current estimated capital cost is based on two liquefaction trains and an update to the estimated capital cost is expected to be provided by the fourth quarter of 2023.

5Our equity contribution is US$893 million, with the remainder financed through non-recourse project level debt. Capital cost estimates will be updated prior to 60% engineering milestone, at which point Enbridge's preferred return will be set.

6Our equity contribution is $103 million, with the remainder financed through non-recourse project level debt.

7Our equity contribution is $181 million, with the remainder financed through non-recourse project level debt.

A full description of each of our projects is provided in our annual report on Form 10-K for the year ended December 31, 2022. Significant updates that have occurred since the date of filing of our Form 10-K are discussed below.

GAS TRANSMISSION AND MIDSTREAM

Rio Bravo Pipeline

In July 2023, the Rio Grande LNG export facility, owned by NextDecade Corporation (NextDecade), reached a final investment decision. As a result, the construction on our previously announced Rio Bravo Pipeline project will proceed after obtaining necessary regulatory approvals. The first phase of the Rio Bravo Pipeline will transport 2.6 bcf per day of natural gas feedstock to NextDecade's Rio Grande LNG export facility in the Port of Brownsville, Texas. The project is expected to achieve commercial operations in 2026.

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 help 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, share redemptions, execute share repurchases under our normal course issuer bid (NCIB) 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.

We have signed capital obligation contracts for the purchase of services, pipe and other materials totaling approximately $1.2 billion, which are expected to be paid over the next five years.

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

CAPITAL MARKET ACCESS

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

Credit Facilities and Liquidity

To ensure ongoing liquidity and to mitigate the risk of capital market disruption, we maintain ready access to funds through committed bank credit facilities and actively manage our bank funding sources to optimize pricing and other terms. The following table provides details of our committed credit facilities as at June 30, 2023:


	Maturity1	Total Facilities	Draws2	Available
(millions of Canadian dollars)
Enbridge Inc.	2024-2027	8,860	4,341	4,519
Enbridge (U.S.) Inc.	2024-2027	8,403	4,260	4,143
Enbridge Pipelines Inc.	2024	2,000	930	1,070
Enbridge Gas Inc.	2024	2,500	850	1,650
Total committed credit facilities		21,763	10,381	11,382

1Maturity date is inclusive of the one-year term out option for certain credit facilities.

2Includes facility draws and commercial paper issuances that are back-stopped by credit facilities.

In July 2023, Enbridge Pipelines Inc. extended the maturity date of its 364-day extendible credit facility to July 2025, which includes a one-year term out provision from July 2024.

As at June 30, 2023, our net available liquidity totaled $12.4 billion (December 31, 2022 - $10.0 billion), consisting of available credit facilities of $11.4 billion (December 31, 2022 - $9.1 billion) and unrestricted cash and cash equivalents of $1.0 billion (December 31, 2022 - $861 million) as reported in the Consolidated Statements of Financial Position.

LONG-TERM DEBT ISSUANCES

During the six months ended June 30, 2023, we completed the following long-term debt issuances totaling US$3.0 billion and $1.5 billion:

Company

Issue Date

Principal Amount

(millions of Canadian dollars, unless otherwise stated)

Enbridge Inc.

March 2023

5.70%

sustainability-linked senior notes due March 20331

US$2,300

March 2023

5.97%

senior notes due March 20262

US$700

May 2023

4.90%

medium-term notes due May 2028

$600

May 2023

5.36%

sustainability-linked medium-term notes due May 20333

$400

May 2023

5.76%

medium-term notes due May 2053

$500

2We have the option to call the notes at par after one year from issuance. Refer to Part 1. Item 1. Financial Statements - Note 8 - Risk Management and Financial Instruments.

LONG-TERM DEBT REPAYMENTS

During the six months ended June 30, 2023, we completed the following long-term debt repayments totaling US$1.2 billion and $0.7 billion:

Company

Repayment Date

Principal Amount

(millions of Canadian dollars, unless otherwise stated)

Enbridge Inc.

January 2023

3.94%

medium-term notes

$275

February 2023

Floating rate notes1

US$500

April 2023

6.38%

fixed-to-floating rate subordinated notes2

US$600

June 2023

3.94%

medium-term notes

$450

Enbridge Pipelines (Southern Lights) L.L.C.

June 2023

3.98%

senior notes

US$38

Enbridge Southern Lights LP

June 2023

4.01%

senior notes

Tri Global Energy, LLC

January 2023

10.00%

senior notes

US$4

January 2023

14.00%

senior notes

US$9

1The notes carried an interest rate set to equal the Secured Overnight Financing Rate plus a margin of 40 basis points.

2The five-year callable notes, with an original maturity date of April 2078, were all redeemed at par.

Strong internal cash flow, ready access to liquidity from diversified sources and a stable business model have enabled us to manage our credit profile. We actively monitor and manage key financial metrics with the objective of sustaining investment grade credit ratings from the major credit rating agencies and ongoing access to bank funding and term debt capital on attractive terms. Key measures of financial strength that are closely managed include the ability to service debt obligations from operating cash flow and the ratio of debt to EBITDA.

There are no material restrictions on our cash. Total restricted cash of $60 million, as reported on the Consolidated Statements of Financial Position, primarily includes reinsurance security, cash collateral, future pipeline abandonment costs collected and held in trust, amounts received in respect of specific shipper commitments and capital projects. Cash and cash equivalents held by certain subsidiaries may not be readily accessible for alternative uses by us.

Excluding current maturities of long-term debt, as at June 30, 2023 and December 31, 2022, we had positive and negative working capital positions of $1.0 billion and $2.1 billion, respectively. During the six months ended June 30, 2023, the major contributing factor to the positive working capital position was due to settlement of current liabilities, while during the year ended December 31, 2022, the negative working capital position was due to current liabilities associated with our growth capital program. We maintain significant liquidity in the form of committed credit facilities and other sources as previously discussed, which enable the funding of liabilities as they become due.

SOURCES AND USES OF CASH


	Six months ended June 30,
		2023	2022
(millions of Canadian dollars)
Operating activities		7,305	5,473
Investing activities		(2,333)	(2,120)
Financing activities		(4,770)	(2,605)
Effect of translation of foreign denominated cash and cash equivalents and restricted cash		(19)	20
Net change in cash and cash equivalents and restricted cash		183	768

Significant sources and uses of cash for the six months ended June 30, 2023 and 2022 are summarized below:

Operating Activities

Typically, the primary factors impacting cash provided by operating activities period-over-period include changes in our operating assets and liabilities in the normal course due to various factors, including the impact of fluctuations in commodity prices and activity levels on working capital within our business segments, the timing of tax payments and cash receipts and payments generally. Cash provided by operating activities is also impacted by changes in earnings and certain infrequent or other non-operating factors, as discussed in Results of Operations, as well as Distributions from equity investments. Changes in operating and assets and liabilities increased period-over-period primarily due to a larger decline in gas inventory balances in 2023 when compared to the same period in 2022, as well as the timing of natural gas cost recovery through rates, in Enbridge Gas.

Investing Activities

Cash used in investing activities primarily relates to capital expenditures to execute our 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. Cash used in investing activities is also impacted by acquisitions and changes in contributions to, and distributions from, our equity investments. The increase in cash used in investing activities period-over-period was primarily due to the acquisition of Tres Palacios on April 3, 2023, partially offset by higher equity distributions in 2023 mainly related to our investment in NEXUS Gas Transmission, LLC.

Financing Activities

Cash used in financing activities primarily relates to issuances and repayments of external debt, as well as transactions with our common and preference shareholders relating to dividends, share issuances, share redemptions and common share repurchases under our NCIB. Cash used in financing activities is also impacted by changes in distributions to, and contributions from, noncontrolling interests. Factors impacting the increase in cash used in financing activities period-over-period primarily include:

•net repayments of our short-term borrowings and commercial paper and credit facilities in 2023 when compared to net draws during the same period in 2022;

•higher long-term debt repayments in 2023 when compared to the same period in 2022; and

•an increase in common share dividend payments due to the increase in our common share dividend rate.

The factors above were partially offset by higher long-term debt issuances in 2023 when compared to the same period in 2022 and the absence in 2023 of the redemption of Preference Shares, Series 17 and Series J in the first and second quarters of 2022, respectively.

SUMMARIZED FINANCIAL INFORMATION

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

Consenting SEP notes and EEP notes under Guarantee


SEP Notes1			EEP Notes2
4.750% 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

1As at June 30, 2023, the aggregate outstanding principal amount of SEP notes was approximately US$3.2 billion.

2As at June 30, 2023, the aggregate outstanding principal amount of EEP notes was approximately US$2.4 billion.

Enbridge Notes under Guarantees


USD Denominated1			CAD Denominated2
Floating Rate Senior Notes due 2024			3.950% Senior Notes due 2024
4.000% Senior Notes due 2023			2.440% Senior Notes due 2025
0.550% Senior Notes due 2023			3.200% Senior Notes due 2027
3.500% Senior Notes due 2024			5.700% Senior Notes due 2027
2.150% Senior Notes due 2024			6.100% Senior Notes due 2028
2.500% Senior Notes due 2025			4.900% Senior Notes due 2028
2.500% Senior Notes due 2025			2.990% Senior Notes due 2029
4.250% Senior Notes due 2026			7.220% Senior Notes due 2030
1.600% Senior Notes due 2026			7.200% Senior Notes due 2032
5.969% Senior Notes due 2026			6.100% Sustainability-Linked Senior Notes due 2032
3.700% Senior Notes due 2027			3.100% Sustainability-Linked Senior Notes due 2033
3.125% Senior Notes due 2029			5.360% Sustainability-Linked Senior Notes due 2033
2.500% Sustainability-Linked Senior Notes due 2033			5.570% Senior Notes due 2035
5.700% Sustainability-Linked Senior Notes due 2033			5.750% Senior Notes due 2039
4.500% Senior Notes due 2044			5.120% Senior Notes due 2040
5.500% Senior Notes due 2046			4.240% Senior Notes due 2042
4.000% Senior Notes due 2049			4.570% Senior Notes due 2044
3.400% Senior Notes due 2051			4.870% Senior Notes due 2044
			4.100% Senior Notes due 2051
			6.510% Senior Notes due 2052
			5.760% Senior Notes due 2053
			4.560% Senior Notes due 2064

1As at June 30, 2023, the aggregate outstanding principal amount of the Enbridge US dollar-denominated notes was approximately US$13.5 billion.

2As at June 30, 2023, the aggregate outstanding principal amount of the Enbridge Canadian dollar-denominated notes was approximately $11.0 billion.

Rule 3-10 of the US SEC Regulation S-X provides an exemption from the reporting requirements of the Exchange Act for fully consolidated subsidiary issuers of guaranteed securities and subsidiary guarantors and allows for summarized financial information in lieu of filing separate financial statements for each of the Partnerships.

The following Summarized Combined Statement of Earnings and Summarized Combined Statements of Financial Position combines the balances of EEP, SEP and Enbridge.

Summarized Combined Statement of Earnings


Six months ended June 30,			2023
(millions of Canadian dollars)

Operating loss			(6)
Earnings			2,402
Earnings attributable to common shareholders			2,231

Summarized Combined Statements of Financial Position


	June 30, 2023	December 31, 2022
(millions of Canadian dollars)
Cash and cash equivalents	1,076	425
Accounts receivable from affiliates	3,705	2,486
Short-term loans receivable from affiliates	3,500	5,232
Other current assets	682	969
Long-term loans receivable from affiliates	42,378	43,873
Other long-term assets	3,486	4,111
Accounts payable to affiliates	2,665	1,375
Short-term loans payable to affiliates	1,524	1,745
Other current liabilities	6,100	8,752
Long-term loans payable to affiliates	36,364	37,626
Other long-term liabilities	46,178	47,447

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

Under US bankruptcy law and comparable provisions of state fraudulent transfer laws, a guarantee can be voided, or claims may be subordinated to all other debts of that guarantor if, among other things, the guarantor, at the time the indebtedness evidenced by its guarantee or, in some states, when payments become due under the guarantee:

•received less than reasonably equivalent value or fair consideration for the incurrence of the guarantee and was insolvent or rendered insolvent by reason of such incurrence;

•was engaged in a business or transaction for which the guarantor’s remaining assets constituted unreasonably small capital; or

•intended to incur, or believed that it would incur, debts beyond its ability to pay those debts as they mature.

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

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

Under the terms of the guarantee agreement and applicable supplemental indentures, the guarantees of either of the Partnerships of any Guaranteed Enbridge Notes will be unconditionally released and discharged automatically upon the occurrence of any of the following events:

•any direct or indirect sale, exchange or transfer, whether by way of merger, sale or transfer of equity interests or otherwise, to any person that is not an affiliate of Enbridge, of any of Enbridge’s direct or indirect limited partnership of other equity interests in that Partnership as a result of which the Partnership ceases to be a consolidated subsidiary of Enbridge;

•the merger of that Partnership into Enbridge or the other Partnership or the liquidation and dissolution of that Partnership;

•the repayment in full or discharge or defeasance of those Guaranteed Enbridge Notes, as contemplated by the applicable indenture or guarantee agreement;

•with respect to EEP, the repayment in full or discharge or defeasance of each of the consenting EEP notes listed above;

•with respect to SEP, the repayment in full or discharge or defeasance of each of the consenting SEP notes listed above; or

•with respect to any series of Guaranteed Enbridge Notes, with the consent of holders of at least a majority of the outstanding principal amount of that series of Guaranteed Enbridge Notes.

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

The Partnerships also guarantee the obligations of Enbridge under its existing credit facilities.

LEGAL AND OTHER UPDATES

Line 5 Easement (Bad River Band)

On July 23, 2019, the Bad River Band of the Lake Superior Tribe of Chippewa Indians (the Band) filed a complaint in the United States District Court for the Western District of Wisconsin (the Court) over our Line 5 pipeline and right-of-way across the Bad River Reservation (the Reservation). Only a small portion of the total easements across 12 miles of the Reservation are at issue. The Band alleges that our continued use of Line 5 to transport crude oil and related liquids across the Reservation is a public nuisance under federal and state law and that the pipeline is in trespass on certain tracts of land in which the Band possesses ownership interests. The complaint seeks an Order prohibiting us from using Line 5 to transport crude oil and related liquids across the Reservation and requiring removal of the pipeline from the Reservation. Subsequently amended versions of the complaint also seek recovery of profits-based damages based on an unjust enrichment theory. Enbridge has responded to each claim in the initial and amended complaints with an answer, defenses and counterclaims.

On August 29, 2022, the Government of Canada released a statement formally invoking the dispute settlement provisions of the 1977 Transit Pipelines Treaty in respect of this litigation; reiterating its concerns about the uninterrupted transmission of hydrocarbons through Line 5. On September 7, 2022, the Court issued a decision on cross-motions for summary judgment. The Court determined that the Band’s nuisance claim raised factual issues that could not be resolved on summary judgment. The Court further determined that Enbridge is in trespass on 12 parcels on the Reservation and that the Band is entitled to some measure of profits-based damages and to an injunction, with the level of damages and scope of the injunction to be determined at trial, which occurred October 24 through November 1, 2022.

On May 9, 2023, the Band filed an Emergency Motion for Injunctive Relief asking the Court to require Enbridge to purge and shutdown Line 5 on the Bad River Reservation due to significant erosion at the Meander. Enbridge responded and a hearing was held on May 18, 2023 in front of Judge Conley who indicated that he did not find the Band had proven imminence but his final ruling on all issues would be provided soon.

On June 26, 2023, the Court issued its Final Order ruling that (1) Enbridge shall adopt and implement its 2022 Monitoring and Shutdown Plan with the Court’s modifications by July 5, 2023; (2) Enbridge owes the Band $5,151,668 for past trespass on the 12 allotted parcels; (3) Enbridge must continue to pay money on a quarterly basis using the formula set in its Order as long as Line 5 operates in trespass on the 12 allotted parcels (approximately $400,000 per year); (4) Enbridge must cease operation of Line 5 on any parcel within the Band’s tribal territory without a valid right of way by June 16, 2026 and thereafter arrange prompt, reasonable remediation at those sites; and (5) The Court declined to allow for the Relocation to be completed prior to having to cease operations. The Final Judgment was entered on June 29, 2023. Enbridge filed its Notice of Appeal on June 30, 2023 and the Band filed its Notice of Cross Appeal on July 27, 2023. The 7th Circuit Court of Appeals issued a Notice of Telephonic Mediation for July 21, 2023, which occurred as scheduled. On July 31, 2023, the Court entered the parties agreed upon briefing schedule. According to that schedule, briefing should be complete on or before December 8, 2023.

Michigan Line 5 Dual Pipelines - Straits of Mackinac Easement

In 2019, the Michigan Attorney General (AG) filed a complaint in the Michigan Ingham County Circuit Court (the Circuit Court) that requests the Circuit Court to declare the easement granted in 1953 that we have for the operation of Line 5 in the Straits of Mackinac (the Straits) to be invalid and to prohibit continued operation of Line 5 in the Straits. On December 15, 2021, Enbridge removed the case to the US District Court in the Western District of Michigan (US District Court), where it was assigned to Judge Janet T. Neff. The removal of the AG’s case to federal court followed a November 16, 2021 ruling which held that the similar (and now dismissed) 2020 lawsuit brought by the Governor of Michigan to force Line 5’s shutdown raised important federal issues that should be heard in federal court. On December 21, 2021, the AG made a request to file a motion to remand the 2019 case, which the US District Court allowed on January 5, 2022. However, after full briefing, on August 18, 2022, Judge Neff denied the AG’s motion to remand. On August 30, 2022, the AG filed a motion to certify the August 18 Order to pursue an appeal on the jurisdictional issue, which Enbridge opposed. On February 21, 2023, that motion was granted and shortly after, on March 2, 2023, the AG filed her Petition for Permission to Appeal in the 6th Circuit Court of Appeals (6th Circuit). Enbridge responded and on July 21, 2023, the 6th Circuit granted the AG’s Petition. In the meantime, this case will remain on hold in US District Court. It will likely take approximately 12 to 18 months for additional briefing and a decision.

OTHER LITIGATION

We and our subsidiaries are involved in various other legal and regulatory actions and proceedings which arise in the normal course of business, including interventions in regulatory proceedings and challenges to regulatory approvals and permits. While the final outcome of such actions and proceedings cannot be predicted with certainty, management believes that the resolution of such actions and proceedings will not have a material impact on our consolidated financial position or results of operations.

TAX MATTERS

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Our exposure to market risk is described in Part II. Item 7A. Quantitative and Qualitative Disclosures About Market Risk of our annual report on Form 10-K for the year ended December 31, 2022. We believe our exposure to market risk has not changed materially since then.

ITEM 4. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

Disclosure controls and procedures are controls and other procedures that are designed to ensure that information required to be disclosed by us in the reports we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified by the SEC's rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to provide reasonable assurance that information required to be disclosed by us in the reports we file or submit under the Exchange Act is accumulated and communicated to management, including the Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure.

Under the supervision of and with the participation of management, including the Chief Executive Officer and Chief Financial Officer, we have evaluated the effectiveness of our disclosure controls and procedures (as such term is defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as at June 30, 2023, and based upon this evaluation, the Chief Executive Officer and Chief Financial Officer have concluded that these controls and procedures are effective in ensuring that information required to be disclosed by us in reports that we file with or submit to the SEC and the Canadian Securities Administrators is recorded, processed, summarized and reported within the time periods required.

Changes in Internal Control over Financial Reporting

Under the supervision of and with the participation of management, including the Chief Executive Officer and Chief Financial Officer, we have evaluated changes in internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) that occurred during the fiscal quarter ended June 30, 2023 and found no change that has materially affected, or is reasonably likely to materially affect, internal control over financial reporting.

PART II - OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

We are involved in various legal and regulatory actions and proceedings which arise in the ordinary course of business. While the final outcome of such actions and proceedings cannot be predicted with certainty, management believes that the resolution of such actions and proceedings will not have a material impact on our consolidated financial position or results of operations. Refer to Part I. Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations - Legal and Other Updates for discussion of other legal proceedings.

SEC regulations require the disclosure of any proceeding under environmental laws to which a governmental authority is a party unless the registrant reasonably believes it will not result in monetary sanctions over a certain threshold. Given the size of our operations, we have elected to use a threshold of US$1 million for the purposes of determining proceedings requiring disclosure.

As part of its ongoing post-construction monitoring activities for L3R, Enbridge reported groundwater flow near Moose Lake in Aitkin County to the Minnesota Department of Natural Resources (DNR). Enbridge has been working cooperatively with DNR and other agencies and will provide a corrective action plan for this location as requested and implement it upon approval. For additional information, please see our annual report on Form 10-K for the year ended December 31, 2022.

ITEM 1A. RISK FACTORS

In addition to the other information set forth in this report, careful consideration should be given to the factors discussed in Part I. Item 1A. Risk Factors of our annual report on Form 10-K for the year ended December 31, 2022, which could materially affect our financial condition or future results. There have been no material modifications to those risk factors.

ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

ISSUER PURCHASES OF EQUITY SECURITIES


Period	Total number of shares purchased	Average price paid per share	Total number of shares purchased as part of publicly announced plans or programs	Maximum number of shares that may yet be purchased under the plans or programs1
April 2023 (April 1 - April 30)	478,500	CAD$52.24 (TSX)/CAD$52.25 (Other)	478,500	27,459,663
May 2023 (May 1 - May 31)	1,521,300	CAD$49.25 (TSX)/CAD$49.24 (Other)	1,521,300	25,938,363
June 2023 (June 1 - June 30)	504,556	CAD $49.55 (TSX)/ CAD $49.55 (Other)	504,556	25,433,807

1On January 4, 2023, the Toronto Stock Exchange (TSX) approved our NCIB to purchase, for cancellation, up to 27,938,163 of the outstanding common shares of Enbridge to an aggregate amount of up to $1.5 billion. Purchases under the NCIB may be made through the facilities of the TSX, the New York Stock Exchange and other designated exchanges and alternative trading systems. Our NCIB commenced on January 6, 2023 and continues until January 5, 2024, when it expires, or such earlier date on which we have either acquired the maximum number of common shares allowable or otherwise decide not to make further repurchases.

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

None.

ITEM 4. MINE SAFETY DISCLOSURES

Not applicable.

ITEM 5. OTHER INFORMATION

Certain of our officers and directors have made elections to participate in, and are participating in, our compensation and benefit plans involving Enbridge stock, such as our 401(k) plan and directors’ compensation plan, and may from time to time make elections which may be designed to satisfy the affirmative defense conditions of Rule 10b5-1 under the Exchange Act or may constitute non-Rule 10b5-1 trading arrangements (as defined in Item 408(c) of Regulation S-K).

ITEM 6. EXHIBITS

Each exhibit identified below is included as a part of this quarterly report. Exhibits included in this filing are designated by an asterisk ("*"); all exhibits not so designated are incorporated by reference to a prior filing as indicated. Exhibits designated with a "^" are furnished herewith.


Exhibit No.						Description
4.1						Shareholder Rights Plan Agreement between Enbridge Inc. and Computershare Trust Company of Canada dated as of November 9, 1995 and Amended and Restated as of May 3, 2023 (incorporated by reference to Exhibit 4.1 to Enbridge’s Current Report on Form 8-K filed May 4, 2023).
22.1*						Subsidiary Guarantors
31.1*						Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2*						Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1*^						Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2*^						Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101.SCH*						Inline XBRL Taxonomy Extension Schema Document.
101.CAL*						Inline XBRL Taxonomy Extension Calculation Linkbase Document.
101.DEF*						Inline XBRL Taxonomy Extension Definition Linkbase Document.
101.LAB*						Inline XBRL Taxonomy Extension Label Linkbase Document.
101.PRE*						Inline XBRL Taxonomy Extension Presentation Linkbase Document.
104						Cover Page Interactive Data File - the cover page XBRL tags are embedded within the Inline XBRL document (included in Exhibit 101)

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.


			ENBRIDGE INC.
			(Registrant)

Date:	August 4, 2023	By:	/s/ Gregory L. Ebel
			Gregory L. Ebel President, Chief Executive Officer and Director (Principal Executive Officer)

Date:	August 4, 2023	By:	/s/ Patrick R. Murray
			Patrick R. Murray Executive Vice President and Chief Financial Officer (Principal Financial Officer)