SEC Form 10-Q filed by Enbridge Inc

5/10/24 7:04:40 AM ET

Natural Gas Distribution

Energy

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enb-20240331

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 March 31, 2024


☐						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

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 2,126,090,754 common shares outstanding as at May 3, 2024.


	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	53
Item 4.	Controls and Procedures	54

	PART II

Item 1.	Legal Proceedings	55
Item 1A.	Risk Factors	55
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	55
Item 3.	Defaults Upon Senior Securities	55
Item 4.	Mine Safety Disclosures	55
Item 5.	Other Information	56
Item 6.	Exhibits	56
	Signatures	57

GLOSSARY


"we", "our", "us" and "Enbridge"			Enbridge Inc.

AOCI			Accumulated other comprehensive income/(loss)
ASC			Accounting Standards Codification


CER			Canada Energy Regulator



EBITDA			Earnings before interest, income taxes and depreciation and amortization

EEP			Enbridge Energy Partners, L.P.







EOG			The East Ohio Gas Company

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




LNG			Liquefied natural gas








MTS			Mainline Tolling Settlement



OCI			Other comprehensive income/(loss)

OEB			Ontario Energy Board
OPEB			Other postretirement benefits



Phase 1 Decision			The Ontario Energy Board's Decision and Order on December 21, 2023, on Phase 1 of Enbridge Gas Inc.'s application to establish a 2024 through 2028 Incentive Regulation rate setting framework

SEP			Spectra Energy Partners, LP





the Acquisitions			Enbridge Inc.'s acquisitions of three US gas utilities from Dominion Energy, Inc.



the Band			Bad River Band of the Lake Superior Tribe of Chippewa Indians


the EOG Acquisition			Enbridge Inc.'s acquisition of all outstanding shares of capital stock in The East Ohio Gas Company on March 6, 2024
the Partnerships			Spectra Energy Partners, LP and Enbridge Energy Partners, L.P.
the Reservation			Bad River Reservation

Tomorrow RNG			Six Morrow Renewables operating landfill gas-to-renewable natural gas production facilities

US			United States of America

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), liquefied natural gas (LNG), renewable natural gas (RNG) 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, Gas Distribution and Storage and Renewable Power Generation businesses; the characteristics, anticipated benefits, financing and timing of our acquisitions and other transactions, including the acquisitions of three US gas utilities (Gas Utilities) from Dominion Energy, Inc. (the Acquisitions) and the joint venture with WhiteWater Midstream, LLC/I Squared Capital and MPLX LP (the Whistler Parent JV); expected costs, benefits and in-service dates related to announced projects and projects under construction; expected capital expenditures; investable capacity and capital allocation priorities; 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; our ability to complete the Acquisitions and successfully integrate the Gas Utilities; expected closing of other acquisitions and dispositions and the timing thereof, including the remaining Acquisitions, and the Whistler Parent JV; 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 those relating to the Gas Distribution and Storage business; 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, RNG 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 and transactions; anticipated in-service dates; weather; the timing, terms and closing of acquisitions and dispositions, including the Acquisitions; the realization of anticipated benefits of transactions, including the Acquisitions; 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, RNG 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 (including the 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.sedarplus.ca or www.sec.gov.

PART I - FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

ENBRIDGE INC.

CONSOLIDATED STATEMENTS OF EARNINGS


	Three months ended March 31,
		2024	2023
(unaudited; millions of Canadian dollars, except per share amounts)
Operating revenues
Commodity sales		4,145	4,783
Gas distribution sales		1,699	2,279
Transportation and other services		5,194	5,013
Total operating revenues (Note 3)		11,038	12,075
Operating expenses
Commodity costs		4,006	4,636
Gas distribution costs		994	1,594
Operating and administrative		2,134	2,037
Depreciation and amortization		1,193	1,146

Total operating expenses		8,327	9,413
Operating income		2,711	2,662
Income from equity investments		696	517


Other income/(expense) (Note 11)		(551)	102
Interest expense		(905)	(905)
Earnings before income taxes		1,951	2,376
Income tax expense		(386)	(510)
Earnings		1,565	1,866
Earnings attributable to noncontrolling interests		(53)	(49)
Earnings attributable to controlling interests		1,512	1,817
Preference share dividends		(93)	(84)
Earnings attributable to common shareholders		1,419	1,733
Earnings per common share attributable to common shareholders (Note 5)		0.67	0.86
Diluted earnings per common share attributable to common shareholders (Note 5)		0.67	0.85

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

ENBRIDGE INC.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME


	Three months ended March 31,
		2024	2023
(unaudited; millions of Canadian dollars)
Earnings		1,565	1,866
Other comprehensive income/(loss), net of tax
Change in unrealized gain/(loss) on cash flow hedges		116	(45)
Change in unrealized gain/(loss) on net investment hedges		(377)	15
Other comprehensive loss from equity investees		(1)	—
Excluded components of fair value hedges		4	7
Reclassification to earnings of loss on cash flow hedges		—	7
Reclassification to earnings of pension and other postretirement benefits (OPEB) amounts		(4)	(4)

Foreign currency translation adjustments		1,658	(59)
Other comprehensive income/(loss), net of tax		1,396	(79)
Comprehensive income		2,961	1,787
Comprehensive income attributable to noncontrolling interests		(88)	(64)
Comprehensive income attributable to controlling interests		2,873	1,723
Preference share dividends		(93)	(84)
Comprehensive income attributable to common shareholders		2,780	1,639

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

ENBRIDGE INC.

CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY


	Three months ended March 31,
		2024	2023
(unaudited; millions of Canadian dollars, except per share amounts)
Preference shares


Balance at beginning and end of period		6,818	6,818
Common shares
Balance at beginning of period		69,180	64,760

Shares issued on exercise of stock options		4	2
Shares issued on vesting of restricted stock units (RSU), net of tax		17	12


Balance at end of period		69,201	64,774
Additional paid-in capital
Balance at beginning of period		268	275
Stock-based compensation		32	20
Stock options exercised		(4)	(1)
Vested RSUs		(22)	(20)


Balance at end of period		274	274
Deficit
Balance at beginning of period		(17,115)	(15,486)
Earnings attributable to controlling interests		1,512	1,817
Preference share dividends		(93)	(84)




Balance at end of period		(15,696)	(13,753)
Accumulated other comprehensive income/(loss) (Note 8)
Balance at beginning of period		2,303	3,520
Other comprehensive income attributable to common shareholders, net of tax		1,361	(94)
Balance at end of period		3,664	3,426




Total Enbridge Inc. shareholders’ equity		64,261	61,539
Noncontrolling interests
Balance at beginning of period		3,029	3,511
Earnings attributable to noncontrolling interests		53	49
Other comprehensive income/(loss) attributable to noncontrolling interests, net of tax
Change in unrealized gain on cash flow hedges		6	17
Foreign currency translation adjustments		29	(2)
		35	15
Comprehensive income attributable to noncontrolling interests		88	64
Distributions		(78)	(92)
Contributions		2	4

Other		1	(1)
Balance at end of period		3,042	3,486
Total equity		67,303	65,025
Dividends paid per common share		0.92	0.89

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

ENBRIDGE INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS


	Three months ended March 31,
	2024	2023
(unaudited; millions of Canadian dollars)
Operating activities
Earnings	1,565	1,866
Adjustments to reconcile earnings to net cash provided by operating activities:
Depreciation and amortization	1,193	1,146
Deferred income tax expense	134	484
Unrealized derivative fair value loss/(gain), net (Note 9)	693	(520)
Income from equity investments	(696)	(517)
Distributions from equity investments	556	453




Other	6	40
Changes in operating assets and liabilities	(300)	914
Net cash provided by operating activities	3,151	3,866
Investing activities
Capital expenditures	(1,185)	(1,129)
Long-term, restricted and other investments	(411)	(413)
Distributions from equity investments in excess of cumulative earnings	266	100
Additions to intangible assets	(42)	(66)
Acquisitions	(6,397)	—


Net change in affiliate loans	—	71
Other	(23)	—
Net cash used in investing activities	(7,792)	(1,437)
Financing activities
Net change in short-term borrowings	(65)	(559)
Net change in commercial paper and credit facility draws	5,828	(2,921)
Debenture and term note issues, net of issue costs	—	4,111
Debenture and term note repayments	(3,781)	(968)
Contributions from noncontrolling interests	2	4
Distributions to noncontrolling interests	(78)	(92)


Preference share dividends	(93)	(84)
Common share dividends	(1,945)	(1,798)

Net change in affiliate loans	14	51
Other	(2)	(33)
Net cash used in financing activities	(120)	(2,289)
Effect of translation of foreign denominated cash and cash equivalents and restricted cash	161	4
Net change in cash and cash equivalents and restricted cash	(4,600)	144
Cash and cash equivalents and restricted cash at beginning of period	5,985	907
Cash and cash equivalents and restricted cash at end of period	1,385	1,051

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

ENBRIDGE INC.

CONSOLIDATED STATEMENTS OF FINANCIAL POSITION


	March 31, 2024	December 31, 2023
(unaudited; millions of Canadian dollars; number of shares in millions)
Assets
Current assets
Cash and cash equivalents	1,214	5,901
Restricted cash	171	84
Trade receivables and unbilled revenues	4,916	4,410
Other current assets	2,239	2,440
Accounts receivable from affiliates	89	85
Inventory	1,383	1,479
	10,012	14,399
Property, plant and equipment, net	113,445	104,641
Long-term investments	17,438	16,793
Restricted long-term investments	743	717
Deferred amounts and other assets	9,782	8,041
Intangible assets, net	4,528	3,537
Goodwill	34,294	31,848
Deferred income taxes	471	341
Total assets	190,713	180,317

Liabilities and equity
Current liabilities
Short-term borrowings	335	400
Trade payables and accrued liabilities	3,820	4,308
Other current liabilities	3,748	5,659
Accounts payable to affiliates	20	26
Interest payable	934	958
Current portion of long-term debt	5,861	6,084
	14,718	17,435
Long-term debt	81,386	74,715
Other long-term liabilities	10,619	8,653
Deferred income taxes	16,687	15,031
	123,410	115,834
Contingencies (Note 12)
Equity
Share capital
Preference shares	6,818	6,818
Common shares (2,126 and 2,125 outstanding at March 31, 2024 and December 31, 2023, respectively)	69,201	69,180
Additional paid-in capital	274	268
Deficit	(15,696)	(17,115)
Accumulated other comprehensive income (Note 8)	3,664	2,303

Total Enbridge Inc. shareholders’ equity	64,261	61,454
Noncontrolling interests	3,042	3,029
	67,303	64,483
Total liabilities and equity	190,713	180,317

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, 2023. 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, 2023. 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. CHANGES IN ACCOUNTING POLICIES

FUTURE ACCOUNTING POLICY CHANGES

Segment Reporting

Accounting Standards Update (ASU) 2023-07 was issued in November 2023 to improve reportable segment disclosure requirements primarily through enhanced disclosures about significant segment expenses and to require in interim period financial statements all disclosures about a reportable segment's profit or loss and assets that are currently required annually. The new ASU requires entities to disclose the title and position of the individual or the name of the group or committee identified as the chief operating decision-maker (CODM) of each segment. ASU 2023-07 is effective January 1, 2024, with interim period disclosure requirements effective after January 1, 2025 and should be applied retrospectively to all prior periods presented in the financial statements. We are currently assessing the impact of the new standard on our interim financial statement disclosures for 2025 and the required annual disclosures will be adopted for the year ending December 31, 2024.

Income Tax Disclosures

ASU 2023-09 was issued in December 2023 to improve income tax disclosures by requiring specified categories in the annual rate reconciliation that meet quantitative thresholds and further disaggregation on income taxes paid by jurisdiction. ASU 2023-09 is effective January 1, 2025 and should be applied prospectively, with retrospective application being permitted. We are currently assessing the impact of the new standard on our consolidated financial statements.

3. REVENUE

REVENUE FROM CONTRACTS WITH CUSTOMERS

Major Products and Services


Three months ended March 31, 2024	Liquids Pipelines	Gas Transmission	Gas Distribution and Storage	Renewable Power Generation	Eliminations and Other	Consolidated
(millions of Canadian dollars)
Transportation revenue	3,024	1,341	351	—	—	4,716
Storage and other revenue	62	138	99	—	—	299

Gas distribution revenue	—	—	1,666	—	—	1,666
Electricity revenue	—	—	—	57	—	57
Commodity sales	—	40	—	—	—	40
Total revenue from contracts with customers	3,086	1,519	2,116	57	—	6,778
Commodity sales	3,733	41	—	—	331	4,105
Other revenue1,2	63	6	13	73	—	155
Intersegment revenue	—	6	2	1	(9)	—
Total revenue	6,882	1,572	2,131	131	322	11,038


Three months ended March 31, 2023	Liquids Pipelines	Gas Transmission	Gas Distribution and Storage	Renewable Power Generation	Eliminations and Other	Consolidated
(millions of Canadian dollars)
Transportation revenue	2,942	1,384	276	—	—	4,602
Storage and other revenue	64	95	99	—	—	258

Gas distribution revenue	—	—	2,287	—	—	2,287
Electricity revenue	—	—	—	66	—	66

Total revenue from contracts with customers	3,006	1,479	2,662	66	—	7,213
Commodity sales	4,262	—	—	—	521	4,783
Other revenue1,2	30	11	(40)	78	—	79
Intersegment revenue	—	1	3	—	(4)	—
Total revenue	7,298	1,491	2,625	144	517	12,075

1Includes realized and unrealized gains and losses from our hedging program which for the three months ended March 31, 2024 were a net $22 million loss (2023 - $55 million loss).

2Includes revenues from lease contracts for the three months ended March 31, 2024 and 2023 of $140 million and $144 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 March 31, 2024	2,962	337	2,537
Balance as at December 31, 2023	2,802	400	2,591

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 months ended March 31, 2024 included in contract liabilities at the beginning of the period was $151 million. Increases in contract liabilities from cash received, net of amounts recognized as revenues, during the three months ended March 31, 2024 were $117 million.

Performance Obligations

There were no material revenues recognized in the three months ended March 31, 2024 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 $60.5 billion, of which $6.2 billion and $7.9 billion are expected to be recognized during the remaining nine months ending December 31, 2024 and the year ending December 31, 2025, respectively.

The revenues excluded from the amounts above based on optional exemptions available under Accounting Standards Codification (ASC) 606, as explained below, represent a significant portion of our overall revenues and revenues from contracts with customers. Certain revenues such as flow-through operating costs charged to shippers are recognized at the amount for which we have the right to invoice our customers and are excluded from the amounts for 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.

Mainline Tolling Agreement

On March 4, 2024, the Canadian Energy Regulator (CER) approved the negotiated Mainline tolling settlement. The new tolls are finalized and were in effect on an interim basis on July 1, 2023, and the overall agreement is retroactively effective as of July 1, 2021.

Recognition and Measurement of Revenues














Three months ended March 31, 2024	Liquids Pipelines	Gas Transmission	Gas Distribution and Storage	Renewable Power Generation	Consolidated
(millions of Canadian dollars)
Revenues from products transferred at a point in time	—	40	29	—	69
Revenues from products and services transferred over time1	3,086	1,479	2,087	57	6,709
Total revenue from contracts with customers	3,086	1,519	2,116	57	6,778

Three months ended March 31, 2023	Liquids Pipelines	Gas Transmission	Gas Distribution and Storage	Renewable Power Generation	Consolidated
(millions of Canadian dollars)
Revenues from products transferred at a point in time	—	—	30	—	30
Revenues from products and services transferred over time1	3,006	1,479	2,632	66	7,183
Total revenue from contracts with customers	3,006	1,479	2,662	66	7,213

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.

4. SEGMENTED INFORMATION

Change in Reportable Segments

Effective January 1, 2024, to better align how the CODM reviews operating performance and resource allocation across operating segments, we transferred our Canadian and United States (US) crude oil marketing businesses from the Energy Services segment to the Liquids Pipelines segment. As a result, the Energy Services segment ceased to exist and the remainder of the business, comprising natural gas and power marketing, are now reported in the Eliminations and Other segment. Beginning in the first quarter of 2024, prior period comparable results for segmented information have been recast to reflect the change in reportable segments. This segment reporting change does not have an impact on our consolidated results.


Three months ended March 31, 2024	Liquids Pipelines	Gas Transmission	Gas Distribution and Storage	Renewable Power Generation	Eliminations and Other1	Consolidated
(millions of Canadian dollars)
Operating revenues (Note 3)	6,882	1,572	2,131	131	322	11,038
Commodity and gas distribution costs	(3,635)	(47)	(1,004)	(3)	(311)	(5,000)
Operating and administrative	(1,107)	(561)	(379)	(69)	(18)	(2,134)


Income/(loss) from equity investments	253	265	—	181	(3)	696


Other income/(expense) (Note 11)	11	36	17	17	(632)	(551)
Earnings/(loss) before interest, income taxes and depreciation and amortization	2,404	1,265	765	257	(642)	4,049
Depreciation and amortization						(1,193)
Interest expense						(905)
Income tax expense						(386)
Earnings						1,565
Capital expenditures2	289	495	304	69	43	1,200


Three months ended March 31, 2023	Liquids Pipelines	Gas Transmission	Gas Distribution and Storage	Renewable Power Generation	Eliminations and Other1	Consolidated
(millions of Canadian dollars)
Operating revenues (Note 3)	7,298	1,491	2,625	144	517	12,075
Commodity and gas distribution costs	(4,132)	—	(1,612)	(4)	(482)	(6,230)
Operating and administrative	(1,135)	(549)	(309)	(53)	9	(2,037)


Income/(loss) from equity investments	248	238	—	35	(4)	517


Other income/(expense) (Note 11)	74	25	12	14	(23)	102
Earnings before interest, income taxes and depreciation and amortization	2,353	1,205	716	136	17	4,427
Depreciation and amortization						(1,146)
Interest expense						(905)
Income tax expense						(510)
Earnings						1,866
Capital expenditures2	280	527	264	45	25	1,141

1Includes operating revenues and commodity costs from our natural gas and power marketing subsidiaries for the three months ended March 31, 2024 of $332 million (2023 - $520 million) and $322 million (2023 - $499 million), respectively.

2Includes allowance for equity funds used during construction.

5. EARNINGS PER COMMON SHARE AND DIVIDENDS PER SHARE

BASIC

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

DILUTED

The treasury stock method is used to determine the dilutive impact of stock options and share-settled RSUs. This method assumes any proceeds from the exercise of stock options and vesting of share-settled 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 common share are as follows:


	Three months ended March 31,
		2024	2023
(number of shares in millions)
Weighted average shares outstanding		2,126	2,025
Effect of dilutive options and RSUs		2	3
Diluted weighted average shares outstanding		2,128	2,028

For the three months ended March 31, 2024 and 2023, 23.0 million and 16.7 million, respectively, of anti-dilutive stock options with a weighted average exercise price of $52.97 and $55.62, respectively, were excluded from the diluted earnings per common share calculation.

DIVIDENDS PER SHARE

On April 23, 2024, our Board of Directors declared the following quarterly dividends. All dividends are payable on June 1, 2024 to shareholders of record on May 15, 2024.


			Dividend per share
Common Shares			$0.91500
Preference Shares, Series A			$0.34375
Preference Shares, Series B			$0.32513
Preference Shares, Series D			$0.33825
Preference Shares, Series F			$0.34613
Preference Shares, Series G1			$0.47383
Preference Shares, Series H			$0.38200
Preference Shares, Series I2			$0.44932
Preference Shares, Series L			US$0.36612
Preference Shares, Series N			$0.41850
Preference Shares, Series P3			$0.36988
Preference Shares, Series R			$0.25456
Preference Shares, Series 1			US$0.41898
Preference Shares, Series 3			$0.23356
Preference Shares, Series 54			US$0.41769
Preference Shares, Series 75			$0.37425
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 G was decreased to $0.47383 from $0.47676 on March 1, 2024 due to reset on a quarterly basis.

2The quarterly dividend per share paid on Preference Shares, Series I was decreased to $0.44932 from $0.45251 on March 1, 2024 due to reset on a quarterly basis.

3The quarterly dividend per share paid on Preference Shares, Series P was increased to $0.36988 from $0.27369 on March 1, 2024 due to reset of the annual dividend on March 1, 2024.

4The quarterly dividend per share paid on Preference Shares, Series 5 was increased to US$0.41769 from US$0.33596 on March 1, 2024 due to reset of the annual dividend on March 1, 2024.

5The quarterly dividend per share paid on Preference Shares, Series 7 was increased to $0.37425 from $0.27806 on March 1, 2024 due to reset of the annual dividend on March 1, 2024.

6. ACQUISITIONS

THE EAST OHIO GAS COMPANY

On March 6, 2024, through a wholly-owned US subsidiary, we acquired all of the outstanding shares of capital stock in The East Ohio Gas Company (EOG) for cash consideration of $5.8 billion (US$4.3 billion) (the EOG Acquisition). EOG is a public natural gas utility providing distribution, storage and transmission services to residential, commercial and industrial customers in Ohio and is regulated by the Public Utilities Commission of Ohio and the Federal Energy Regulatory Commission. The EOG Acquisition is complementary to our other operations in Ohio.

We accounted for the EOG Acquisition using the acquisition method as prescribed by ASC 805 Business Combinations. In accordance with valuation methodologies described in ASC 820 Fair Value Measurement, acquired assets and assumed liabilities are recorded at their estimated fair values as at the date of acquisition.

The fair values of regulatory assets and liabilities, which are subject to rate-setting and cost recovery mechanisms under ASC 980, are equal to their carrying values at acquisition. The recognition of regulatory assets and liabilities is based on the actions, or expected future actions, of the regulator. To the extent that the regulator's actions differ from our expectations, the timing and amount of recovery or settlement of regulatory balances could differ significantly from those recorded at acquisition.

The purchase price allocation was prepared on a preliminary basis and is subject to change as additional information becomes available concerning the fair values of the pension and regulatory balances and their tax bases. Any adjustments to the purchase price allocation will be made as soon as practicable, but no later than one year from the date of acquisition.

The following table summarizes the estimated preliminary fair values that were assigned to the net assets of EOG:


			March 6, 2024
(millions of Canadian dollars)
Fair value of net assets acquired:
Current assets (a)			641
Property, plant and equipment (b)			7,253
Long-term assets (c)			1,647
Current liabilities			670
Long-term debt (d)			2,612
Other long-term liabilities (e)			993
Deferred income tax liabilities			1,036
Goodwill (f)			1,608
Purchase price:
Cash			5,838

a) Current assets consist primarily of cash, trade and other accounts receivable, prepaid expenses, regulatory assets and inventory. The fair value of trade receivables from customers approximates their carrying value of $376 million due to the short period to maturity. A provision for credit and recovery risk associated with accounts receivable has been made through the expected credit loss, which totaled $3 million.

b) EOG's property, plant and equipment constitutes an integrated system of rate-regulated natural gas transmission, gathering, distribution and storage assets. For these rate-regulated assets, fair value was determined using a market participant perspective. Given the regulated nature of, and fixed return on the assets, the fair value of property, plant and equipment acquired is equal to its carrying value.

c) Long-term assets consist primarily of overfunded pension plan assets of $395 million and $1.2 billion of regulatory assets expected to be recovered from customers in future periods through rates.

Pension plan assets attributable to the workforce acquired from EOG were transferred in cash to an Enbridge-sponsored pension plan based on their fair value as at December 31, 2023, subject to closing adjustments. The fair value of plan assets was determined using unadjusted quoted market prices for identical investments.

d) The fair value of long-term debt was determined based on the current underlying US Treasury interest rates on instruments of similar yield, credit risk and tenor, as well as an implied credit spread based on current market conditions. We recorded a fair value adjustment to reduce long-term debt by $478 million with no corresponding regulatory offset.

e) Other long-term liabilities consist primarily of regulatory liabilities expected to be refunded to customers in future periods through rates.

f) Goodwill is primarily attributable to the existing assembled assets and workforce of EOG that cannot be duplicated at the same cost by a new entrant and the enhanced scale and geographic diversity of our regulated natural gas distribution business, which provides platforms for future growth and optimization with existing assets. The goodwill balance recognized has been assigned to our Gas Distribution and Storage segment and is not tax deductible.

Upon completion of the EOG Acquisition, we began consolidating EOG. For the period beginning March 6, 2024 through to March 31, 2024, EOG generated approximately $105 million of operating revenues and $25 million of earnings attributable to common shareholders.

Our supplemental pro forma consolidated financial information for the three months ended March 31, 2024 and 2023, including the results of operations for EOG as if the EOG Acquisition had been completed on January 1, 2023, are as follows:


	Three months ended March 31,
		2024	2023
(unaudited; millions of Canadian dollars)
Operating revenues		11,346	12,496
Earnings attributable to common shareholders1		1,476	1,770

1 Includes adjustment for pro forma interest expense on debt financing for the EOG Acquisition of $41 million (after-tax of $33 million) for the three months ended March 31, 2023.

ACQUISITION OF RNG FACILITIES

On January 2, 2024, through a wholly-owned US subsidiary, we acquired six Morrow Renewables operating landfill gas-to-renewable natural gas (RNG) production facilities (Tomorrow RNG) located in Texas and Arkansas for total consideration of $1.3 billion (US$1.0 billion), of which $584 million (US$439 million) was paid at close and an additional deferred consideration is payable within two years with a fair value of $757 million (US$568 million) (the RNG Facilities Acquisition). The acquired assets align with and advance our low-carbon strategy.

We accounted for the RNG Facilities Acquisition using the acquisition method as prescribed by ASC 805 Business Combinations. In accordance with valuation methodologies described in ASC 820 Fair Value Measurement, the acquired assets and assumed liabilities are recorded at their estimated fair values as at the date of acquisition.

The following table summarizes the estimated preliminary fair values that were assigned to the net assets of Tomorrow RNG:


			January 2, 2024
(millions of Canadian dollars)
Fair value of net assets acquired:
Current assets			31
Intangible assets (a)			925
Property, plant and equipment (b)			174
Current liabilities			5
Goodwill (c)			223
Purchase price:
Cash			584
Deferred consideration (d):
Current portion of long-term debt			550
Long-term debt			207
Other adjustments			7
			1,348

a) Intangible assets consist of long-term gas supply agreements with the respective facility's landfill owner. Fair value was determined using an income-based approach, specifically the multi-period excess earnings method, by estimating the present value of the after-tax cash flows attributable to the gas rights. The intangible assets will be amortized on a straight-line basis over the term of the respective agreement, inclusive of extension options, which range from 13 to 42 years.

b) Tomorrow RNG's property, plant and equipment constitutes specialized landfill gas plant and equipment which collects gas produced by waste decomposition, treats and compresses the gas to pipeline specifications. The direct method of replacement cost was used to determine the majority of the fair value of property, plant and equipment. Adjustments were then applied for estimated physical deterioration.

c) Goodwill is primarily attributable to expected future returns from a portfolio of both operating and scalable RNG assets, furthering the diversity of our renewable projects portfolio and accelerating progress toward our energy transition goals. The goodwill balance recognized has been assigned to our Gas Transmission segment and is tax deductible over 15 years.

d) We entered into six non-interest bearing promissory notes due to Morrow Renewables, the total value of which represents deferred payments of $808 million (US$606 million) due within two years. The first and second payments are due on January 2, 2025 and December 31, 2025, respectively. The $757 million (US$568 million) recognized in the purchase price represents the fair value of deferred consideration at the date of acquisition using the imputed interest rate method over the terms of the notes.

Upon completion of the RNG Facilities Acquisition, we began consolidating Tomorrow RNG. For the period beginning January 2, 2024 through to March 31, 2024, operating revenues and earnings attributable to common shareholders generated by Tomorrow RNG were immaterial. The impact to our supplemental pro forma consolidated operating revenues and earnings attributable to common shareholders for the three months ended March 31, 2024 and 2023, as if the RNG Facilities Acquisition had been completed on January 1, 2023, was also immaterial.

7. DEBT

CREDIT FACILITIES

The following table provides details of our committed credit facilities as at March 31, 2024:


	Maturity1	Total Facilities	Draws2	Available
(millions of Canadian dollars)
Enbridge Inc.	2024-2049	9,036	5,690	3,346
Enbridge (U.S.) Inc.	2025-2028	8,594	3,681	4,913
Enbridge Pipelines Inc.	2025	2,000	728	1,272
Enbridge Gas Inc.	2025	2,500	335	2,165
Total committed credit facilities		22,130	10,434	11,696

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 2024, we entered into a delayed-draw term loan facility of $200 million which matures in March 2049.

In addition to the committed credit facilities noted above, we maintain $1.2 billion of uncommitted demand letter of credit facilities, of which $766 million was unutilized as at March 31, 2024. As at December 31, 2023, we had $1.1 billion of uncommitted demand letter of credit facilities, of which $572 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 2049.

As at March 31, 2024 and December 31, 2023, commercial paper and credit facility draws, net of short-term borrowings and non-revolving credit facilities that mature within one year, of $9.6 billion and $3.8 billion, respectively, were supported by the availability of long-term committed credit facilities and, therefore, have been classified as long-term debt.

As a result of the EOG Acquisition and RNG Facilities Acquisition, our debt increased by US$1.9 billion and US$568 million, respectively, on each acquisition date. Accordingly, annual debt maturities have also increased. Long-term debt maturing during the year ending December 31, 2025, has increased by US$500 million and US$606 million, from the EOG Acquisition and RNG Facilities Acquisition, respectively. From the EOG Acquisition, the remaining US$1.8 billion debt is due after December 31, 2029. Refer to Note 6 - Acquisitions for further details.

LONG-TERM DEBT ISSUANCE

In April 2024, we closed a four-tranche offering consisting of three-year senior notes, five-year senior notes, 10-year senior notes, and 30-year senior notes for an aggregate principal amount of US$3.5 billion, which mature in April 2027, April 2029, April 2034 and April 2054, respectively.

LONG-TERM DEBT REPAYMENTS

During the three months ended March 31, 2024, we completed the following long-term debt repayments totaling US$2.7 billion and $0.2 billion:

Company

Repayment Date

Principal Amount

(millions of Canadian dollars, unless otherwise stated)

Enbridge Inc.

February 2024

Floating rate notes1

US$600

February 2024

2.15%

senior notes

US$400

March 2024

5.97%

senior notes2

US$700

Enbridge Pipelines Inc.

February 2024

8.20%

debentures

$200

Enbridge Southern Lights LP

January 2024

4.01%

senior notes

$10

Spectra Energy Partners, LP

March 2024

4.75%

senior notes

US$1,000

1The notes carried an interest rate set to equal the Secured Overnight Financing Rate plus a margin of 63 basis points.

2The notes carried an original maturity date in March 2026, and were callable one year after their issuance, in March 2024.

SUBORDINATED TERM NOTES

As at March 31, 2024 and December 31, 2023, our fixed-to-floating rate and fixed-to-fixed rate subordinated term notes had a principal value of $13.2 billion and $13.0 billion, respectively.

FAIR VALUE ADJUSTMENT

As at March 31, 2024 and December 31, 2023, the net fair value adjustments to total debt assumed in a historical acquisition were $501 million and $514 million, respectively. As a result of the EOG Acquisition, there were additional fair value adjustments of $478 million to decrease total debt as at March 31, 2024. Amortization of the fair value adjustment is recorded as an increase to Interest expense in the Consolidated Statements of Earnings:


	Three months ended March 31,
	2024	2023
(millions of Canadian dollars)


Amortization of fair value adjustment	12	11

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 March 31, 2024, we were in compliance with all such debt covenant provisions.

8. COMPONENTS OF ACCUMULATED OTHER COMPREHENSIVE INCOME

Changes in Accumulated other comprehensive income (AOCI) attributable to our common shareholders for the three months ended March 31, 2024 and 2023 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, 2024	320	(23)	(728)	2,653	11	70	2,303
Other comprehensive income/(loss) retained in AOCI	144	(15)	(377)	1,629	(1)	—	1,380
Other comprehensive (income)/loss reclassified to earnings


Foreign exchange contracts1	—	19	—	—	—	—	19

Amortization of pension and OPEB actuarial gain2	—	—	—	—	—	(5)	(5)

	144	4	(377)	1,629	(1)	(5)	1,394
Tax impact
Income tax on amounts retained in AOCI	(34)	4	—	—	—	—	(30)
Income tax on amounts reclassified to earnings	—	(4)	—	—	—	1	(3)
	(34)	—	—	—	—	1	(33)

Balance as at March 31, 2024	430	(19)	(1,105)	4,282	10	66	3,664


	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	(90)	7	15	(57)	—	—	(125)
Other comprehensive (income)/loss reclassified to earnings
Interest rate contracts3	8	—	—	—	—	—	8


Other contracts4	1	—	—	—	—	—	1
Amortization of pension and OPEB actuarial gain2	—	—	—	—	—	(5)	(5)

	(81)	7	15	(57)	—	(5)	(121)
Tax impact
Income tax on amounts retained in AOCI	28	—	—	—	—	—	28
Income tax on amounts reclassified to earnings	(2)	—	—	—	—	1	(1)
	26	—	—	—	—	1	27

Balance as at March 31, 2023	66	(28)	(1,122)	4,291	5	214	3,426

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

2These components are included in the computation of net periodic benefit credit and are reported within Other income/(expense) in the Consolidated Statements of Earnings.

3Reported within Interest expense in the Consolidated Statements of Earnings.

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

9. 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 US dollar-denominated investments and subsidiaries using foreign currency US dollar-denominated debt.

Interest Rate Risk

Our earnings, cash flows and OCI are exposed to short-term interest rate variability due to the regular repricing of our variable rate debt, primarily commercial paper. We have a policy of limiting the maximum floating rate debt to 30% of total debt outstanding. To ensure compliance with our policy, we monitor and adjust our debt portfolio mix of fixed and variable rate debt instruments in conjunction with the use of hedging instruments. 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 and costless collars. These swaps have an average fixed rate of 4.1%.

Our earnings and cash flows are also exposed to variability in longer term interest rates ahead of anticipated fixed rate term debt issuances. A combination of qualifying and non-qualifying 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 execution of floating-to-fixed interest rate swaps with an average swap rate of 3.5%.

Commodity Price Risk

Our earnings, cash flows and OCI 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 marketing 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.

TOTAL DERIVATIVE INSTRUMENTS

We 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 tables summarize 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.


March 31, 2024	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	—	32	92	124	(26)	98
Interest rate contracts	51	—	51	102	(50)	52
Commodity contracts	—	—	241	241	(157)	84

	51	32	384	467	(233)	234
Deferred amounts and other assets
Foreign exchange contracts	—	—	124	124	(98)	26
Interest rate contracts	67	—	26	93	(7)	86
Commodity contracts	—	—	87	87	(40)	47

	67	—	237	304	(145)	159
Other current liabilities
Foreign exchange contracts	—	(43)	(195)	(238)	26	(212)
Interest rate contracts	(97)	—	(2)	(99)	50	(49)
Commodity contracts	(4)	—	(311)	(315)	157	(158)
Other contracts	—	—	(1)	(1)	—	(1)
	(101)	(43)	(509)	(653)	233	(420)
Other long-term liabilities
Foreign exchange contracts	—	(51)	(899)	(950)	98	(852)
Interest rate contracts	—	—	(22)	(22)	7	(15)
Commodity contracts	(2)	—	(164)	(166)	40	(126)

	(2)	(51)	(1,085)	(1,138)	145	(993)
Total net derivative asset/(liability)
Foreign exchange contracts	—	(62)	(878)	(940)	—	(940)
Interest rate contracts	21	—	53	74	—	74
Commodity contracts	(6)	—	(147)	(153)	—	(153)
Other contracts	—	—	(1)	(1)	—	(1)
	15	(62)	(973)	(1,020)	—	(1,020)


December 31, 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	—	41	98	139	(32)	107
Interest rate contracts	31	—	34	65	(32)	33
Commodity contracts	—	—	418	418	(270)	148
Other contracts	—	—	1	1	(1)	—
	31	41	551	623	(335)	288
Deferred amounts and other assets
Foreign exchange contracts	—	16	319	335	(122)	213
Interest rate contracts	51	—	2	53	(21)	32
Commodity contracts	—	—	75	75	(41)	34

	51	16	396	463	(184)	279
Other current liabilities
Foreign exchange contracts	—	(44)	(84)	(128)	32	(96)
Interest rate contracts	(183)	—	(3)	(186)	32	(154)
Commodity contracts	(11)	—	(412)	(423)	270	(153)
Other contracts	—	—	(1)	(1)	1	—
	(194)	(44)	(500)	(738)	335	(403)
Other long-term liabilities
Foreign exchange contracts	—	(17)	(481)	(498)	122	(376)
Interest rate contracts	(3)	—	(85)	(88)	21	(67)
Commodity contracts	(7)	—	(159)	(166)	41	(125)

	(10)	(17)	(725)	(752)	184	(568)
Total net derivative liability
Foreign exchange contracts	—	(4)	(148)	(152)	—	(152)
Interest rate contracts	(104)	—	(52)	(156)	—	(156)
Commodity contracts	(18)	—	(78)	(96)	—	(96)
Other contracts	—	—	—	—	—	—
	(122)	(4)	(278)	(404)	—	(404)

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


March 31, 2024	2024	2025	2026	2027	2028	Thereafter	Total
Foreign exchange contracts - US dollar forwards - purchase (millions of US dollars)	715	500	—	—	—	—	1,215
Foreign exchange contracts - US dollar forwards - sell (millions of US dollars)	5,368	5,327	4,697	4,091	3,162	888	23,533
Foreign exchange contracts - British pound (GBP) forwards - sell (millions of GBP)	25	30	28	32	—	—	115

Foreign exchange contracts - Euro forwards - sell (millions of Euro)	106	126	121	81	67	195	696
Foreign exchange contracts - Japanese yen forwards - purchase (millions of yen)	—	84,800	—	—	—	—	84,800
Interest rate contracts - short-term pay fixed rate (millions of Canadian dollars)	4,726	1,904	1,130	75	25	13	7,873
Interest rate contracts - short-term receive fixed rate (millions of Canadian dollars)	708	947	179	—	—	—	1,834
Interest rate contracts - long-term pay fixed rate (millions of Canadian dollars)1	5,436	588	—	—	—	—	6,024
Interest rate contracts - costless collar (millions of Canadian dollars)	—	1,382	53	—	—	—	1,435

Commodity contracts - natural gas (billions of cubic feet)	50	28	18	12	—	—	108
Commodity contracts - crude oil (millions of barrels)	13	—	—	—	—	—	13

Commodity contracts - power (megawatt per hour (MW/H))	51	(18)	(35)	(51)	(49)	(30)	(25)	2

1Represents the notional amount of long-term debt issuances hedged.

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

Derivatives Designated as Fair Value Hedges

The following table presents foreign exchange derivative instruments that are designated and qualify as fair value hedges. The realized and unrealized 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 March 31,
		2024	2023
(millions of Canadian dollars)
Unrealized loss on derivative		(63)	(11)
Unrealized gain on hedged item		74	11
Realized gain/(loss) on derivative		59	(11)
Realized loss on hedged item		(79)	—

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 comprehensive income, before the effect of income taxes:


	Three months ended March 31,
		2024	2023
(millions of Canadian dollars)
Amount of unrealized gain/(loss) recognized in OCI
Cash flow hedges

Interest rate contracts		138	(105)
Commodity contracts		12	34
Other contracts		1	(2)
Fair value hedges
Foreign exchange contracts		(15)	7


		136	(66)
Amount of loss reclassified from AOCI to earnings
Foreign exchange contracts1		19	—
Interest rate contracts2		—	8

Other contracts3		—	1
		19	9

1Reported within Other income/(expense) in the Consolidated Statements of Earnings.

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

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

We estimate that a loss of $8 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 two years as at March 31, 2024.

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 March 31,
		2024	2023
(millions of Canadian dollars)
Foreign exchange contracts1		(730)	556
Interest rate contracts2		105	10
Commodity contracts3		(67)	(39)
Other contracts4		(1)	(7)
Total unrealized derivative fair value gain/(loss), net		(693)	520

1For the respective three months ended periods, reported within Transportation and other services revenues (2024 - nil; 2023 - $645 million gain) and Other income/(expense) (2024 - $730 million loss; 2023 - $89 million loss) in the Consolidated Statements of Earnings.

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

3For the respective three months ended periods, reported within Transportation and other services revenues (2024 - $35 million loss; 2023 - $6 million gain), Commodity sales (2024 - $37 million loss; 2023 - $69 million gain), Commodity costs (2024 - $23 million gain; 2023 - $75 million loss) and Operating and administrative expense (2024 - $18 million loss; 2023 - $39 million loss) 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 March 31, 2024. As a result, all credit facilities are available to us and the banks are obligated to fund us under the terms of the facilities. We also identify a variety of other potential sources of debt and equity funding alternatives, including reinstatement of our dividend reinvestment and share purchase plan or at-the-market equity issuances.

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 review 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:


	March 31, 2024	December 31, 2023
(millions of Canadian dollars)
Canadian financial institutions	353	457
US financial institutions	91	252
European financial institutions	69	107
Asian financial institutions	85	121
Other1	119	125
	717	1,062

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

As at March 31, 2024, 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 March 31, 2024 and December 31, 2023.

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 funds held by our captive insurance subsidiaries, as well as restricted long-term investments in exchange-traded funds 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 trust 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 derivative's 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.

Fair Value of Derivatives

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


March 31, 2024	Level 1	Level 2	Level 3	Total Gross Derivative Instruments
(millions of Canadian dollars)
Financial assets
Current derivative assets
Foreign exchange contracts	—	124	—	124
Interest rate contracts	—	102	—	102
Commodity contracts	35	82	124	241

	35	308	124	467
Long-term derivative assets
Foreign exchange contracts	—	124	—	124
Interest rate contracts	—	93	—	93
Commodity contracts	—	14	73	87

	—	231	73	304
Financial liabilities
Current derivative liabilities
Foreign exchange contracts	—	(238)	—	(238)
Interest rate contracts	—	(99)	—	(99)
Commodity contracts	(63)	(78)	(174)	(315)
Other contracts	—	(1)	—	(1)
	(63)	(416)	(174)	(653)
Long-term derivative liabilities
Foreign exchange contracts	—	(950)	—	(950)
Interest rate contracts	—	(22)	—	(22)
Commodity contracts	—	(16)	(150)	(166)

	—	(988)	(150)	(1,138)
Total net financial asset/(liability)
Foreign exchange contracts	—	(940)	—	(940)
Interest rate contracts	—	74	—	74
Commodity contracts	(28)	2	(127)	(153)
Other contracts	—	(1)	—	(1)
	(28)	(865)	(127)	(1,020)


December 31, 2023	Level 1	Level 2	Level 3	Total Gross Derivative Instruments
(millions of Canadian dollars)
Financial assets
Current derivative assets
Foreign exchange contracts	—	139	—	139
Interest rate contracts	—	65	—	65
Commodity contracts	142	103	173	418
Other contracts	—	1	—	1
	142	308	173	623
Long-term derivative assets
Foreign exchange contracts	—	335	—	335
Interest rate contracts	—	53	—	53
Commodity contracts	—	24	51	75

	—	412	51	463
Financial liabilities
Current derivative liabilities
Foreign exchange contracts	—	(128)	—	(128)
Interest rate contracts	—	(186)	—	(186)
Commodity contracts	(136)	(76)	(211)	(423)
Other contracts	—	(1)	—	(1)
	(136)	(391)	(211)	(738)
Long-term derivative liabilities
Foreign exchange contracts	—	(498)	—	(498)
Interest rate contracts	—	(88)	—	(88)
Commodity contracts	—	(22)	(144)	(166)

	—	(608)	(144)	(752)
Total net financial asset/(liability)
Foreign exchange contracts	—	(152)	—	(152)
Interest rate contracts	—	(156)	—	(156)
Commodity contracts	6	29	(131)	(96)
Other contracts	—	—	—	—
	6	(279)	(131)	(404)

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


March 31, 2024	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	(8)	Forward gas price	1.73	8.97	3.72	$/mmbtu2
Crude	(7)	Forward crude price	84.20	105.12	100.91	$/barrel

Power	(72)	Forward power price	23.64	163.57	61.76	$/MW/H
Commodity contracts - physical1
Natural gas	18	Forward gas price	0.83	12.95	3.39	$/mmbtu2
Crude	12	Forward crude price	79.56	115.53	99.80	$/barrel

Power	(70)	Forward power price	19.59	184.82	63.68	$/MW/H
	(127)

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


	Three months ended March 31,
	2024	2023
(millions of Canadian dollars)
Level 3 net derivative liability at beginning of period	(131)	(136)
Total gain/(loss), unrealized
Included in earnings1	(17)	(44)
Included in OCI	12	33
Settlements	9	(1)
Level 3 net derivative liability at end of period	(127)	(148)

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 March 31, 2024 or December 31, 2023.

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 three months ended March 31, 2024 and 2023, we recognized unrealized foreign exchange losses of $377 million and gains of $59 million, respectively, on the translation of US dollar-denominated debt, in OCI. During the three months ended March 31, 2024 and 2023, we recognized nil and realized losses of $44 million, 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 $176 million and $173 million as at March 31, 2024 and December 31, 2023, respectively.

As at March 31, 2024, we had investments with a fair value of $743 million included in Restricted long-term investments in the Consolidated Statements of Financial Position (December 31, 2023 - $717 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 $293 million as at March 31, 2024 which are classified as Level 1 in the fair value hierarchy (December 31, 2023 - $263 million). We also had restricted long-term investments held in trust totaling $450 million (cost basis - $507 million) and $454 million (cost basis - $486 million) as at March 31, 2024 and December 31, 2023, respectively, which are classified as Level 2 in the fair value hierarchy. There were unrealized holding losses of $13 million on these investments for the three months ended March 31, 2024 (2023 - gains of $34 million).

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 March 31, 2024, the fair value of investments in equity funds and debt securities held by our captive insurance subsidiaries was $312 million and $251 million, respectively (December 31, 2023 - $287 million and $284 million, respectively). Our investments in debt securities had a cost basis of $247 million as at March 31, 2024 (December 31, 2023 - $279 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 $16 million for the three months ended March 31, 2024, (2023 - gains of $15 million).

As at March 31, 2024 and December 31, 2023, our long-term debt including finance lease liabilities had a carrying value of $87.6 billion and $81.2 billion, respectively, before debt issuance costs and a fair value of $84.6 billion and $78.1 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 March 31, 2024 and December 31, 2023, the non-current notes receivable had a carrying value of $53 million, respectively, which also approximates their fair value.

The fair value of financial assets and liabilities other than derivative instruments, certain long-term investments in other entities, restricted long-term investments, investments held by our captive insurance subsidiaries, long-term debt and non-current notes receivable described above approximate their carrying value due to the short period to maturity.

10. INCOME TAXES

The effective income tax rates for the three months ended March 31, 2024 and 2023 were 19.8% and 21.5%, respectively.

The period-over-period decrease in the effective income tax rate is due to a state apportionment income tax rate change due to the EOG Acquisition, and the effects of rate-regulated accounting for income taxes, relative to lower earnings.

11. OTHER INCOME/(EXPENSE)


	Three months ended March 31,
		2024	2023
(millions of Canadian dollars)

Realized foreign currency gain		122	145
Unrealized foreign currency loss		(858)	(188)
Net defined pension and OPEB credit		41	33
Other		144	112
		(551)	102

12. 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, which requires 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. Our insurance coverage is also 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.

13. SUBSEQUENT EVENT

DISPOSITION OF ALLIANCE PIPELINE AND AUX SABLE

On April 1, 2024, we closed the sale of our 50.0% interest in the Alliance Pipeline and our interest in Aux Sable (includes a 42.7% interest in Aux Sable Midstream LLC and Aux Sable Liquid Products L.P., and a 50% interest in Aux Sable Canada LP) to Pembina Pipeline Corporation for $3.1 billion, including approximately $327 million of non-recourse debt, subject to customary closing adjustments. As part of the net gain on sale of approximately $1.1 billion before tax, we will allocate approximately $1.0 billion of the goodwill in our Gas Transmission segment to the disposal group.

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, 2023.

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

We reached an agreement on a negotiated settlement with shippers for tolls on the Mainline System in May 2023 and filed an application with the Canada Energy Regulator (CER) for approval of the Mainline Tolling Settlement (MTS) on December 15, 2023, with unanimous support from its Representative Stakeholder Group. The CER issued an order on March 4, 2024 approving our application as filed.

The MTS covers both the Canadian and US portions of the Mainline and has the Mainline continue to operate as a common carrier system available to all shippers on a monthly nomination basis. The term of the MTS is seven and a half years through to the end of 2028.

The MTS 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 continue to be distance and commodity adjusted, and now 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 earns 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 flexes 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.

SOUTHERN LIGHTS FIXED TOLL CONTRACTS

During the fourth quarter of 2023, Southern Lights Pipeline (Southern Lights) successfully completed an open season that resulted in new transportation service agreements. These new five-year fixed toll contracts were executed in the first quarter of 2024, and have a commencement date of July 1, 2025. As at December 31, 2023, Southern Lights discontinued its rate-regulated accounting as the new agreements will not follow a cost of service toll methodology.

ACQUISITIONS

Joint Venture with WhiteWater/I Squared and MPLX

On March 26, 2024, we announced that Enbridge Inc. (Enbridge) entered into a definitive agreement with WhiteWater/I Squared Capital (WhiteWater/I Squared) and MPLX LP (MPLX) to form a joint venture (the Whistler Parent JV) that will develop, construct, own, and operate natural gas pipeline and storage assets connecting Permian Basin natural gas supply to growing liquefied natural gas (LNG) and other US Gulf Coast demand.

The Whistler Parent JV will be owned by WhiteWater/I Squared (50.6%), MPLX (30.4%), and Enbridge (19.0%) and will include the following assets:

•100% interest in the Whistler pipeline, a 450-mile intrastate pipeline transporting natural gas from the Waha Header in the Permian Basin to Agua Dulce, Texas;

•100% interest in the Rio Bravo pipeline project, two new parallel 137-mile pipelines transporting natural gas from the Agua Dulce supply area to NextDecade's Rio Grande LNG project in Brownsville, Texas;

•70% interest in the ADCC pipeline, a new 40-mile pipeline designed to transport 1.7 billion cubic feet per day (bcf/d) of natural gas from the terminus of the Whistler pipeline in Agua Dulce, Texas to Cheniere's Corpus Christi LNG export facility; and

•50% interest in Waha Gas Storage, a 2.0 bcf gas storage cavern facility connecting to key Permian egress pipelines including the Whistler pipeline.

Upon closing of the transaction, Enbridge will contribute its wholly-owned Rio Bravo pipeline project and approximately US$350 million in cash to the Whistler Parent JV. In addition to the 19% equity interest in the Whistler Parent JV, Enbridge will receive a special equity interest in the Whistler Parent JV providing for a 25% economic interest in the Rio Bravo pipeline project (which interest is subject to certain redemption rights held by Whitewater/I Squared and MPLX). After the closing, Enbridge’s share of the post-closing capital expenditures to complete the Rio Bravo pipeline project will be 100% for the first approximate US$150 million and, thereafter, proportionate to its aggregate economic interest in the project. Closing is expected in the second quarter of 2024, subject to receipt of required regulatory approvals and satisfaction of other customary closing conditions.

The East Ohio Gas Company

On September 5, 2023, Enbridge entered into three separate definitive agreements with Dominion Energy, Inc. to acquire EOG, Questar Gas Company and its related Wexpro companies, and Public Service Company of North Carolina for an aggregate purchase price of $19.1 billion (US$14.0 billion), comprised of $12.8 billion (US$9.4 billion) of cash consideration and $6.3 billion (US$4.6 billion) of assumed debt, subject to customary closing adjustments (the Acquisitions). We continue to expect the remaining Acquisitions to close in 2024, subject to the satisfaction of customary closing conditions, including the receipt of required US federal and state regulatory approvals.

Acquisition of RNG Facilities

On January 2, 2024, through a wholly-owned US subsidiary, we acquired six Morrow Renewables operating landfill gas-to-renewable natural gas (RNG) production facilities (Tomorrow RNG) located in Texas and Arkansas for total consideration of $1.3 billion (US$1.0 billion), of which $584 million (US$439 million) was paid at close and an additional deferred consideration is payable within two years with a fair value of $757 million (US$568 million) . The acquired assets align with and advance our low-carbon strategy.

ASSET MONETIZATION

Disposition of Alliance Pipeline and Aux Sable

GAS TRANSMISSION RATE PROCEEDINGS

Maritimes & Northeast Pipeline

The toll settlement agreement for the Canadian portion of Maritimes & Northeast (M&N) Pipeline system expired in December 2023. M&N Pipeline reached a toll settlement with shippers for the effective period from January 1, 2024 to December 31, 2025. On November 28, 2023 M&N Canada filed the 2024-2025 toll settlement agreement with the CER, which was approved on February 14, 2024, as filed.

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 initially sought 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). A third phase (Phase 3) has been established with the OEB as part of the Phase 1 Partial Settlement Proposal.

On December 21, 2023, the OEB issued its Decision and Order on Phase 1 (Phase 1 Decision). Enbridge Gas filed a Notice of Appeal with the Ontario Divisional Court on January 22, 2024 regarding four aspects of the Phase 1 Decision: small volume customer revenue horizon, the 2024 capital plan reduction, the extension of service life for certain asset classes and equity thickness. On January 29, 2024 Enbridge Gas also filed a Notice of Motion with the OEB requesting the OEB to review and vary five aspects of the Phase 1 Decision: small volume customer revenue horizon, the 2024 capital plan reduction, integration capital, depreciation and equity thickness. The outcome of these proceedings is uncertain.

On February 24, 2024 the Government of Ontario introduced Bill 165, the Keeping Energy Costs Down Act (the Act), in response to the Phase 1 Decision. If passed, the Act would give the Government of Ontario time-limited authority to set the revenue horizon for small volume customers, effectively reversing that aspect of the OEB's Phase 1 Decision. The Act is currently proceeding to a third reading and final vote in the provincial legislature.

The Phase 1 Decision resulted in interim 2024 rates, pending Phase 2 of the proceeding and resolution of the Notice of Motion. An updated Draft Interim Rate Order reflecting the Phase 1 Decision was filed March 15, 2024 and subsequently approved by the OEB on April 11, 2024. The Interim Rate Order implemented 2024 rates on May 1, 2024, along with retroactive treatment to January 1, 2024.

Enbridge Gas filed its Phase 2 evidence on April 26, 2024. Phase 2 will establish the incentive rate mechanism for 2025-2028, and will also address unregulated storage cost allocation and new energy transition proposals. Phase 3 will address cost allocation and the harmonization of rates and rate classes between legacy rate zones.

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 2024, the April 1, 2024 QRAM application was filed and approved by the OEB. The application included no rate mitigation measures, as the mitigation plans from the April and July 2022 QRAM applications concluded at the end of March 2024..

As at March 31, 2024, Enbridge Gas' PGVA payable balance was $226 million.

FINANCING UPDATE

On March 8, 2024 call date, we redeemed at par all of the outstanding US$700 million three-year callable, 5.97% senior notes that carried an original maturity date in March 2026.

In March 2024, we entered into a delayed-draw term loan facility of $200 million which matures in March 2049.

These financing activities, in combination with the financing activities executed in 2023, provide significant liquidity that we expect will enable us to fund our current portfolio of capital projects and acquisitions 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 March 31, 2024, after adjusting for the impact of floating-to-fixed interest rate swap hedges, 6% of our total debt is exposed to floating rates. Refer to Part I. Item 1. Financial Statements - Note 9 - Risk Management and Financial Instruments for more information on our interest rate hedging program.

Credit Rating Action

On March 29, 2024 Moody's Investor Service (Moody's) downgraded Enbridge's credit ratings for our senior unsecured debt ratings to Baa2 from Baa1. Moody's also downgraded the credit ratings of our subsidiaries: Enbridge Energy Partners, L.P. (EEP), Enbridge Energy Limited Partnership, Spectra Energy Partners, LP (SEP) and Texas Eastern Transmission L.P. (Texas Eastern). The outlooks of all five entities were changed to stable from negative. The credit ratings from DBRS, Fitch and Standard & Poor's remained unchanged at BBB (high), BBB+ and BBB+, respectively.

RESULTS OF OPERATIONS


	Three months ended March 31,
	2024	2023
(millions of Canadian dollars, except per share amounts)
Segment earnings/(loss) before interest, income taxes and depreciation and amortization1
Liquids Pipelines	2,404	2,353
Gas Transmission	1,265	1,205
Gas Distribution and Storage	765	716
Renewable Power Generation	257	136
Eliminations and Other	(642)	17
Earnings before interest, income taxes and depreciation and amortization1	4,049	4,427
Depreciation and amortization	(1,193)	(1,146)
Interest expense	(905)	(905)
Income tax expense	(386)	(510)
Earnings attributable to noncontrolling interests	(53)	(49)
Preference share dividends	(93)	(84)
Earnings attributable to common shareholders	1,419	1,733
Earnings per common share attributable to common shareholders	0.67	0.86
Diluted earnings per common share attributable to common shareholders	0.67	0.85

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

Change in Reportable Segments

Effective January 1, 2024, to better align how the chief operating decision-maker reviews operating performance and resource allocation across operating segments, we transferred our Canadian and United States (US) crude oil marketing businesses from the Energy Services segment to the Liquids Pipelines segment. As a result, the Energy Services segment ceased to exist and the remainder of the business, comprising natural gas and power marketing, are now reported in the Eliminations and Other segment. Beginning in the first quarter of 2024, prior period comparable results for segmented information have been recast to reflect the change in reportable segments. This segment reporting change does not have an impact on our consolidated results.

EARNINGS ATTRIBUTABLE TO COMMON SHAREHOLDERS

Three months ended March 31, 2024, compared with the three months ended March 31, 2023

Earnings attributable to common shareholders were negatively impacted by $543 million due to certain infrequent or other non-operating factors, primarily explained by the following:

•a non-cash, net unrealized derivative fair value loss of $677 million ($518 million after-tax) in 2024, compared with a net unrealized gain of $542 million ($406 million after-tax) in 2023, reflecting changes in the mark-to-market value of derivative financial instruments used to manage foreign exchange, interest rate and commodity price risks;

•severance costs of $105 million ($79 million after-tax) as a result of workforce reduction in February 2024; and

•the absence in 2024 of the receipt of a litigation claim settlement of $68 million ($52 million after-tax); partially offset by

•the absence in 2024 of a realized loss of $638 million ($479 million after-tax) due to termination of foreign exchange hedges, as foreign exchange risks inherent within the Competitive Toll Settlement (CTS) are not present in the MTS.

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, interest rate 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 $229 million increase in earnings attributable to common shareholders is primarily explained by:

•higher contributions from our Liquids Pipelines segment due to higher volumes on the Flanagan South Pipeline and from the Enbridge Ingleside Energy Center (EIEC), greater long-haul deliveries from the Express-Platte System, and discontinuation of rate-regulated accounting of Southern Lights Pipeline in 2023;

•higher contributions from our Gas Transmission segment primarily due to favorable contracting in our Gas Transmission and Storage assets and acquisitions completed after the first quarter of 2023;

•contributions from the EOG Acquisition in the first quarter of 2024 and higher distribution charges at our Gas Distribution and Storage segment resulting from increases in rates and customer base;

•higher investment income primarily due to pre-funding of the Acquisitions and lower operating and administrative costs in our Eliminations and Other segment; and

•higher contributions from our Renewable Power Generation segment mainly due to contributions from our investment in Fox Squirrel Solar LLC (Fox Squirrel), an additional 24.45% interest acquired in the Hohe See and Albatros Offshore Wind Facilities in November 2023, and stronger wind resources at European wind facilities in 2024.

The factors above were partially offset by:

•higher interest expense due to higher long-term debt principal and interest rates;

•higher income tax expense driven by higher earnings;

•realized foreign exchange loss on hedge settlements in our Eliminations and Other segment in 2024, compared to a gain in 2023;

•warmer weather in 2024 negatively impacting earnings in our Gas Distribution and Storage segment; and

•the absence in 2024 of the recognition of revenues attributable to the Texas Eastern rate case settlement in our Gas Transmission segment.

BUSINESS SEGMENTS

LIQUIDS PIPELINES


	Three months ended March 31,
	2024	2023
(millions of Canadian dollars)
Earnings before interest, income taxes and depreciation and amortization	2,404	2,353

Three months ended March 31, 2024, compared with the three months ended March 31, 2023

EBITDA was negatively impacted by $67 million due to certain infrequent or other non-operating factors, primarily explained by:

•a non-cash, net unrealized loss of $35 million in 2024, compared with a net unrealized gain of $615 million in 2023, reflecting changes in the mark-to-market value of derivative financial instruments used to manage foreign exchange and commodity price risks; and

•the absence in 2024 of the receipt of a litigation claim settlement of $68 million; partially offset by

•the absence in 2024 of a realized loss of $638 million due to termination of foreign exchange hedges, as foreign exchange risks inherent within the CTS are not present in the MTS.

After taking into consideration the factors above, the remaining $118 million increase is primarily explained by the following significant business factors:

•higher contributions from the Gulf Coast and Mid-Continent System due to higher volumes on the Flanagan South Pipeline and from the EIEC;

•higher contributions from the Express-Platte System due primarily to greater long-haul deliveries; and

•higher contributions from Southern Lights Pipeline due primarily to the discontinuation of rate-regulated accounting in the fourth quarter of 2023.

GAS TRANSMISSION


	Three months ended March 31,
	2024	2023
(millions of Canadian dollars)
Earnings before interest, income taxes and depreciation and amortization	1,265	1,205

Three months ended March 31, 2024, compared with the three months ended March 31, 2023

EBITDA was negatively impacted by $25 million due to certain infrequent or other non-operating factors, primarily explained by:

•a non-cash, net unrealized loss of $17 million in 2024 reflecting changes in the mark-to-market value of derivative financial instruments used to manage commodity price risks; and

•the absence in 2024 of a non-cash, net positive equity earnings adjustment of $8 million relating to our share of changes in the mark-to-market value of derivative financial instruments of our equity method investee, DCP Midstream, LP.

The remaining $85 million increase is primarily explained by the following significant business factors:

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

•contributions from the acquisition of Tres Palacios in the second quarter of 2023, Aitken Creek in the fourth quarter of 2023, and Tomorrow RNG in the first quarter of 2024; and

•higher earnings at Aux Sable joint venture due to favorable contracting; partially offset by

•the absence in 2024 of recognition of revenues attributable to the Texas Eastern rate case settlement in 2023.

GAS DISTRIBUTION AND STORAGE


	Three months ended March 31,
	2024	2023
(millions of Canadian dollars)
Earnings before interest, income taxes and depreciation and amortization	765	716

Three months ended March 31, 2024, compared with the three months ended March 31, 2023

EBITDA was positively impacted by $49 million primarily due to the following significant business factors:

•contributions from the EOG Acquisition in the first quarter of 2024; and

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

•when compared with the normal weather forecast embedded in rates, warmer than normal weather in 2024 negatively impacted 2024 EBITDA by approximately $42 million period over period.

RENEWABLE POWER GENERATION


	Three months ended March 31,
	2024	2023
(millions of Canadian dollars)
Earnings before interest, income taxes and depreciation and amortization	257	136

Three months ended March 31, 2024, compared with the three months ended March 31, 2023

EBITDA was negatively impacted by $19 million due to certain infrequent or other non-operating factors, primarily explained by a non-cash, net unrealized loss of $11 million in 2024, compared with a net unrealized gain of $2 million in 2023, reflecting changes in the mark-to-market value of derivative financial instruments used to manage foreign exchange and commodity price risks.

The remaining $140 million increase is primarily due to the following significant business factors:

•contributions from our investment in Fox Squirrel as a result of the generation of investment tax credits;

•higher contributions from the Hohe See and Albatros Offshore Wind Facilities as a result of the November 2023 acquisition of an additional 24.45% interest in these facilities; and

•stronger wind resources at European wind facilities.

ELIMINATIONS AND OTHER


	Three months ended March 31,
	2024	2023
(millions of Canadian dollars)
Earnings/(loss) before interest, income taxes and depreciation and amortization	(642)	17

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, corporate investments, and natural gas and power marketing and logistical services to North American refiners, producers, and other customers.

Three months ended March 31, 2024, compared with the three months ended March 31, 2023

EBITDA was negatively impacted by $753 million due to certain infrequent or non-operating factors, primarily explained by:

•a non-cash, net unrealized loss of $722 million in 2024, compared with a net loss of $77 million in 2023, reflecting changes in the mark-to-market value of derivative financial instruments used to manage foreign exchange and commodity price risk; and

•severance costs of $105 million as a result of workforce reduction in February 2024.

After taking into consideration the non-operating factors above, the remaining $94 million increase is primarily explained by:

•higher investment income primarily from the pre-funding of the Acquisitions; and

•lower operating and administrative costs; partially offset by

•realized foreign exchange loss on hedge settlements in 2024, compared to a gain 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
1.	Texas Eastern Venice Extension3	100	%	US$477 million	US$251 million	Under construction	2024
2.	Texas Eastern Modernization	100	%	US$394 million	US$48 million	Pre-construction	2025 - 2026
3.	T-North Expansion (Aspen Point)	100	%	$1.2 billion	$107 million	Pre-construction	2026
4.	Rio Bravo Pipeline4	100	%	US$1.2 billion	US$82 million	Pre-construction	2026
5.	Tennessee Ridgeline Expansion	100	%	US$1.1 billion	US$94 million	Pre-construction	2026
6.	Woodfibre LNG5	30	%	US$1.5 billion	US$358 million	Under construction	2027
7.	T-South Expansion (Sunrise Expansion)	100	%	$4.0 billion	$93 million	Pre-construction	2028


RENEWABLE POWER GENERATION
8.	Fécamp Offshore Wind6	17.9	%	$692 million	$565 million	Under construction	2Q - 2024
				(€471 million)	(€387 million)
9.	Calvados Offshore Wind7	21.7	%	$954 million	$367 million	Under construction	2025
				(€645 million)	(€255 million)
10.	Fox Squirrel Solar8	50	%	US$406 million	US$152 million	Under construction	2024

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 March 31, 2024.

3Includes the US$37 million Gator Express Project placed into service in August 2023. Total estimated capital cost consists of the reversal and expansion of Texas Eastern's Line 40 expected to be completed in 2024.

4Current estimated capital cost is based on two liquefaction trains and an update to the estimated capital cost is expected to be provided in 2024. Our ownership interest and our share of project capital will be reduced once the transaction with WhiteWater/I Squared and MPLX is closed. See Recent Developments - Acquisitions for further discussion.

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

6Our equity contribution is reduced to nil after project refinancing was approved in the first quarter of 2024. The project is fully financed through non-recourse project level debt.

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

8Includes the initial phase of the project which commenced operations in December 2023.

A full description of each of our projects is provided in our annual report on Form 10-K for the year ended December 31, 2023. Significant updates that have occurred since the date of filing of our Form 10-K are discussed below.

GAS TRANSMISSION

Tennessee Ridgeline Expansion

The Tennessee Ridgeline Expansion project is an expansion of the East Tennessee Natural Gas (ETNG) system which would provide additional natural gas for the Tennessee Valley Authority (TVA) to support the replacement of an existing coal-fired power plant as it continues to transition its generation mix towards lower-carbon fuels. The proposed scope includes the installation of approximately 125 miles of 30-inch pipeline looping, one electric-powered compressor station, and an 8-megawatt behind-the-meter solar array.

TVA published a Notice of Intent in the Federal Register on June 15, 2021, to initiate the environmental review process for its proposed action to retire the Kingston Coal-Fired Plant and to replace it with a natural gas plant. On April 2, 2024, TVA issued a Record of Decision (ROD) documenting its decision to adopt TVA's Preferred Alternative to replace the retiring coal generating units at the Kingston Coal-Fired Plant with a natural gas plant. The issuance of the ROD adopting its Preferred Alternative satisfied a key condition of TVA's Precedent Agreement with ETNG related to the ETNG Ridgeline Expansion project.

All necessary regulatory authorizations from the Federal Energy Regulatory Commission and other federal and state agencies will be obtained before construction of the project commences. Pending the approval and receipt of all necessary permits, construction would begin in 2025 with a target in-service date of late 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 issuances and/or credit facility draws and the proceeds of capital market offerings to fund liabilities as they become due, finance capital expenditures and acquisitions, fund debt retirements and pay common and preference share dividends. We target to maintain sufficient liquidity through securement of committed credit facilities with a diversified group of banks and financial institutions to enable us to fund all anticipated requirements for approximately one year without accessing the capital markets.

We have signed capital obligation contracts for the purchase of services, pipe and other materials totaling approximately $2.9 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.

CAPITAL MARKET ACCESS

We ensure ready access to capital markets, subject to market conditions, through maintenance of shelf prospectuses that allow for issuances 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 March 31, 2024:


	Maturity1	Total Facilities	Draws2	Available
(millions of Canadian dollars)
Enbridge Inc.	2024-2049	9,036	5,690	3,346
Enbridge (U.S.) Inc.	2025-2028	8,594	3,681	4,913
Enbridge Pipelines Inc.	2025	2,000	728	1,272
Enbridge Gas Inc.	2025	2,500	335	2,165
Total committed credit facilities		22,130	10,434	11,696

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 2024, we entered into a delayed-draw term loan facility of $200 million which matures in March 2049.

As at March 31, 2024, our net available liquidity totaled $12.9 billion (December 31, 2023 - $23.0 billion), consisting of available credit facilities of $11.7 billion (December 31, 2023 - $17.1 billion) and unrestricted cash and cash equivalents of $1.2 billion (December 31, 2023 - $5.9 billion) as reported in the Consolidated Statements of Financial Position.

LONG-TERM DEBT ISSUANCE

LONG-TERM DEBT REPAYMENTS

During the three months ended March 31, 2024, we completed the following long-term debt repayments totaling US$2.7 billion and $0.2 billion:

Company

Repayment Date

Principal Amount

(millions of Canadian dollars, unless otherwise stated)

Enbridge Inc.

February 2024

Floating rate notes1

US$600

February 2024

2.15%

senior notes

US$400

March 2024

5.97%

senior notes2

US$700

Enbridge Pipelines Inc.

February 2024

8.20%

debentures

$200

Enbridge Southern Lights LP

January 2024

4.01%

senior notes

$10

Spectra Energy Partners, LP

March 2024

4.75%

senior notes

US$1,000

1The notes carried an interest rate set to equal the Secured Overnight Financing Rate plus a margin of 63 basis points.

2The notes carried an original maturity date in March 2026, and were callable one year after their issuance, in March 2024.

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 $171 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 March 31, 2024 and December 31, 2023, we had positive working capital positions of $1.2 billion and $3.0 billion, respectively. During both the three months ended March 31, 2024 and the year ended December 31, 2023, the major contributing factor to the positive working capital position was due to the increase in cash associated with pre-funding of the Acquisitions. The decrease to the working capital position at March 31, 2024 compared to December 31, 2023 was due to the closing of the EOG Acquisition. 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


	Three months ended March 31,
		2024	2023
(millions of Canadian dollars)
Operating activities		3,151	3,866
Investing activities		(7,792)	(1,437)
Financing activities		(120)	(2,289)
Effect of translation of foreign denominated cash and cash equivalents and restricted cash		161	4
Net change in cash and cash equivalents and restricted cash		(4,600)	144

Significant sources and uses of cash for the three months ended March 31, 2024 and 2023 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.

Investing Activities

Cash used in investing activities includes 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 EOG and Tomorrow RNG acquisitions.

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 normal course issuer bid (NCIB). Cash used in financing activities is also impacted by changes in distributions to, and contributions from, noncontrolling interests. Factors impacting the decrease in cash used in financing activities period-over-period primarily include:

•net commercial paper and credit facility draws in 2024 when compared to net repayments during the same period in 2023; and

•lower net repayments of short-term borrowings in 2024 when compared to the same period in 2023.

The factors above were partially offset by:

•an absence in 2024 of long-term debt issuances, as well as higher long-term debt repayments in 2024 when compared to the same period in 2023; and

•increased common share dividend payments primarily due to the increase in our common share dividend rate and an increase in the number of common shares outstanding.

SUMMARIZED FINANCIAL INFORMATION

On January 22, 2019, Enbridge entered into supplemental indentures with its wholly-owned subsidiaries, SEP and EEP (together, the Partnerships), pursuant to which Enbridge fully and unconditionally guaranteed, on a senior unsecured basis, the payment obligations of the Partnerships with respect to the outstanding series of notes issued under the respective indentures of the Partnerships. Concurrently, the Partnerships entered into a subsidiary guarantee agreement pursuant to which they 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
3.50% Senior Notes due 2025			5.88% Notes due 2025
3.38% Senior Notes due 2026			5.95% Notes due 2033
5.95% Senior Notes due 2043			6.30% Notes due 2034
4.50% Senior Notes due 2045			7.50% Notes due 2038
			5.50% Notes due 2040

			7.38% Notes due 2045

1As at March 31, 2024, the aggregate outstanding principal amount of SEP notes was approximately US$2.2 billion.

2As at March 31, 2024, the aggregate outstanding principal amount of EEP notes was approximately US$2.4 billion.

Enbridge Notes under Guarantees


USD Denominated1			CAD Denominated2
3.50% Senior Notes due 2024			3.95% Senior Notes due 2024
2.50% Senior Notes due 2025			2.44% Senior Notes due 2025
2.50% Senior Notes due 2025			3.20% Senior Notes due 2027
4.25% Senior Notes due 2026			5.70% Senior Notes due 2027
1.60% Senior Notes due 2026			6.10% Senior Notes due 2028
5.90% Senior Notes due 2026			4.90% Senior Notes due 2028
3.70% Senior Notes due 2027			2.99% Senior Notes due 2029
6.00% Senior Notes due 2028			7.22% Senior Notes due 2030
3.13% Senior Notes due 2029			7.20% Senior Notes due 2032
6.20% Senior Notes due 2030			6.10% Sustainability-Linked Senior Notes due 2032
2.50% Sustainability-Linked Senior Notes due 2033			3.10% Sustainability-Linked Senior Notes due 2033
5.70% Sustainability-Linked Senior Notes due 2033			5.36% Sustainability-Linked Senior Notes due 2033
4.50% Senior Notes due 2044			5.57% Senior Notes due 2035
5.50% Senior Notes due 2046			5.75% Senior Notes due 2039
4.00% Senior Notes due 2049			5.12% Senior Notes due 2040
3.40% Senior Notes due 2051			4.24% Senior Notes due 2042
6.70% Senior Notes due 2053			4.57% Senior Notes due 2044
			4.87% Senior Notes due 2044
			4.10% Senior Notes due 2051
			6.51% Senior Notes due 2052
			5.76% Senior Notes due 2053
			4.56% Senior Notes due 2064

1As at March 31, 2024, the aggregate outstanding principal amount of the Enbridge US dollar-denominated notes was approximately US$14.0 billion.

2As at March 31, 2024, 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


Three months ended March 31,			2024
(millions of Canadian dollars)

Operating income			35
Loss			(429)
Loss attributable to common shareholders			(522)

Summarized Combined Statements of Financial Position


	March 31, 2024	December 31, 2023
(millions of Canadian dollars)
Cash and cash equivalents	1,422	6,525
Accounts receivable from affiliates	3,282	3,440
Short-term loans receivable from affiliates	3,542	3,291
Other current assets	538	491
Long-term loans receivable from affiliates	37,196	45,702
Other long-term assets	1,539	3,303
Accounts payable to affiliates	2,560	2,264
Short-term loans payable to affiliates	992	807
Trade account payable and accrued liabilities	340	743
Other current liabilities	4,705	7,256
Long-term loans payable to affiliates	26,048	35,556
Other long-term liabilities	52,721	52,096

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 US 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 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. Briefing by the parties was complete on December 15, 2023. On December 12, 2023, the 7th Circuit Court of Appeals requested that the US file a brief in this appeal as amicus curiae to address the effect of the Agreement Between the US and Canada Concerning Transit Pipelines, 28 U.S.T. 7449 (1977), and any other issues that the US believes to be material. Subsequently, the US filed its brief on April 8, 2024. As invited by the Court of Appeals, Enbridge and the Band filed their respective responses to the US amicus brief on April 29, 2024. We anticipate the Court of Appeals will issue a decision in 2024.

OTHER LITIGATION

We and our subsidiaries are subject to 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

CHANGES IN ACCOUNTING POLICIES

Refer to Part I. Item 1. Financial Statements - Note 2. Changes in Accounting Policies.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Our exposure to market risk is described in Part II. Item 7A. Quantitative and Qualitative Disclosures About Market Risk of our annual report on Form 10-K for the year ended December 31, 2023. 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 March 31, 2024, 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 March 31, 2024 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 certain legal proceedings with recent developments.

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 previously reported, the Minnesota Attorney General filed a misdemeanor criminal charge for the taking of water without a permit at the Clearbrook aquifer, with this charge to be dismissed following one year of compliance with the state water appropriation rules. Enbridge satisfied all relevant conditions, and the misdemeanor charge was dismissed on February 5, 2024.

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, 2023, 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

On January 4, 2023, the Toronto Stock Exchange (TSX) approved our NCIB, which commenced on January 6, 2023 and expired on January 5, 2024. Our NCIB permitted us 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 through the facilities of the TSX, the New York Stock Exchange and other designated exchanges and alternative trading systems. No common shares were purchased under the NCIB during the period from January 1, 2024 to January 5, 2024.

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
2.1						Enbridge Pipelines Inc. Mainline Tolling Settlement, dated as of December 15, 2023, (incorporated by reference to Exhibit 10.1 to Enbridge’s Current Report on Form 8-K filed March 8, 2024).
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:	May 10, 2024	By:	/s/ Gregory L. Ebel
			Gregory L. Ebel
			President and Chief Executive Officer
			(Principal Executive Officer)

Date:	May 10, 2024	By:	/s/ Patrick R. Murray
			Patrick R. Murray
			Executive Vice President and Chief Financial Officer
			(Principal Financial Officer)

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SEC Form 10-Q filed by Enbridge Inc

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