enb-20250331

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, 2025


☐						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 2,180,284,527 common shares outstanding as at May 2, 2025.


	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	56
Item 3.	Defaults Upon Senior Securities	56
Item 4.	Mine Safety Disclosures	56
Item 5.	Other Information	56
Item 6.	Exhibits	57
	Signatures	58

GLOSSARY


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


AOCI			Accumulated other comprehensive income/(loss)







DAPL			Dakota Access Pipeline
EBITDA			Earnings before interest, income taxes and depreciation and amortization

EEP			Enbridge Energy Partners, L.P.





EIS			Environmental Impact Statement
Enbridge Gas Ontario			Enbridge Gas Inc.

EOG			The East Ohio Gas Company

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



















OCI			Other comprehensive income/(loss)

OEB			Ontario Energy Board









SEP			Spectra Energy Partners, LP























the Band			the Bad River Band of the Lake Superior Tribe of Chippewa Indians
the Court			the US District Court for the Western District of Wisconsin
the District Court			the US Court for the District of Columbia
the Partnerships			Spectra Energy Partners, LP and Enbridge Energy Partners, L.P.
the Reservation			the Bad River Reservation
Tomorrow RNG			Six Morrow Renewables operating landfill gas-to-renewable natural gas production facilities

US			United States of America
US District Court			the US District Court in the Western District of Michigan

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, dispositions and other transactions, including the anticipated benefits of the acquisitions of three US gas utilities (Gas Utilities) from Dominion Energy, Inc. (the Acquisitions); expected future actions of regulators and courts, government trade policies, including possible impacts of potential and announced tariffs, duties, fees, economic sanctions, or other trade measures and the timing and impact thereof; 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 successfully integrate the Gas Utilities; expected closing of acquisitions, dispositions and other transactions and the timing thereof; toll and rate cases discussions and proceedings and anticipated outcomes, timelines and impacts therefrom, including those relating to the Gas Transmission and Gas Distribution and Storage businesses; operational, industry, regulatory, climate change and other risks associated with our businesses; and our assessment of the potential impact of the various risk factors identified herein.

Although we believe these forward-looking statements are reasonable based on the information available on the date such statements are made and processes used to prepare the information, such statements are not guarantees of future performance and readers are cautioned against placing undue reliance on forward-looking statements. By their nature, these statements involve a variety of assumptions, known and unknown risks and uncertainties and other factors, which may cause actual results, levels of activity and achievements to differ materially from those expressed or implied by such statements. Material assumptions include assumptions about the following: the expected supply of, demand for, export of and prices of crude oil, natural gas, NGL, LNG, RNG and renewable energy; anticipated utilization of assets; exchange rates; inflation; interest rates; tariffs and trade policies; 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, dispositions and other transactions; 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, interest rates and tariffs 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; the impact of weather and customer, government, court and regulatory approvals on construction and in-service schedules and cost recovery regimes.

Our forward-looking statements are subject to risks and uncertainties pertaining to the successful execution of our strategic priorities; operating performance; legislative and regulatory parameters; litigation; acquisitions, dispositions and other transactions and the realization of anticipated benefits therefrom (including the anticipated benefits from the Acquisitions); evolving government trade policies, including potential and announced tariffs, duties, fees, economic sanctions or other trade measures; 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,
	2025	2024
(unaudited; millions of Canadian dollars, except per share amounts)
Operating revenues
Commodity sales	9,549	4,145
Gas distribution sales	3,699	1,960
Transportation and other services	5,254	4,933
Total operating revenues (Note 3)	18,502	11,038
Operating expenses
Commodity costs	9,335	4,006
Gas distribution costs	1,616	994
Operating and administrative	2,471	2,134
Depreciation and amortization	1,408	1,193

Total operating expenses	14,830	8,327
Operating income	3,672	2,711
Income from equity investments	729	696


Other income/(expense) (Note 11)	120	(551)
Interest expense	(1,334)	(905)
Earnings before income taxes	3,187	1,951
Income tax expense	(697)	(386)
Earnings	2,490	1,565
Earnings attributable to noncontrolling interests	(126)	(53)
Earnings attributable to controlling interests	2,364	1,512
Preference share dividends	(103)	(93)
Earnings attributable to common shareholders	2,261	1,419
Earnings per common share attributable to common shareholders (Note 5)	1.04	0.67
Diluted earnings per common share attributable to common shareholders (Note 5)	1.03	0.67

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,
	2025	2024
(unaudited; millions of Canadian dollars)
Earnings	2,490	1,565
Other comprehensive income/(loss), net of tax
Change in unrealized gain/(loss) on cash flow hedges	(25)	116
Change in unrealized loss on net investment hedges	(34)	(377)
Other comprehensive income/(loss) from equity investees and other investments	12	(1)
Excluded components of fair value hedges	4	4
Reclassification to earnings of loss on cash flow hedges	6	—
Reclassification to earnings of pension and other postretirement benefits (OPEB) amounts	(7)	(4)

Foreign currency translation adjustments	119	1,658
Other comprehensive income, net of tax	75	1,396
Comprehensive income	2,565	2,961
Comprehensive income attributable to noncontrolling interests	(128)	(88)
Comprehensive income attributable to controlling interests	2,437	2,873
Preference share dividends	(103)	(93)
Comprehensive income attributable to common shareholders	2,334	2,780

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,
	2025	2024
(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	71,738	69,180

Shares issued on exercise of stock options	32	4
Shares issued on vesting of restricted stock units (RSU), net of tax	38	17


Balance at end of period	71,808	69,201
Additional paid-in capital
Balance at beginning of period	275	268
Stock-based compensation	49	32
Stock options exercised	(27)	(4)
Vested RSUs	(68)	(22)


Balance at end of period	229	274
Deficit
Balance at beginning of period	(20,046)	(17,115)
Earnings attributable to controlling interests	2,364	1,512
Preference share dividends	(103)	(93)




Balance at end of period	(17,785)	(15,696)
Accumulated other comprehensive income (Note 8)
Balance at beginning of period	7,115	2,303
Other comprehensive income attributable to common shareholders, net of tax	73	1,361
Balance at end of period	7,188	3,664




Total Enbridge Inc. shareholders’ equity	68,258	64,261
Noncontrolling interests
Balance at beginning of period	2,993	3,029
Earnings attributable to noncontrolling interests	126	53
Other comprehensive income attributable to noncontrolling interests, net of tax
Change in unrealized gain on cash flow hedges	1	6
Foreign currency translation adjustments	1	29
	2	35
Comprehensive income attributable to noncontrolling interests	128	88
Distributions	(100)	(78)
Contributions	5	2

Other	(4)	1
Balance at end of period	3,022	3,042
Total equity	71,280	67,303
Dividends paid per common share	0.94	0.92

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,
	2025	2024
(unaudited; millions of Canadian dollars)
Operating activities
Earnings	2,490	1,565
Adjustments to reconcile earnings to net cash provided by operating activities:
Depreciation and amortization	1,408	1,193
Deferred income tax expense	304	134
Unrealized derivative fair value loss/(gain), net (Note 9)	(92)	693
Income from equity investments	(729)	(696)
Distributions from equity investments	557	556




Other	14	6
Changes in operating assets and liabilities	(899)	(300)
Net cash provided by operating activities	3,053	3,151
Investing activities
Capital expenditures	(1,723)	(1,185)
Long-term, restricted and other investments	(304)	(411)
Distributions from equity investments in excess of cumulative earnings	184	266
Additions to intangible assets	(60)	(42)
Acquisitions	—	(6,397)
Proceeds from disposition of equity investments	130	—


Other	(16)	(23)
Net cash used in investing activities	(1,789)	(7,792)
Financing activities
Net change in short-term borrowings	330	(65)
Net change in commercial paper and credit facility draws	967	5,828
Debenture and term note issues, net of issue costs	2,777	—
Debenture and term note repayments	(2,742)	(3,781)
Contributions from noncontrolling interests	5	2
Distributions to noncontrolling interests	(100)	(78)
Common shares issued, net of issue costs	5	—

Preference share dividends	(102)	(93)
Common share dividends	(2,054)	(1,945)

Net change in affiliate loans	—	14
Other	(36)	(2)
Net cash used in financing activities	(950)	(120)
Effect of translation of foreign denominated cash and cash equivalents and restricted cash	8	161
Net change in cash and cash equivalents and restricted cash	322	(4,600)
Cash and cash equivalents and restricted cash at beginning of period1	2,000	5,985
Cash and cash equivalents and restricted cash at end of period1	2,322	1,385

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

1As at March 31, 2025 and December 31, 2024, long-term restricted cash of $109 million (March 31, 2024 - nil) and $105 million (December 31, 2023 - nil), respectively, was included in Restricted long-term investments and cash in the Consolidated Statements of Financial Position.

ENBRIDGE INC.

CONSOLIDATED STATEMENTS OF FINANCIAL POSITION


	March 31, 2025	December 31, 2024
(unaudited; millions of Canadian dollars; number of shares in millions)
Assets
Current assets
Cash and cash equivalents	2,087	1,803
Restricted cash	126	92
Trade receivables and unbilled revenues	7,619	6,920
Other current assets	2,440	2,770
Accounts receivable from affiliates	98	90
Inventory	1,228	1,488
	13,598	13,163
Property, plant and equipment, net	131,583	131,104
Long-term investments	20,978	20,691
Restricted long-term investments and cash (Note 9)	1,065	998
Deferred amounts and other assets	10,916	11,034
Intangible assets, net	4,515	4,587
Goodwill	36,599	36,600
Deferred income taxes	791	796
Total assets	220,045	218,973

Liabilities and equity
Current liabilities
Short-term borrowings	859	529
Trade payables and accrued liabilities	6,609	7,060
Other current liabilities	4,871	7,241
Accounts payable to affiliates	28	22
Interest payable	1,172	1,231
Current portion of long-term debt	5,095	7,729
	18,634	23,812
Long-term debt	97,159	93,414
Other long-term liabilities	12,995	13,258
Deferred income taxes	19,977	19,596
	148,765	150,080
Contingencies (Note 12)
Equity
Share capital
Preference shares	6,818	6,818
Common shares (2,180 and 2,178 outstanding at March 31, 2025 and December 31, 2024, respectively)	71,808	71,738
Additional paid-in capital	229	275
Deficit	(17,785)	(20,046)
Accumulated other comprehensive income (Note 8)	7,188	7,115

Total Enbridge Inc. shareholders’ equity	68,258	65,900
Noncontrolling interests	3,022	2,993
	71,280	68,893
Total liabilities and equity	220,045	218,973

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, 2024. 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, 2024. 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

Income Tax Disclosures

Accounting Standards Update (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. The effects of the new standard on the presentation of our income tax note disclosures will be reflected in our December 31, 2025 annual consolidated financial statements.

Disaggregation of Income Statement Expenses

ASU 2024-03 was issued in November 2024 to improve financial reporting by requiring entities to disclose additional information about specific expense categories in the notes to financial statements at interim and annual reporting periods. The ASU requires entities to disclose 1) the amounts of (a) purchases of inventory, (b) employee compensation, (c) depreciation, (d) intangible asset amortization, (e) depreciation, depletion and amortization recognized as part of oil and gas producing activities, (f) expense reimbursements included in a relevant expense caption, and (g) selling expenses, and 2) a qualitative description of the amounts remaining in relevant expense captions that are not separately disaggregated quantitatively. ASU 2024-03 is effective January 1, 2027, with interim period disclosure requirements effective after January 1, 2028 and can be applied either prospectively or retrospectively. We are currently assessing the impact of the new standard on our annual disclosures for the year ending December 31, 2027 and on our interim disclosures beginning in 2028.

3. REVENUE

Change in Revenue Classification

To better align the classification of revenues resulting from our acquisitions of the United States (US) Gas Utilities (Note 6), we have made adjustments to Gas distribution sales and Transportation and other services revenues. Revenues generated from customers who procure their own gas but use our distribution system for delivery to the end use location have been reclassified to Gas distribution sales revenue from Transportation and other services revenue on the Consolidated Statements of Earnings and reclassified to Gas distribution sales from Transportation revenue in the Revenue from Contracts with Customers tables below. Our prior period comparable results have been recast to reflect the change in revenue classification. This change did not have an impact on our Total operating revenues.

REVENUE FROM CONTRACTS WITH CUSTOMERS

Major Products and Services


Three months ended March 31, 2025	Liquids Pipelines	Gas Transmission	Gas Distribution and Storage	Renewable Power Generation	Eliminations and Other	Consolidated
(millions of Canadian dollars)
Transportation revenue	3,105	1,480	90	—	—	4,675
Storage and other revenue	68	173	157	—	—	398

Gas distribution revenue	—	—	3,670	—	—	3,670
Electricity revenue	—	—	—	42	—	42
Commodity sales	—	24	—	—	—	24
Total revenue from contracts with customers	3,173	1,677	3,917	42	—	8,809
Commodity sales	8,934	37	—	—	554	9,525
Other revenue1,2	77	(7)	21	77	—	168
Intersegment revenue	—	8	18	1	(27)	—
Total revenue	12,184	1,715	3,956	120	527	18,502


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 revenue3	3,024	1,341	93	—	—	4,458
Storage and other revenue	62	138	99	—	—	299

Gas distribution revenue3	—	—	1,924	—	—	1,924
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

1Includes realized and unrealized gains and losses from our hedging program which for the three months ended March 31, 2025 were a net $99 million gain (2024 - $22 million loss).

2Includes revenues from lease contracts for the three months ended March 31, 2025 and 2024 of $158 million and $140 million, respectively.

3These balances reflect a transfer from Transportation revenue to Gas distribution sales of $258 million for the three months ended March 31, 2024.

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, 2025	4,207	323	2,728
Balance as at December 31, 2024	3,764	330	2,828

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, 2025 included in contract liabilities at the beginning of the period were $245 million. Increases in contract liabilities from cash received, net of amounts recognized as revenues, during the three months ended March 31, 2025 were $142 million.

Performance Obligations

There were no material revenues recognized in the three months ended March 31, 2025 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 $62.8 billion, of which $7.9 billion and $8.1 billion are expected to be recognized during the remaining nine months ending December 31, 2025 and the year ending December 31, 2026, 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.

Recognition and Measurement of Revenues


Three months ended March 31, 2025	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	—	24	36	—	60
Revenues from products and services transferred over time1	3,173	1,653	3,881	42	8,749
Total revenue from contracts with customers	3,173	1,677	3,917	42	8,809

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

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


Three months ended March 31, 2025	Liquids Pipelines	Gas Transmission	Gas Distribution and Storage	Renewable Power Generation	Total Reportable Segments
(millions of Canadian dollars)
Operating revenues1	12,184	1,715	3,956	120	17,975
Commodity and gas distribution costs	(8,850)	(11)	(1,634)	3	(10,492)
Operating and administrative	(1,128)	(524)	(772)	(78)	(2,502)


Income from equity investments	368	232	1	132	733


Other income	19	61	49	46	175
Earnings before interest, income taxes and depreciation and amortization	2,593	1,473	1,600	223	5,889
Eliminations and Other					40
Depreciation and amortization					(1,408)
Interest expense					(1,334)
Earnings before income taxes					3,187


Three months ended March 31, 2024	Liquids Pipelines	Gas Transmission	Gas Distribution and Storage	Renewable Power Generation	Total Reportable Segments
(millions of Canadian dollars)
Operating revenues1	6,882	1,572	2,131	131	10,716
Commodity and gas distribution costs	(3,635)	(47)	(1,004)	(3)	(4,689)
Operating and administrative	(1,107)	(561)	(379)	(69)	(2,116)


Income from equity investments	253	265	—	181	699


Other income	11	36	17	17	81
Earnings before interest, income taxes and depreciation and amortization	2,404	1,265	765	257	4,691
Eliminations and Other					(642)
Depreciation and amortization					(1,193)
Interest expense					(905)
Earnings before income taxes					1,951

1Refer to Note 3 - Revenue for a reconciliation of segment Operating revenues to the Consolidated Statements of Earnings.

Capital Expenditures1


Three months ended March 31,	2025	2024
(millions of Canadian dollars)
Liquids Pipelines	309	289
Gas Transmission	604	495
Gas Distribution and Storage	661	304
Renewable Power Generation	145	69
Eliminations and Other	35	43
	1,754	1,200

1Includes the equity component of the allowance for funds used during construction.

Property, Plant and Equipment


	March 31, 2025	December 31, 2024
(millions of Canadian dollars)
Liquids Pipelines	53,693	53,863
Gas Transmission	34,940	34,683
Gas Distribution and Storage	38,909	38,636
Renewable Power Generation	3,720	3,612
Eliminations and Other	321	310
	131,583	131,104

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,
		2025	2024
(number of shares in millions)
Weighted average shares outstanding		2,179	2,126
Effect of dilutive options and RSUs		6	2
Diluted weighted average shares outstanding		2,185	2,128

For the three months ended March 31, 2025 and 2024, 3.1 million and 23.0 million, respectively, of anti-dilutive stock options with a weighted average exercise price of $60.45 and $52.97, respectively, were excluded from the diluted earnings per common share calculation.

DIVIDENDS PER SHARE

The Board of Directors has declared the following quarterly dividends. All dividends are payable on June 1, 2025 to shareholders of record on May 15, 2025.


			Dividend per share
Common Shares			$0.94250
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			$0.34468
Preference Shares, Series H			$0.38200
Preference Shares, Series I2			$0.32011
Preference Shares, Series L			US$0.36612
Preference Shares, Series N			$0.41850
Preference Shares, Series P			$0.36988
Preference Shares, Series R			$0.39463
Preference Shares, Series 1			US$0.41898
Preference Shares, Series 3			$0.33050
Preference Shares, Series 43			$0.33649
Preference Shares, Series 5			US$0.41769
Preference Shares, Series 7			$0.37425
Preference Shares, Series 9			$0.35450
Preference Shares, Series 114			$0.34231
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 $0.34468 from $0.37911 on March 1, 2025 due to reset on a quarterly basis.

2The quarterly dividend per share paid on Preference Shares, Series I was decreased to $0.32011 from $0.35507 on March 1, 2025 due to reset on a quarterly basis.

3The quarterly dividend per share paid on Preference Shares, Series 4 was decreased to $0.33649 from $0.37110 on March 1, 2025 due to reset on a quarterly basis.

4The quarterly dividend per share paid on Preference Shares, Series 11 was increased to $0.34231 from $0.24613 on March 1, 2025 due to reset of the annual dividend on March 1, 2025.

6. ACQUISITIONS

BUSINESS COMBINATIONS

We accounted for each of the acquisitions discussed below 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 Regulated Operations, 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 East Ohio Gas Company

On March 6, 2024, through a wholly-owned US subsidiary, we acquired all of the outstanding shares of capital stock of 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. Subsequent to its acquisition, EOG conducts business as Enbridge Gas Ohio.

The EOG Acquisition further diversifies, and is complementary to, our existing gas distribution business.

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


			March 6, 20241
(millions of Canadian dollars)
Fair value of net assets acquired:
Current assets (a)			493
Property, plant and equipment (b)			7,276
Long-term assets (c)			1,689
Current liabilities			551
Long-term debt (d)			2,612
Other long-term liabilities (e)			1,001
Deferred income tax liabilities			1,045
Goodwill (f)			1,603
Purchase price:
Cash			5,852

1 In the fourth quarter of 2024, immaterial adjustments were made to the EOG Acquisition purchase price allocation.

a) Current assets consist primarily of trade and other accounts receivable, prepaid expenses, regulatory assets and inventory. The fair value of trade receivables from customers approximates their carrying value of $379 million due to the short period to maturity. A provision of $3 million for expected credit loss associated with accounts receivable has been recorded.

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 $367 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 March 6, 2024. 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 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 a platform 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 $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, including the results of operations for EOG as if the EOG Acquisition had been completed on January 1, 2023, was as follows:



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

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 lower-carbon strategy.

The following table summarizes the estimated 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 (approximately nine years to the next extension period on a weighted-average basis).

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 payment was made on January 2, 2025 and the second payment is due on December 31, 2025. 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, 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, 2025:


	Maturity1	Total Facilities	Draws2	Available
(millions of Canadian dollars)
Enbridge Inc.	2025-2049	8,874	6,379	2,495
Enbridge (U.S.) Inc.	2026-2029	10,822	5,144	5,678
Enbridge Pipelines Inc.	2026	2,000	540	1,460
Enbridge Gas Inc.	2026	2,500	860	1,640
Total committed credit facilities		24,196	12,923	11,273

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 addition to the committed credit facilities noted above, we maintain $1.5 billion of uncommitted demand letter of credit facilities, of which $882 million was unutilized as at March 31, 2025. As at December 31, 2024, we had $1.4 billion of uncommitted demand letter of credit facilities, of which $931 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 our commercial paper programs and we have the option to extend such facilities, which are currently scheduled to mature from 2025 to 2049.

As at March 31, 2025 and December 31, 2024, commercial paper and credit facility draws, net of short-term borrowings and non-revolving credit facilities that mature within one year, of $11.2 billion and $10.3 billion, respectively, were supported by the availability of long-term committed credit facilities and, therefore, have been classified as long-term debt.

LONG-TERM DEBT ISSUANCES

During the three months ended March 31, 2025, we completed the following long-term debt issuances totaling $2.8 billion:

Company

Issue Date

Principal Amount

(millions of Canadian dollars, unless otherwise stated)

Enbridge Inc.

February 2025

Floating rate medium-term notes due February 20281

$400

February 2025

3.55%

medium-term notes due February 2028

$300

February 2025

3.90%

medium-term notes due February 2030

$800

February 2025

4.56%

medium-term notes due February 2035

$700

February 2025

5.32%

medium-term notes due August 2054

$600

1Notes carry an interest rate set to equal the Canadian Overnight Repo Rate Average plus a margin of 85 basis points.

LONG-TERM DEBT REPAYMENTS

During the three months ended March 31, 2025, we completed the following long-term debt repayments totaling US$1.9 billion, and $0.1 billion:

Company

Repayment Date

Principal Amount

(millions of Canadian dollars, unless otherwise stated)

Enbridge Inc.

January 2025

2.50%

senior notes

US$500

February 2025

2.50%

senior notes

US$500

Enbridge Pipelines Inc.

February 2025

4.10%

medium-term notes1

$100

Spectra Energy Partners, LP

March 2025

3.50%

senior notes

US$500

Enbridge Holdings (Tomorrow RNG), LLC

January 2025

4.97%

senior notes

US$309

January 2025

4.97%

senior notes

US$85

January 2025

4.97%

senior notes

US$19

1The notes carried an original maturity date in July 2112.

SUBORDINATED TERM NOTES

As at March 31, 2025 and December 31, 2024, our fixed-to-floating rate and fixed-to-fixed rate subordinated term notes had a principal value of $15.5 billion.

FAIR VALUE ADJUSTMENT

As at March 31, 2025 and December 31, 2024, the fair value adjustments to decrease total debt assumed in a historical acquisition were $465 million and $468 million, respectively.

DEBT COVENANTS

Our credit facility agreements and term debt indentures include standard events of default and covenant provisions whereby accelerated repayment and/or termination of the agreements may result if we were to default on payment or violate certain covenants. As at March 31, 2025, 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, 2025 and 2024 are as follows:


	Cash Flow Hedges	Excluded Components of Fair Value Hedges	Net Investment Hedges	Cumulative Translation Adjustment	Equity Investees and Other Investments	Pension and OPEB Adjustment	Total
(millions of Canadian dollars)
Balance as at January 1, 2025	407	(14)	(2,033)	8,452	1	302	7,115
Other comprehensive income/(loss) retained in AOCI	(35)	(6)	(34)	118	12	—	55
Other comprehensive (income)/loss reclassified to earnings
Interest rate contracts1	8	—	—	—	—	—	8

Foreign exchange contracts2	—	12	—	—	—	—	12

Amortization of pension and OPEB actuarial gain3	—	—	—	—	—	(9)	(9)

	(27)	6	(34)	118	12	(9)	66
Tax impact
Income tax on amounts retained in AOCI	9	1	—	—	—	—	10
Income tax on amounts reclassified to earnings	(2)	(3)	—	—	—	2	(3)
	7	(2)	—	—	—	2	7

Balance as at March 31, 2025	387	(10)	(2,067)	8,570	13	295	7,188


	Cash Flow Hedges	Excluded Components of Fair Value Hedges	Net Investment Hedges	Cumulative Translation Adjustment	Equity Investees and Other Investments	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 contracts2	—	19	—	—	—	—	19

Amortization of pension and OPEB actuarial gain3	—	—	—	—	—	(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

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

2Reported within Interest expense and Other income/(expense) in the Consolidated Statements of Earnings.

3These components are included in the computation of net periodic benefit credit and are reported within Other income/(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 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 derivative instruments. We have implemented a 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 3.5%.

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 3.6%.

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 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, 2025	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	—	—	26	26	(17)	9
Interest rate contracts	5	—	16	21	(9)	12
Commodity contracts	2	—	432	434	(257)	177

	7	—	474	481	(283)	198
Deferred amounts and other assets
Foreign exchange contracts	—	—	68	68	(58)	10
Interest rate contracts	15	—	92	107	(32)	75
Commodity contracts	—	—	196	196	(53)	143

	15	—	356	371	(143)	228
Other current liabilities
Foreign exchange contracts	—	(31)	(713)	(744)	17	(727)
Interest rate contracts	(11)	—	(25)	(36)	9	(27)
Commodity contracts	—	—	(483)	(483)	257	(226)

	(11)	(31)	(1,221)	(1,263)	283	(980)
Other long-term liabilities
Foreign exchange contracts	—	—	(1,523)	(1,523)	58	(1,465)
Interest rate contracts	(16)	—	(97)	(113)	32	(81)
Commodity contracts	—	—	(162)	(162)	53	(109)

	(16)	—	(1,782)	(1,798)	143	(1,655)
Total net derivative asset/(liability)
Foreign exchange contracts	—	(31)	(2,142)	(2,173)	—	(2,173)
Interest rate contracts	(7)	—	(14)	(21)	—	(21)
Commodity contracts	2	—	(17)	(15)	—	(15)

	(5)	(31)	(2,173)	(2,209)	—	(2,209)


December 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	—	78	47	125	(29)	96
Interest rate contracts	44	—	23	67	(39)	28
Commodity contracts	2	—	360	362	(191)	171
Other contracts	—	—	3	3	—	3
	46	78	433	557	(259)	298
Deferred amounts and other assets
Foreign exchange contracts	—	—	83	83	(71)	12
Interest rate contracts	9	—	137	146	(27)	119
Commodity contracts	—	—	197	197	(39)	158

	9	—	417	426	(137)	289
Other current liabilities
Foreign exchange contracts	—	(73)	(731)	(804)	29	(775)
Interest rate contracts	(58)	—	(22)	(80)	39	(41)
Commodity contracts	—	—	(451)	(451)	191	(260)

	(58)	(73)	(1,204)	(1,335)	259	(1,076)
Other long-term liabilities
Foreign exchange contracts	—	—	(1,579)	(1,579)	71	(1,508)
Interest rate contracts	—	—	(80)	(80)	27	(53)
Commodity contracts	(1)	—	(238)	(239)	39	(200)

	(1)	—	(1,897)	(1,898)	137	(1,761)
Total net derivative asset/(liability)
Foreign exchange contracts	—	5	(2,180)	(2,175)	—	(2,175)
Interest rate contracts	(5)	—	58	53	—	53
Commodity contracts	1	—	(132)	(131)	—	(131)
Other contracts	—	—	3	3	—	3
	(4)	5	(2,251)	(2,250)	—	(2,250)

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


March 31, 2025	2025	2026	2027	2028	2029	Thereafter	Total
Foreign exchange contracts - US dollar forwards - purchase (millions of US dollars)	791	—	—	—	—	—	791
Foreign exchange contracts - US dollar forwards - sell (millions of US dollars)	4,706	5,627	4,841	3,552	1,278	30	20,034

Foreign exchange contracts - British pound (GBP) forwards - sell (millions of GBP)	23	28	32		—	—	83

Foreign exchange contracts - Euro forwards - sell (millions of Euro)	93	121	81	67	66	129	557
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)	1,469	1,737	676	49	13	—	3,944

Interest rate contracts - long-term pay fixed rate (millions of Canadian dollars)1	2,883	1,384	—	—	—	—	4,267
Interest rate contracts - costless collar (millions of Canadian dollars)	1,520	1,314	846	36	—	—	3,716

Commodity contracts - natural gas (billions of cubic feet)2	93	87	42	14	4	2	242
Commodity contracts - crude oil (millions of barrels)2	1	5	(3)	1	1	1	6

Commodity contracts - power (megawatt per hour (MW/H))	118	107	51	30	30	—	64	3

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

2Represents the notional amount of net purchase/(sale).

3Total 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,
		2025	2024
(millions of Canadian dollars)
Unrealized loss on derivative		(42)	(63)
Unrealized gain on hedged item		50	74
Realized gain on derivative		61	59
Realized loss on hedged item		(74)	(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,
		2025	2024
(millions of Canadian dollars)
Amount of unrealized gain/(loss) recognized in OCI
Cash flow hedges

Interest rate contracts		(35)	138
Commodity contracts		1	12
Other contracts		—	1
Fair value hedges
Foreign exchange contracts		(6)	(15)


		(40)	136
Amount of loss reclassified from AOCI to earnings
Foreign exchange contracts1		12	19
Interest rate contracts2		8	—


		20	19

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

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

We estimate that a gain of $2 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, 2025.

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,
		2025	2024
(millions of Canadian dollars)
Foreign exchange contracts1		38	(730)
Interest rate contracts2		(73)	105
Commodity contracts3		130	(67)
Other contracts4		(3)	(1)
Total unrealized derivative fair value gain/(loss), net		92	(693)

1Reported within Other income/(expense) 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 (2025 - $86 million gain; 2024 - $35 million loss), Commodity sales (2025 - $24 million loss; 2024 - $37 million loss), Commodity costs (2025 - $70 million gain; 2024 - $23 million gain) and Operating and administrative expense (2025 - $2 million loss; 2024 - $18 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. 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, 2025. 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 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, contractual requirements and netting arrangements. We also review counterparty credit exposure using external credit rating services and other analytical tools to manage credit risk.

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


	March 31, 2025	December 31, 2024
(millions of Canadian dollars)
Canadian financial institutions	291	344
US financial institutions	107	128
European financial institutions	73	116
Asian financial institutions	32	53
Other1	335	332
	838	973

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

As at March 31, 2025, 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, 2025 and December 31, 2024.

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 counterparty credit ratings and netting arrangements. Within the Gas Distribution and Storage segment, credit risk is mitigated by the utility's large and diversified customer base and the ability to recover 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. Under the fair value hierarchy, cash and cash equivalents are classified as Level 1. 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, and investments in exchange-traded funds held by our captive insurance subsidiaries. We also hold restricted long-term investments in exchange-traded funds and common shares in trusts in accordance with the CER's regulatory requirements under the Land Matters Consultation Initiative (LMCI) and to cover future pipeline decommissioning costs in the state of Minnesota.

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, physical forward commodity contracts, as well as options. 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, 2025	Level 1	Level 2	Level 3	Total Gross Derivative Instruments
(millions of Canadian dollars)
Financial assets
Current derivative assets
Foreign exchange contracts	—	26	—	26
Interest rate contracts	—	21	—	21
Commodity contracts	30	76	328	434

	30	123	328	481
Long-term derivative assets
Foreign exchange contracts	—	68	—	68
Interest rate contracts	—	107	—	107
Commodity contracts	—	17	179	196

	—	192	179	371
Financial liabilities
Current derivative liabilities
Foreign exchange contracts	—	(744)	—	(744)
Interest rate contracts	—	(36)	—	(36)
Commodity contracts	(49)	(113)	(321)	(483)

	(49)	(893)	(321)	(1,263)
Long-term derivative liabilities
Foreign exchange contracts	—	(1,523)	—	(1,523)
Interest rate contracts	—	(113)	—	(113)
Commodity contracts	—	(33)	(129)	(162)

	—	(1,669)	(129)	(1,798)
Total net financial asset/(liability)
Foreign exchange contracts	—	(2,173)	—	(2,173)
Interest rate contracts	—	(21)	—	(21)
Commodity contracts	(19)	(53)	57	(15)

	(19)	(2,247)	57	(2,209)


December 31, 2024	Level 1	Level 2	Level 3	Total Gross Derivative Instruments
(millions of Canadian dollars)
Financial assets
Current derivative assets
Foreign exchange contracts	—	125	—	125
Interest rate contracts	—	67	—	67
Commodity contracts	34	72	256	362
Other contracts	—	3	—	3
	34	267	256	557
Long-term derivative assets
Foreign exchange contracts	—	83	—	83
Interest rate contracts	—	146	—	146
Commodity contracts	1	14	182	197

	1	243	182	426
Financial liabilities
Current derivative liabilities
Foreign exchange contracts	—	(804)	—	(804)
Interest rate contracts	—	(80)	—	(80)
Commodity contracts	(52)	(116)	(283)	(451)

	(52)	(1,000)	(283)	(1,335)
Long-term derivative liabilities
Foreign exchange contracts	—	(1,579)	—	(1,579)
Interest rate contracts	—	(80)	—	(80)
Commodity contracts	(1)	(31)	(207)	(239)

	(1)	(1,690)	(207)	(1,898)
Total net financial asset/(liability)
Foreign exchange contracts	—	(2,175)	—	(2,175)
Interest rate contracts	—	53	—	53
Commodity contracts	(18)	(61)	(52)	(131)
Other contracts	—	3	—	3
	(18)	(2,180)	(52)	(2,250)

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


March 31, 2025	Fair Value	Unobservable Input	Minimum Price/Volatility	Maximum Price/ Volatility	Weighted Average Price/Volatility	Unit of Measurement
(fair value in millions of Canadian dollars)
Commodity contracts - financial1
Natural gas	11	Forward gas price	3.78	9.85	5.91	$/mmbtu2
Crude	(8)	Forward crude price	76.32	103.75	97.19	$/barrel

Power	(19)	Forward power price	28.60	195.45	74.48	$/MW/H
Commodity contracts - physical1
Natural gas	(71)	Forward gas price	0.59	12.21	4.61	$/mmbtu2
Crude	25	Forward crude price	76.45	118.36	99.11	$/barrel

Power	(15)	Forward power price	24.97	138.58	76.37	$/MW/H
Commodity options3
Natural gas	134	Forward gas price	4.66	11.29	7.60	$/mmbtu2
		Price volatility	11%	77%	53%
	57

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

2One million British thermal units (mmbtu).

3Commodity options contracts are valued using an option model valuation technique.

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,
	2025	2024
(millions of Canadian dollars)
Level 3 net derivative liability at beginning of period	(52)	(131)
Total gain/(loss), unrealized
Included in earnings1	23	(17)
Included in OCI	2	12
Included in regulatory assets/liabilities	(45)	—
Settlements	129	9
Level 3 net derivative asset/(liability) at end of period	57	(127)

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, 2025 or December 31, 2024.

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, 2025 and 2024, we recognized unrealized foreign exchange gains of $47 million and losses of $377 million, respectively, on the translation of US dollar-denominated debt, in OCI. During the three months ended March 31, 2025 and 2024, we recognized realized losses of $81 million and nil, respectively, associated with the settlement of US dollar-denominated debt that had matured during the period, in OCI.

Fair Value of Other Financial Instruments

Certain long-term investments in other entities with no actively quoted prices are classified as Fair Value Measurement Alternative (FVMA) investments and are recorded at cost less impairment. The carrying value of FVMA investments totaled $186 million and $187 million as at March 31, 2025 and December 31, 2024, respectively.

As at March 31, 2025, we had investments with a fair value of $1,065 million included in Restricted long-term investments and cash in the Consolidated Statements of Financial Position (December 31, 2024 - $998 million) which are classified as available-for-sale. During the three months ended March 31, 2025, we purchased and sold $103 million and $77 million of restricted long-term investments, respectively (2024 - purchases of $36 million and sales of $10 million). The net cash flow impact is presented in Cash Flows from Investing Activities in the Consolidated Statements of Cash Flows. These securities represent restricted funds held in trust for the purpose of funding pipeline abandonment in accordance with the regulatory requirements of the Canada Energy Regulator, to cover future pipeline decommissioning costs in the state of Minnesota and to satisfy retirement obligations as Wexpro properties are abandoned.

We had restricted long-term investments and cash held in trust totaling $529 million as at March 31, 2025 which are classified as Level 1 in the fair value hierarchy (December 31, 2024 - $491 million). We also had restricted long-term investments held in trust totaling $536 million (cost basis - $558 million) and $507 million (cost basis - $540 million) as at March 31, 2025 and December 31, 2024, respectively, which are classified as Level 2 in the fair value hierarchy. There were unrealized holding gains of $16 million on these investments for the three months ended March 31, 2025 (2024 - losses of $13 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, 2025, the fair value of investments in equity funds and debt securities held by our captive insurance subsidiaries was $nil and $1.1 billion, respectively (December 31, 2024 - $114 million and $1.1 billion, respectively). Our investments in debt securities had a cost basis of $1.1 billion as at March 31, 2025 (December 31, 2024 - $1.1 billion). 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 $1 million for the three months ended March 31, 2025, (2024 - gains of $16 million).

As at March 31, 2025 and December 31, 2024, our long-term debt including finance lease liabilities had a carrying value of $102.7 billion and $101.6 billion, respectively, before debt issuance costs and a fair value of $101.4 billion and $98.9 billion, respectively.

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 and long-term debt 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, 2025 and 2024 were 21.9% and 19.8%, respectively.

The period-over-period increase in the effective income tax rate is due to the effects of rate-regulated accounting for income taxes, a state apportionment income tax rate change benefit in the prior period due to the EOG Acquisition, partially offset by higher US Investment Tax Credits, relative to higher earnings.

11. OTHER INCOME/(EXPENSE)


	Three months ended March 31,
	2025	2024
(millions of Canadian dollars)

Realized foreign currency gain/(loss)	(182)	122
Unrealized foreign currency gain/(loss)	55	(858)
Net defined pension and OPEB credit	72	41
Other	175	144
	120	(551)

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 cases, 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.

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, 2024.

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

GAS TRANSMISSION RATE PROCEEDINGS

Algonquin

Algonquin Gas Transmission, LLC (Algonquin) filed a rate case on May 30, 2024 and a settlement in principle was reached with customers in December 2024.  A Stipulation and Agreement was approved by the Federal Energy Regulatory Commission (FERC) on April 25, 2025 with rates effective December 1, 2024.

Maritimes & Northeast Pipeline

Maritimes & Northeast Pipeline (M&N) US filed a rate case on May 30, 2024 and a settlement in principle was reached with customers in December 2024.  A Stipulation and Agreement was approved by the FERC on April 25, 2025 with rates effective January 1, 2025.

GAS DISTRIBUTION AND STORAGE RATE APPLICATIONS

Enbridge Gas Ontario

In October 2022, Enbridge Gas Inc. (Enbridge Gas Ontario) 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) was established with the OEB in 2023. Phase 3 will address cost allocation and the harmonization of rates and rate classes and is anticipated to be completed in 2025.

In December 2023, the OEB issued its Decision and Order on Phase 1 (Phase 1 Decision). Enbridge Gas Ontario filed a motion requesting the OEB review and vary the Phase 1 Decision with respect to two aspects: asset class average useful lives for depreciation purposes and the recoverability of integration capital. In October 2024, the OEB issued a decision on Enbridge Gas Ontario's motion and determined that only the issue of integration capital met the threshold to warrant a review. In April 2025 the OEB issued a decision denying Enbridge Gas Ontario's motion to vary the Phase 1 Decision which had disallowed recoverability of undepreciated integration capital. In January 2024, Enbridge Gas Ontario also filed a Notice of Appeal with the Ontario Divisional Court regarding various aspects of the Phase 1 Decision, followed by its written submissions in March 2025. The OEB and any other intervening parties have 60 days to file their responding factums, after which the Ontario Divisional Court will schedule an oral hearing.

In November 2024, the OEB issued its Decision approving the Phase 2 Partial Settlement Proposal (Phase 2 Settlement). The Phase 2 Settlement establishes a price cap IR rate setting mechanism to be used for determining rates for 2025-2028. The price cap mechanism includes the continuation and establishment of certain deferral and variance accounts, as well as an earnings sharing mechanism that requires Enbridge Gas Ontario to share equally with customers any earnings in excess of 100 basis points over the allowed return on equity (ROE), and 90% of any earnings in excess of 300 basis points over the allowed ROE. Issues not addressed as part of the Phase 2 Settlement proceeded to hearing in December 2024 and a decision is expected in the second quarter of 2025.

In March 2025, the OEB released its decision in the Generic Cost of Capital proceeding. The OEB determined that Enbridge Gas Ontario’s equity thickness would remain at 38% as approved in the Phase 1 Rebasing decision. The OEB also revised the formula for calculating ROE by reducing flotation costs by 25 basis points. The new formula will be implemented at the next rebasing proceeding.

Enbridge Gas Ohio

In October 2023, Enbridge Gas Ohio filed its base rate case and schedules with the Ohio Commission. Enbridge Gas Ohio proposed a non-fuel, base rate annual revenue increase of $212 million, projected to be effective January 2025. The base rate increase was proposed to recover the significant investment in distribution infrastructure for the benefit of Ohio customers. The proposed rates would have provided for an ROE of 10.40% compared to the currently authorized ROE of 10.38%. In addition, Enbridge Gas Ohio requested approval for an alternative rate plan for the continuation and modification of certain programs, including Pipeline Infrastructure Replacement and Capital Expenditure Program. On December 18, 2024, Enbridge Gas Ohio filed a Notice of Intent to Modify Filed Positions. The Notice of Intent indicated a willingness to accept a reduced annual revenue requirement increase (from $212 million to $60 million) and, if the reduced position were adopted, to forgo filing a new base rate case until October 31, 2027. The hearing began on January 13, 2025 and was completed in February 2025. Enbridge Gas Ohio filed initial briefs on March 26, 2025 and reply briefs were filed on April 30, 2025. An order is expected in the third quarter of 2025.

Enbridge Gas North Carolina

On April 1, 2025, Enbridge Gas North Carolina filed its first rate review and adjustment since 2021 with the North Carolina Utilities Commission. This rate case aims to reflect the costs of delivering natural gas to customers and recover investments in infrastructure to support service reliability and customer growth. Enbridge Gas North Carolina is proposing a 12% increase to its residential natural gas rates.

Enbridge Gas Utah

On May 1, 2025, Enbridge Gas Utah filed its first rate review and adjustment since 2022 with the Utah Public Service Commission. This rate case aims to reflect the costs of delivering natural gas to customers and recover investments in infrastructure to support service reliability and customer growth. Enbridge Gas Utah is proposing a 9.5% increase to its residential natural gas rates.

FINANCING UPDATE

On February 25, 2025, Enbridge Pipelines Inc. redeemed below par all of the outstanding $100 million 4.10% medium-term notes that carried an original maturity date in July 2112.

In February 2025, we closed a five-tranche offering consisting of three-year floating medium-term notes, three-year medium-term notes, five-year medium-term notes, 10-year medium-term notes, and re-opened existing 30-year medium-term notes for an aggregate principal amount of $2.8 billion, which mature in February 2028, February 2028, February 2030, February 2035, and August 2054, respectively.

These financing activities, in combination with the financing activities executed in 2024, provide significant liquidity that we expect will enable us to fund our current portfolio of capital projects and other operating working capital requirements without requiring access to the capital markets for the next 12 months, should market access be restricted or pricing be unattractive. Refer to Liquidity and Capital Resources.

As at March 31, 2025, after adjusting for the impact of floating-to-fixed interest rate swap hedges, approximately 8% 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.

RESULTS OF OPERATIONS


	Three months ended March 31,
	2025	2024
(millions of Canadian dollars, except per share amounts)
Segment earnings/(loss) before interest, income taxes and depreciation and amortization1
Liquids Pipelines	2,593	2,404
Gas Transmission	1,473	1,265
Gas Distribution and Storage	1,600	765
Renewable Power Generation	223	257
Eliminations and Other	40	(642)
Earnings before interest, income taxes and depreciation and amortization1	5,929	4,049
Depreciation and amortization	(1,408)	(1,193)
Interest expense	(1,334)	(905)
Income tax expense	(697)	(386)
Earnings attributable to noncontrolling interests	(126)	(53)
Preference share dividends	(103)	(93)
Earnings attributable to common shareholders	2,261	1,419
Earnings per common share attributable to common shareholders	1.04	0.67
Diluted earnings per common share attributable to common shareholders	1.03	0.67

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

EARNINGS ATTRIBUTABLE TO COMMON SHAREHOLDERS

Three months ended March 31, 2025, compared with the three months ended March 31, 2024

Earnings attributable to common shareholders were positively impacted by $554 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 $17 million ($13 million after-tax) in 2025, compared with a net unrealized loss of $677 million ($518 million after-tax) in 2024, reflecting changes in the mark-to-market value of derivative financial instruments used to manage foreign exchange, interest rate and commodity price risks;

•the absence in 2025 of severance costs of $105 million ($79 million after-tax) as a result of a workforce reduction in February 2024;

•equity investment income of $87 million ($65 million after-tax) from our investment in DCP Midstream, LP (DCP), as a result of DCP's disposition of certain pipeline assets; and

•a $27 million gain ($25 million after-tax) on disposition of our interest in the East-West Tie Limited Partnership (East-West Tie); partially offset by

•a $139 million realized loss and a $105 million unrealized gain (together resulted in a $26 million loss after-tax) from a hedge settlement in our Renewable Power Generation segment. Earnings attributable to noncontrolling interests of $72 million ($55 million after-tax) was recognized as a result of accounting for the settlement under the hypothetical liquidation at book value method.

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 $288 million increase in earnings attributable to common shareholders is primarily explained by:

•contributions from Enbridge Gas Ohio, Enbridge Gas Utah, and Enbridge Gas North Carolina in our Gas Distribution and Storage segment;

•positive earnings impact in Enbridge Gas Ontario due to colder weather in 2025 compared to a negative impact in 2024 in our Gas Distribution and Storage segment;

•higher contributions from our Liquids Pipelines segment due to stronger Mainline and Line 9 performance and higher equity earnings due to a litigation settlement;

•higher contributions from our Gas Transmission segment primarily due to favorable contracting in our US Gas Transmission assets, and the recognition of increased revenue attributable to Algonquin and Texas Eastern rate case settlements; and

•the favorable effect of translating US dollar earnings at a higher average exchange rate in 2025, compared to the same period in 2024.

The factors above were partially offset by:

•higher interest expense primarily due to higher average debt balances principal outstanding;

•higher depreciation and amortization expense mainly driven by a full quarter ownership of the Gas Utilities;

•higher income tax expense driven by higher earnings;

•higher realized foreign exchange losses on hedge settlements in Eliminations and Other;

•the absence of contributions from Alliance Pipeline and Aux Sable in our Gas Transmission segment due to the sale of our interests in these investments in April 2024; and

•lower contributions from the Gulf Coast and Mid-Continent System in our Liquids Pipelines segment due to lower volumes on the Flanagan South and Spearhead Pipelines.

BUSINESS SEGMENTS

LIQUIDS PIPELINES


	Three months ended March 31,
	2025	2024
(millions of Canadian dollars)
Earnings before interest, income taxes and depreciation and amortization	2,593	2,404

Three months ended March 31, 2025, compared with the three months ended March 31, 2024

EBITDA was positively impacted by $28 million due to certain infrequent or other non-operating factors, primarily explained by a non-cash, net unrealized gain of $6 million in 2025, compared with a net unrealized loss of $35 million in 2024, reflecting changes in the mark-to-market value of derivative financial instruments used to manage commodity price risks.

After taking into consideration the factors above, the remaining $161 million increase is primarily explained by the following significant business factors:

•higher Mainline and Line 9 contributions due to higher throughput;

•equity earnings attributable to a litigation settlement; and

•the favorable effect of translating US dollar earnings at a higher average exchange rate in 2025, compared to the same period in 2024; partially offset by

•lower contributions from the Gulf Coast and Mid-Continent System due to lower volumes on the Flanagan South Pipeline and Spearhead Pipeline.

GAS TRANSMISSION


	Three months ended March 31,
	2025	2024
(millions of Canadian dollars)
Earnings before interest, income taxes and depreciation and amortization	1,473	1,265

Three months ended March 31, 2025, compared with the three months ended March 31, 2024

EBITDA was positively impacted by $43 million due to certain infrequent or other non-operating factors, primarily explained by:

•equity earnings of $87 million from our investment in DCP, as a result of DCP's gain on disposition from certain pipeline assets; partially offset by

•a non-cash, net unrealized loss of $61 million in 2025, compared with a net unrealized loss of $17 million in 2024, reflecting net fair value gains and losses arising from changes in the mark-to-market value of derivative financial instruments used to manage commodity price risks.

The remaining $165 million increase is primarily explained by the following significant business factors:

•favorable contracting on our US Gas Transmission assets;

•the recognition of increased revenues attributable to the Algonquin and Texas Eastern rate case settlements;

•contributions from the acquisitions of an interest in the Whistler Parent JV with WhiteWater/I Squared Capital and MPLX LP and in the Delaware Basin Residue in the second and fourth quarters of 2024, respectively, and from the Texas Eastern Venice Extension project since service commencement in late 2024; and

•the favorable effect of translating US dollar earnings at a higher average exchange rate in 2025, compared to the same period in 2024; partially offset by

•the absence of contributions from Alliance Pipeline and Aux Sable due to the sale of our interests in these investments in April 2024.

GAS DISTRIBUTION AND STORAGE


	Three months ended March 31,
	2025	2024
(millions of Canadian dollars)
Earnings before interest, income taxes and depreciation and amortization	1,600	765

Three months ended March 31, 2025, compared with the three months ended March 31, 2024

EBITDA was positively impacted by $835 million primarily due to the following significant business factors:

•full-quarter contributions from the Gas Utilities including Enbridge Gas Ohio, Enbridge Gas Utah and Enbridge Gas North Carolina;

•When compared with the normal forecast embedded in rates, the positive impact of weather on EBITDA for Enbridge Gas Ontario was approximately $9 million in 2025 compared to a negative impact of approximately $78 million in the same period of 2024; and

•higher distribution charges resulting from increases in rates and customer base at Enbridge Gas Ontario.

RENEWABLE POWER GENERATION


	Three months ended March 31,
	2025	2024
(millions of Canadian dollars)
Earnings before interest, income taxes and depreciation and amortization	223	257

Three months ended March 31, 2025, compared with the three months ended March 31, 2024

EBITDA was positively impacted by $4 million due to certain infrequent or other non-operating factors, primarily explained by:

•a $27 million gain on the disposition of our interest in East-West Tie; partially offset by

•a realized loss of $139 million, partially offset by a non-cash, net unrealized gain of $105 million in 2025, compared with a net unrealized loss of $11 million in 2024, reflecting changes in the mark-to-market value of derivative financial instruments used to manage foreign exchange and commodity price risks.

The remaining $38 million decrease is primarily explained by:

•weaker wind resources at European offshore wind facilities; partially offset by

•stronger wind resources at North American wind facilities.

ELIMINATIONS AND OTHER


	Three months ended March 31,
	2025	2024
(millions of Canadian dollars)
Earnings/(loss) before interest, income taxes and depreciation and amortization	40	(642)

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, 2025, compared with the three months ended March 31, 2024

EBITDA was positively impacted by $931 million, primarily due to certain infrequent or non-operating factors, explained by:

•a non-cash, net unrealized gain of $109 million in 2025, compared with a net unrealized loss of $722 million in 2024, reflecting changes in the mark-to-market value of derivative financial instruments used to manage foreign exchange and commodity price risk; and

•the absence in 2025 of severance costs of $105 million as a result of workforce reduction in February 2024.

After taking into consideration the non-operating factors above, we saw a $249 million decrease in EBITDA that is primarily explained by:

•higher realized foreign exchange losses on hedge settlements in 2025; and

•lower investment income in 2025 compared to 2024 from investing cash sources from the pre-funding of the Acquisitions.

GROWTH PROJECTS - COMMERCIALLY SECURED PROJECTS

The following table summarizes the status of our material 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 Modernization	100	%	US$0.4 billion	US$162 million	Under construction	2025 - 2026
2.	T-North Expansion (Aspen Point)	100	%	$1.2 billion	$325 million	Under construction	2026

3.	Tennessee Ridgeline Expansion	100	%	US$1.1 billion	US$237 million	Pre-construction	2026

4.	Woodfibre LNG3	30	%	US$1.5 billion	US$699 million	Under construction	2027
5.	T-South Expansion (Sunrise)	100	%	$4.0 billion	$235 million	Pre-construction	2028
6.	T-North Expansion (Birch Grove)	100	%	$0.4 billion	No significant expenditures to date	Pre-construction	2028
7.	Canyon System Pipelines	100	%	US$0.7 billion	US$6 million	Pre-construction	2029


GAS DISTRIBUTION AND STORAGE
8.	Moriah Energy Center4	100	%	US$0.6 billion	US$252 million	Under construction	2027
9.	T-15 Reliability Project4,5	100	%	US$0.7 billion	US$15 million	Pre-construction	2027 - 2028
RENEWABLE POWER GENERATION

10.	Sequoia Solar	100	%	US$1.1 billion	US$469 million	Various stages	2025 - 2026
11.	Calvados Offshore Wind6	21.7	%	$1.0 billion	$426 million	Under construction	2027
				(€0.6 billion)	(€294 million)

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

2Expenditures to date and status of the project are determined as at March 31, 2025.

3Our equity contribution is approximately US$0.9 billion, with the remainder financed through non-recourse project level debt. Capital cost estimates will be updated in 2025, at which point Enbridge's preferred return will be set.

4Previously approved projects that were acquired by Enbridge through the acquisition of Public Service Company of North Carolina, Incorporated in the third quarter of 2024.

5Includes approved capital costs for the second phase of the project which involves installation of additional compression to add capacity and is expected to go into service in 2028.

6Our equity contribution is approximately $0.3 billion, with the remainder financed through non-recourse project level debt.

A full description of each of our material projects is provided in our annual report on Form 10-K for the year ended December 31, 2024. Significant updates that have occurred since the date of filing of our Form 10-K are discussed below.

GAS TRANSMISSION

•T-North Expansion (Birch Grove) - An expansion of our British Columbia (BC) Pipeline in northern BC that includes pipeline looping and ancillary station modifications to support 178 million cubic feet per day of additional capacity. The project is underpinned by a cost-of-service commercial model with a target in-service date in the third quarter of 2028. This expansion is driven by the need for natural gas producers in northeastern BC to access markets for their growing production, mainly from the prolific Montney formation.

OTHER ANNOUNCED PROJECTS UNDER DEVELOPMENT

LIQUIDS PIPELINES

Mainline System Capital Investments

On March 4, 2025, we announced plans to invest up to $2.0 billion in our Mainline System through 2028. These investments are expected to earn a return through the Mainline Tolling Settlement and will be focused on extending the service life of the underlying assets, as well as further enhancing reliability and efficiency given continuing demands on the system.

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 $3.1 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 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 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, 2025:


	Maturity1	Total Facilities	Draws2	Available
(millions of Canadian dollars)
Enbridge Inc.	2025-2049	8,874	6,379	2,495
Enbridge (U.S.) Inc.	2026-2029	10,822	5,144	5,678
Enbridge Pipelines Inc.	2026	2,000	540	1,460
Enbridge Gas Inc.	2026	2,500	860	1,640
Total committed credit facilities		24,196	12,923	11,273

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.

As at March 31, 2025, our net available liquidity totaled $13.4 billion (December 31, 2024 - $14.4 billion), consisting of available credit facilities of $11.3 billion (December 31, 2024 - $12.6 billion) and unrestricted cash and cash equivalents of $2.1 billion (December 31, 2024 - $1.8 billion) as reported in the Consolidated Statements of Financial Position.

LONG-TERM DEBT ISSUANCES

During the three months ended March 31, 2025, we completed the following long-term debt issuances totaling $2.8 billion:

Company

Issue Date

Principal Amount

(millions of Canadian dollars, unless otherwise stated)

Enbridge Inc.

February 2025

Floating rate medium-term notes due February 20281

$400

February 2025

3.55%

medium-term notes due February 2028

$300

February 2025

3.90%

medium-term notes due February 2030

$800

February 2025

4.56%

medium-term notes due February 2035

$700

February 2025

5.32%

medium-term notes due August 2054

$600

1Notes carry an interest rate set to equal the Canadian Overnight Repo Rate Average plus a margin of 85 basis points.

LONG-TERM DEBT REPAYMENTS

During the three months ended March 31, 2025, we completed the following long-term debt repayments totaling US$1.9 billion, and $0.1 billion:

Company

Repayment Date

Principal Amount

(millions of Canadian dollars, unless otherwise stated)

Enbridge Inc.

January 2025

2.50%

senior notes

US$500

February 2025

2.50%

senior notes

US$500

Enbridge Pipelines Inc.

February 2025

4.10%

medium-term notes1

$100

Spectra Energy Partners, LP

March 2025

3.50%

senior notes

US$500

Enbridge Holdings (Tomorrow RNG), LLC

January 2025

4.97%

senior notes

US$309

January 2025

4.97%

senior notes

US$85

January 2025

4.97%

senior notes

US$19

1The notes carried an original maturity date in July 2112.

Cash flow growth, 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 $126 million, as reported in 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, 2025 and December 31, 2024, we had positive and negative working capital positions of $0.1 billion and $2.9 billion, respectively. During the three months ended March 31, 2025, the major contributing factor to the positive working capital position was due to settlement of current liabilities, while during the year ended December 31, 2024, the major contributing factor to the negative working capital position was the current liabilities associated with our growth capital program.

SOURCES AND USES OF CASH


	Three months ended March 31,
		2025	2024
(millions of Canadian dollars)
Operating activities		3,053	3,151
Investing activities		(1,789)	(7,792)
Financing activities		(950)	(120)
Effect of translation of foreign denominated cash and cash equivalents and restricted cash		8	161
Net change in cash and cash equivalents and restricted cash		322	(4,600)

Significant sources and uses of cash for the three months ended March 31, 2025 and 2024 are summarized below:

Operating Activities

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, dispositions and changes in contributions to, and distributions from, our equity investments. The decrease in cash used in investing activities period-over-period was primarily due to the acquisitions of EOG and Tomorrow RNG in 2024, which were partially offset by an increase in capital expenditures in 2025.

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. Cash used in financing activities is also impacted by changes in distributions to, and contributions from, noncontrolling interests. Factors impacting the increase in cash used in financing activities period-over-period primarily include:

•lower net commercial paper and credit facility draws in 2025 when compared to net draws during the same period in 2024; and

•increased common share dividend payments in 2025 primarily due to the increase in our common share dividend rate and a higher number of common shares outstanding.

The factors above were partially offset by:

•lower long-term debt repayments and higher long-term debt issuances in 2025 when compared to the same period in 2024; and

•net draws of short-term borrowings in 2025 when compared to net payments during the same period in 2024.

SUMMARIZED FINANCIAL INFORMATION

On January 22, 2019, Enbridge entered into supplemental indentures with its wholly-owned subsidiaries, Spectra Energy Partners, LP (SEP) and Enbridge Energy Partners, L.P. (EEP) (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 Guarantees


SEP Notes1			EEP Notes2
3.38% Senior Notes due 2026			5.88% Notes due 2025
5.95% Senior Notes due 2043			5.95% Notes due 2033
4.50% Senior Notes due 2045			6.30% Notes due 2034
			7.50% Notes due 2038
			5.50% Notes due 2040
			7.38% Notes due 2045

1As at March 31, 2025, the aggregate outstanding principal amount of SEP notes was approximately US$1.7 billion.

2As at March 31, 2025, the aggregate outstanding principal amount of EEP notes was approximately US$2.4 billion.

Enbridge Notes under Guarantees


USD Denominated1			CAD Denominated2
4.25% Senior Notes due 2026			2.44% Senior Notes due 2025
1.60% Senior Notes due 2026			3.20% Senior Notes due 2027
5.90% Senior Notes due 2026			5.70% Senior Notes due 2027
3.70% Senior Notes due 2027			6.10% Senior Notes due 2028
5.25% Senior Notes due 2027			4.90% Senior Notes due 2028
6.00% Senior Notes due 2028			3.55% Senior Notes due 2028
3.13% Senior Notes due 2029			Floating Rate Senior Notes due 2028
5.30% Senior Notes due 2029			2.99% Senior Notes due 2029
6.20% Senior Notes due 2030			7.22% Senior Notes due 2030
2.50% Sustainability-Linked Senior Notes due 2033			4.21% Senior Notes due 2030
5.70% Sustainability-Linked Senior Notes due 2033			3.90% Senior Notes due 2030
5.63% Senior Notes due 2034			7.20% Senior Notes due 2032
4.50% Senior Notes due 2044			6.10% Sustainability-Linked Senior Notes due 2032
5.50% Senior Notes due 2046			3.10% Sustainability-Linked Senior Notes due 2033
4.00% Senior Notes due 2049			5.36% Sustainability-Linked Senior Notes due 2033
3.40% Senior Notes due 2051			4.73% Senior Notes due 2034
6.70% Senior Notes due 2053			5.57% Senior Notes due 2035
5.95% Senior Notes due 2054			4.56% Senior Notes due 2035
			5.75% Senior Notes due 2039
			5.12% Senior Notes due 2040
			4.24% Senior Notes due 2042
			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
			5.32% Senior Notes due 2054
			5.32% Senior Notes due 2054
			4.56% Senior Notes due 2064

1As at March 31, 2025, the aggregate outstanding principal amount of the Enbridge US dollar-denominated notes was approximately US$16.0 billion.

2As at March 31, 2025, the aggregate outstanding principal amount of the Enbridge Canadian dollar-denominated notes was approximately $15.1 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 SEP, EEP, and Enbridge.

Summarized Combined Statement of Earnings


Three months ended March 31,			2025
(millions of Canadian dollars)

Operating income			34
Loss			(32)
Loss attributable to common shareholders			(134)

Summarized Combined Statements of Financial Position


	March 31, 2025	December 31, 2024
(millions of Canadian dollars)
Cash and cash equivalents	2,170	2,000
Accounts receivable from affiliates	3,891	3,901
Short-term loans receivable from affiliates	4,062	3,892
Trade receivables and unbilled revenues	5	—
Other current assets	373	499
Long-term loans receivable from affiliates	47,111	54,416
Other long-term assets	2,071	2,139
Accounts payable to affiliates	2,335	2,252
Short-term loans payable to affiliates	1,481	1,188
Trade payables and accrued liabilities	353	661
Other current liabilities	3,721	8,047
Long-term loans payable to affiliates	31,187	36,576
Other long-term liabilities	65,869	62,642

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 Agreement Between the US and Canada Concerning Transit Pipelines, 28 U.S.T. 7449 (1977) (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 that his final ruling on all issues would be provided soon.

On June 26, 2023, the Court issued its Final Order ruling as follows: (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 Wisconsin Relocation Project 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. On December 12, 2023, the 7th Circuit Court of Appeals requested the US to file a brief in this appeal as amicus curiae to address the effect of 1977 Transit Pipelines Treaty, 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 2025.

In March 2025, after receiving authorizations from tribal, federal, and state agencies, an erosion mitigation project was successfully installed at the Meander.

MICHIGAN LINE 5 DUAL PIPELINES - STRAITS OF MACKINAC EASEMENT

Michigan Attorney General Lawsuit

In 2019, the Michigan Attorney General (AG) filed a complaint in the Michigan Ingham County Circuit Court (the Circuit Court) that requests the Circuit Court to declare the easement granted to Enbridge in 1953 for the operation of Line 5 in the Straits of Mackinac (the Straits) to be invalid and to prohibit continued operation of Line 5 in the Straits. On December 15, 2021, Enbridge removed the case to the US District Court in the Western District of Michigan (US District Court). The removal of the AG's case to federal court followed a November 16, 2021 ruling, which held that the similar (and now dismissed) 2020 lawsuit brought by the Governor of Michigan to force the shutdown of Line 5 raised important federal issues that should be heard in federal court. The AG subsequently filed various motions and appeals (opposed by Enbridge) to remand the case.

On June 17, 2024, the 6th Circuit Court of Appeals (6th Circuit) overturned the US District Court’s decision and remanded the AG's lawsuit against Enbridge back to the Circuit Court. On July 15, 2024, Enbridge filed a petition for rehearing, which was denied on August 16, 2024.

Oral argument took place before the Circuit Court judge on January 27, 2025, on cross motions for summary disposition which have been pending for almost four years. We anticipate a decision on the motions for summary disposition in 2025.

On January 13, 2025, Enbridge filed a petition for certiorari with the US Supreme Court. The petition asks the US Supreme Court to review and reverse the June 2024 decision of the 6th Circuit remanding to state court the Michigan AG’s lawsuit against Enbridge seeking to shut down Line 5.

The AG filed a response to Enbridge’s petition and a decision from the US Supreme Court on whether to grant the petition is anticipated by the third quarter of 2025.

On April 16, 2025, the US Army Corps of Engineers Detroit District issued notice that the Line 5 Tunnel Project was eligible for and will be reviewed under the emergency/special processing procedures.

Enbridge Lawsuit

On November 24, 2020, Enbridge filed in the US District Court a Complaint for Declaratory and Injunctive Relief requesting that the US District Court enjoin the State of Michigan Officials from taking any action to prevent or impede the operation of Line 5. The Government of Canada has filed a supplemental brief reiterating that the 1977 Transit Pipelines Treaty between the US and Canada has been invoked and that the matter is of great importance to Canada. This matter remains in federal court.

In January 2022, the State of Michigan Officials filed a motion to dismiss Enbridge's Complaint and Enbridge filed a motion for summary judgment. On July 5, 2024, the US District Court issued an Order denying the State of Michigan Officials' motion to dismiss Enbridge's Complaint, and the State of Michigan Officials filed for an immediate appeal to the 6th Circuit. On August 29, 2024, the US District Court issued an Order staying the case, pending the 6th Circuit’s decision. On April 23, 2025, the 6th Circuit affirmed the District Court’s denial of the Michigan Officials’ motion to dismiss the Enbridge’s Complaint on sovereign immunity grounds.

Oral argument was held on March 18, 2025, and a decision from the 6th Circuit is anticipated by the third quarter of 2025.

DAKOTA ACCESS PIPELINE

We own an effective interest of 27.6% in the Bakken Pipeline System, which is inclusive of the Dakota Access Pipeline (DAPL). The Standing Rock Sioux Tribe and the Cheyenne River Sioux Tribe filed lawsuits in 2016 with the US Court for the District of Columbia (the District Court) contesting the lawfulness of the Army Corps easement for DAPL, including the adequacy of the Army Corps' environmental review and tribal consultation process. The Oglala Sioux and Yankton Sioux Tribes also filed lawsuits alleging similar claims in 2018.

On June 14, 2017, the District Court found the Army Corps' environmental review to be deficient and ordered the Army Corps to conduct further study concerning spill risks from DAPL.

On March 25, 2020, in response to amended complaints from the Tribes, the District Court found that the Army Corps' subsequent environmental review completed in August 2018 was also deficient and ordered the Army Corps to prepare an Environmental Impact Statement (EIS) to address unresolved controversy pertaining to potential spill impacts resulting from DAPL. On July 6, 2020, the District Court issued an Order vacating the Army Corps' easement for DAPL and ordering that the pipeline be shut down by August 5, 2020. On that day, the US Court of Appeals for the District of Columbia Circuit stayed the District Court's July 6 order to shut down and empty the pipeline.

On January 26, 2021, the US Court of Appeals affirmed the District Court's decision, holding that the Army Corps is required to prepare an EIS and that the Army Corps' easement for DAPL is vacated. The US Supreme Court subsequently denied the request of Dakota Access, LLC to review the decision that an EIS is required. The US Court of Appeals also determined that, absent an injunction proceeding, the District Court could not order DAPL's operations to cease. While not an issue before, the US Court of Appeals also recognized that the Army Corps could consider whether to allow DAPL to continue to operate in the absence of an easement. The Army Corps earlier indicated that it did not intend to exercise its authority to bar DAPL's continued operation, notwithstanding the absence of an easement.

On September 8, 2023, the Army Corps issued its draft EIS, which assesses the impacts of DAPL under five alternative scenarios: denying the easement removing the pipeline; denying the easement and leaving the pipeline in place; granting the easement with the prior conditions (which allow for the ongoing operation, maintenance and ultimate removal of the pipeline and its related facilities); granting the easement with some new safety conditions; and rerouting the pipeline. The Army Corps did not identify a preferred alternative. The public comment period that commenced on the issuance of the draft EIS closed on December 13, 2023. The pipeline will remain operational while the environmental review process continues. The final EIS is expected to be issued in 2025.

On October 15, 2024, the Standing Rock Sioux Tribe filed a complaint in the District Court against the Army Corps, among others, seeking a permanent injunction prohibiting the continued operation of DAPL. The main allegations of the complaint are that the Army Corps is unlawfully permitting DAPL to continue to operate without an easement and without a determination under the National Environmental Policy Act, and that the Army Corps has failed to require that a compliant Facility Response Plan be submitted. Several of the claims are similar to those in the litigation described above. Dakota Access, LLC and 13 states have intervened in the case in support of the Army Corps and continued operation of DAPL. Dakota Access, LLC filed an answer to the complaint on December 19, 2024. On January 17, 2025, the defendants, Dakota Access LLC, and the 13 States filed motions to dismiss the Standing Rock Sioux Tribe’s complaint. Also on January 17, 2025, the Standing Rock Sioux Tribe filed a motion for partial summary judgment on its claims.

On March 28, 2025, the District Court granted the motion to dismiss the October 15, 2024 Complaint.

The Tribes have until May 29, 2025 to file an appeal.

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, 2024. 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, 2025, 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, 2025 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. We have no such proceedings to disclose in this quarterly report.

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, 2024, which could materially affect our financial condition or future results. There have been no material modifications to those risk factors, other than as set forth below.

The effects of US, Canadian and other governments' policies on tariffs and trade relations are uncertain and could significantly adversely impact our business, operations or financial results.

The announcement and imposition of tariffs by the US, together with potential, announced or implemented retaliatory tariffs by other governments on imports from the US, and other potential measures, including duties, fees, economic sanctions or other trade measures, as well as the potential impacts of these tariffs and trade measures, present significant risks to our business operations and financial results. Tariffs announced by the US (which are in addition to any pre-existing tariffs) include, among others:

•March 4, 2025: 25% tariff on Canadian goods exports and 10% on certain Canadian energy exports that are non-compliant under the United States-Mexico-Canada Agreement (USMCA);

•March 12, 2025: 25% tariff on Canadian steel and aluminum products; and

•April 2, 2025: 10% tariff on product imports from almost all countries and individualized higher tariffs on imports from dozens of countries.

Several of the US tariff announcements have been followed by announcements of limited exemptions and temporary pauses on implementation dates. In response to the US tariff announcements, certain governments have threatened or announced retaliatory measures against the US, including increased tariffs on US goods. For instance, effective March 13, 2025, the Canadian federal government imposed 25% tariffs on a list of products imported from the US. These announcements have led to significant uncertainty and market volatility during the first quarter of 2025. If maintained, such trade measures, the nature, extent and timing of which are uncertain, and the potential for escalation of trade disputes, including retaliatory measures, could lead to, among other things, worsening of macroeconomic conditions, inflationary pressures, increased construction costs, costs to maintain our assets and other costs and expenses, as well as to potential reductions in demand for Canadian energy. The measures also introduce uncertainty in North American energy and capital markets and have the potential to disrupt

supply chains and access to capital markets and jeopardize our competitiveness. Any of the foregoing could significantly adversely impact our business, operations or financial results.

The US Government has also stated its interest in renegotiating and altering the USMCA, which could further impact the energy market and our business.

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

None.

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

None.

ITEM 4. MINE SAFETY DISCLOSURES

Not applicable.

ITEM 5. OTHER INFORMATION

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
10.1*						Form of Enbridge Inc. 2019 Long Term Incentive Plan Stock Option Grant Notice and Stock Option Award Agreement (2025)
10.2*						Form of Enbridge Inc. 2019 Long Term Incentive Plan Performance Stock Unit Grant Notice and Performance Stock Unit Award Agreement (2025)
10.3*						Form of Enbridge Inc. 2019 Long Term Incentive Plan Restricted Stock Unit Grant Notice and Restricted Stock Unit Award Agreement (2025)
10.4*						Enbridge Inc. Directors’ Compensation Plan dated February 12, 2025, effective January 1, 2025
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 9, 2025	By:	/s/ Gregory L. Ebel
			Gregory L. Ebel
			President and Chief Executive Officer
			(Principal Executive Officer)

Date:	May 9, 2025	By:	/s/ Patrick R. Murray
			Patrick R. Murray
			Executive Vice President and Chief Financial Officer
			(Principal Financial Officer)