[10-Q] ENBRIDGE INC Quarterly Earnings Report

Rhea-AI Filing Summary

Enbridge Inc. filed its quarterly report for the period ended September 30, 2025. The filing outlines the company’s diversified operations across Liquids Pipelines, Gas Transmission, Gas Distribution and Storage, and Renewable Power Generation, and includes standard disclosures on market conditions, strategy, risk management, and hedge accounting.

The report references prior transactions and partnerships integral to the portfolio, including the acquisition of US gas utilities from Dominion Energy, the PSNC acquisition completed on September 30, 2024, and the Whistler joint venture formed in May 2024. Common shares outstanding were 2,181,275,613 as of October 31, 2025. Enbridge’s common shares trade on the New York Stock Exchange under the symbol ENB.

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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended September 30, 2025

OR

☐ 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 ☒ No ☐

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 ☒ No ☐

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. ☐

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

The registrant had 2,181,275,613 common shares outstanding as at October 31, 2025.

	PART I	PAGE
Item 1.	Financial Statements	6
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	43
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	63
Item 4.	Controls and Procedures	64
	PART II
Item 1.	Legal Proceedings	65
Item 1A.	Risk Factors	65
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	66
Item 3.	Defaults Upon Senior Securities	66
Item 4.	Mine Safety Disclosures	66
Item 5.	Other Information	66
Item 6.	Exhibits	66
	Signatures	67

2

GLOSSARY

"we", "our", "us" and "Enbridge"	Enbridge Inc.
AOCI	Accumulated other comprehensive income/(loss)
BC	British Columbia
EBITDA	Earnings before interest, income taxes and depreciation and amortization
EEP	Enbridge Energy Partners, L.P.
Enbridge Gas Ontario	Enbridge Gas Inc.
EOG	The East Ohio Gas Company
Exchange Act	United States Securities Exchange Act of 1934, as amended
IR	Incentive regulation
LNG	Liquefied natural gas
NCI	Noncontrolling interests
OCI	Other comprehensive income/(loss)
OEB	Ontario Energy Board
OPEB	Other postretirement benefit obligations
PSNC	Public Service Company of North Carolina, Incorporated
Questar	Questar Gas Company
RIN	Renewable identification number
RNG	Renewable natural gas
ROE	Return on Equity
SEP	Spectra Energy Partners, LP
the First Nations Partnership	Stonlasec8 Indigenous Investments Limited Partnership
the Guaranteed Enbridge Notes	Enbridge's outstanding guaranteed notes
the Ohio Commission	the Public Utilities Commission of Ohio
the Partnerships	Spectra Energy Partners, LP and Enbridge Energy Partners, L.P.
the PSNC Acquisition	Enbridge Inc.'s acquisition of all of the membership interests of Fall North Carolina Holdco LLC, which owns 100% of Public Service Company of North Carolina, Incorporated on September 30, 2024
the Whistler Parent JV	the joint venture formed by Enbridge Inc., WhiteWater/I Squared Capital and MPLX LP on May 29, 2024
Tomorrow RNG	Six Morrow Renewables operating landfill gas-to-renewable natural gas production facilities
US	United States of America
US Gas Utilities / the Acquisitions	Enbridge Inc.'s acquisitions of three US gas utilities from Dominion Energy, Inc.
VIE	Variable interest entities
Westcoast	Westcoast Energy Inc.
Westcoast LP	Westcoast Energy Limited Partnership
Wexpro	Wexpro Company and its consolidated subsidiaries

3

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 report 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, governance and sustainability 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 (US Gas Utilities) from Dominion Energy, Inc. (the Acquisitions); expected future actions of regulators and courts; government trade policies and potential impacts of potential and announced tariffs, duties, fees, economic sanctions, or other trade measures and the timing 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 US 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 impact 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

4

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; our ability to maintain adequate insurance in the future at commercially reasonable rates and terms; 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.

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PART I - FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

ENBRIDGE INC.

CONSOLIDATED STATEMENTS OF EARNINGS

	Three months ended September 30,						Nine months ended September 30,
	2025			2024			2025			2024
(unaudited; millions of Canadian dollars, except per share amounts)
Operating revenues
Commodity sales		8,396			8,986			26,069			18,422
Gas distribution sales		1,303			1,091			6,765			4,260
Transportation and other services		4,940			4,805			15,183			14,574
Total operating revenues (Note 3)		14,639			14,882			48,017			37,256
Operating expenses
Commodity costs		8,207			8,865			25,550			18,044
Gas distribution costs		280			201			2,444			1,504
Operating and administrative		2,483			2,281			7,264			6,723
Depreciation and amortization		1,398			1,317			4,197			3,783
Impairment of long-lived assets (Note 4)		—			—			330			—
Total operating expenses		12,368			12,664			39,785			30,054
Operating income		2,271			2,218			8,232			7,202
Income from equity investments		451			479			1,690			1,664
Gain on disposition of equity investments (Note 6)		—			—			—			1,091
Other income/(expense) (Note 14)		(297	)		376			1,192			(206	)
Interest expense		(1,262	)		(1,314	)		(3,777	)		(3,301	)
Earnings before income taxes		1,163			1,759			7,337			6,450
Income tax expense		(316	)		(312	)		(1,679	)		(1,437	)
Earnings		847			1,447			5,658			5,013
Earnings attributable to noncontrolling interests and redeemable noncontrolling interest		(59	)		(56	)		(227	)		(167	)
Earnings attributable to controlling interests		788			1,391			5,431			4,846
Preference share dividends		(106	)		(98	)		(311	)		(286	)
Earnings attributable to common shareholders		682			1,293			5,120			4,560
Earnings per common share attributable to common shareholders (Note 5)		0.30			0.59			2.34			2.12
Diluted earnings per common share attributable to common shareholders (Note 5)		0.30			0.59			2.33			2.12

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

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ENBRIDGE INC.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

	Three months ended September 30,						Nine months ended September 30,
	2025			2024			2025			2024
(unaudited; millions of Canadian dollars)
Earnings		847			1,447			5,658			5,013
Other comprehensive income/(loss), net of tax
Change in unrealized gain/(loss) on cash flow hedges		(9	)		(107	)		(23	)		21
Gain/(loss) on net investment hedges (Note 12)		(197	)		181			216			(357	)
Other comprehensive income from equity investees and other investments		5			2			26			3
Excluded components of fair value hedges		—			3			14			7
Reclassification to earnings of loss on cash flow hedges		8			9			22			18
Reclassification to earnings of pension and other postretirement benefits (OPEB) amounts		(7	)		(2	)		(20	)		(11	)
Reclassification of actuarial gain on pension and OPEB from regulatory assets		—			—			49			—
Foreign currency translation adjustments		1,329			(858	)		(2,086	)		1,527
Other comprehensive income/(loss), net of tax		1,129			(772	)		(1,802	)		1,208
Comprehensive income		1,976			675			3,856			6,221
Comprehensive income attributable to noncontrolling interests and redeemable noncontrolling interest		(80	)		(46	)		(188	)		(206	)
Comprehensive income attributable to controlling interests		1,896			629			3,668			6,015
Preference share dividends		(106	)		(98	)		(311	)		(286	)
Comprehensive income attributable to common shareholders		1,790			531			3,357			5,729

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

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ENBRIDGE INC.

CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY

	Three months ended September 30,						Nine months ended September 30,
	2025			2024			2025			2024
(unaudited; millions of Canadian dollars, except per share amounts)
Preference shares
Balance at beginning and end of period		6,818			6,818			6,818			6,818
Common shares
Balance at beginning of period		71,823			71,698			71,738			69,180
Shares issued, net of issue costs (Note 10)		—			—			—			2,489
Shares issued on exercise of stock options		13			9			59			14
Shares issued on vesting of restricted stock units (RSU), net of tax		—			—			39			24
Balance at end of period		71,836			71,707			71,836			71,707
Additional paid-in capital
Balance at beginning of period		226			272			275			268
Stock-based compensation		25			21			85			74
Stock options exercised		(11	)		(9	)		(51	)		(14	)
Vested RSUs		—			2			(69	)		(42	)
Balance at end of period		240			286			240			286
Deficit
Balance at beginning of period		(17,663	)		(15,794	)		(20,046	)		(17,115	)
Earnings attributable to controlling interests		788			1,391			5,431			4,846
Preference share dividends		(106	)		(98	)		(311	)		(286	)
Common share dividends declared		(2,055	)		(1,994	)		(4,110	)		(3,940	)
Redemption value adjustment attributable to redeemable noncontrolling interest (Note 9)		(28	)		—			(28	)		—
Balance at end of period		(19,064	)		(16,495	)		(19,064	)		(16,495	)
Accumulated other comprehensive income (Note 11)
Balance at beginning of period		4,244			4,234			7,115			2,303
Other comprehensive income/(loss) attributable to common shareholders, net of tax		1,108			(762	)		(1,763	)		1,169
Balance at end of period		5,352			3,472			5,352			3,472
Total Enbridge Inc. shareholders' equity		65,182			65,788			65,182			65,788
Noncontrolling interests
Balance at beginning of period		2,910			3,025			2,993			3,029
Earnings attributable to noncontrolling interests		43			56			211			167
Other comprehensive income/(loss) attributable to noncontrolling interests, net of tax
Change in unrealized gain/(loss) on cash flow hedges		—			2			(1	)		10
Foreign currency translation adjustments		21			(12	)		(38	)		29
		21			(10	)		(39	)		39
Comprehensive income attributable to noncontrolling interests		64			46			172			206
Distributions		(81	)		(79	)		(276	)		(246	)
Contributions		1			2			8			4
Purchase of noncontrolling interests		—			(2	)		—			(2	)
Other		—			(2	)		(3	)		(1	)
Balance at end of period		2,894			2,990			2,894			2,990
Total equity		68,076			68,778			68,076			68,778
Dividends paid per common share		0.94			0.92			2.82			2.76

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

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ENBRIDGE INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

	Nine months ended September 30,
	2025			2024
(unaudited; millions of Canadian dollars)
Operating activities
Earnings		5,658			5,013
Adjustments to reconcile earnings to net cash provided by operating activities:
Depreciation and amortization		4,197			3,783
Deferred income tax expense		944			743
Unrealized derivative fair value (gain)/loss, net		(997	)		809
Income from equity investments		(1,690	)		(1,664	)
Distributions from equity investments		1,547			1,499
Impairment of long-lived assets (Note 4)		330			—
Gain on disposition of equity investments		—			(1,091	)
Other		(91	)		198
Changes in operating assets and liabilities		(739	)		(352	)
Net cash provided by operating activities		9,159			8,938
Investing activities
Capital expenditures		(5,944	)		(4,165	)
Long-term, restricted and other investments		(1,867	)		(1,851	)
Distributions from equity investments in excess of cumulative earnings		531			646
Additions to intangible assets		(215	)		(157	)
Acquisitions		—			(13,065	)
Proceeds from disposition of equity investments		349			2,724
Affiliate loans, net		—			2
Other		(41	)		(49	)
Net cash used in investing activities		(7,187	)		(15,915	)
Financing activities
Net change in short-term borrowings		745			528
Net change in commercial paper and credit facility draws		788			3,276
Debenture and term note issues, net of issue costs		8,314			8,614
Debenture and term note repayments		(6,114	)		(5,615	)
Contributions from noncontrolling interests		8			4
Distributions to noncontrolling interests		(276	)		(246	)
Proceeds from investment by redeemable noncontrolling interest in subsidiary, net of transaction costs		712			—
Common shares issued, net of issue costs		8			2,485
Preference share dividends		(311	)		(286	)
Common share dividends		(6,164	)		(5,885	)
Net change in affiliate loans		39			99
Other		(41	)		(31	)
Net cash (used in)/provided by financing activities		(2,292	)		2,943
Effect of translation of foreign denominated cash and cash equivalents and restricted cash		(28	)		151
Net change in cash and cash equivalents and restricted cash		(348	)		(3,883	)
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		1,652			2,102

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

1 As at September 30, 2025 and December 31, 2024, long-term restricted cash of $141 million (September 30, 2024 - $94 million) and $105 million (December 31, 2023 - nil), respectively, was included in Restricted long-term investments and cash in the Consolidated Statements of Financial Position.

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ENBRIDGE INC.

CONSOLIDATED STATEMENTS OF FINANCIAL POSITION

	September 30, 2025			December 31, 2024
(unaudited; millions of Canadian dollars; number of shares in millions)
Assets
Current assets
Cash and cash equivalents		1,408			1,803
Restricted cash		103			92
Trade receivables and unbilled revenues		5,861			6,920
Other current assets		2,720			2,770
Accounts receivable from affiliates		84			90
Inventory		1,904			1,488
		12,080			13,163
Property, plant and equipment, net		130,946			131,104
Long-term investments		21,314			20,691
Restricted long-term investments and cash (Note 12)		1,245			998
Deferred amounts and other assets		10,738			11,034
Intangible assets, net		4,263			4,587
Goodwill		35,684			36,600
Deferred income taxes		703			796
Total assets		216,973			218,973
Liabilities and equity
Current liabilities
Short-term borrowings		1,274			529
Trade payables and accrued liabilities		6,516			7,060
Other current liabilities		4,192			7,241
Accounts payable to affiliates		22			22
Interest payable		1,204			1,231
Current portion of long-term debt		1,833			7,729
		15,041			23,812
Long-term debt		100,602			93,414
Other long-term liabilities		12,281			13,258
Deferred income taxes		20,237			19,596
		148,161			150,080
Contingencies (Note 15)
Redeemable noncontrolling interest (Note 9)		736			—
Equity
Share capital
Preference shares		6,818			6,818
Common shares (2,181 and 2,178 outstanding at September 30, 2025 and December 31, 2024, respectively)		71,836			71,738
Additional paid-in capital		240			275
Deficit		(19,064	)		(20,046	)
Accumulated other comprehensive income (Note 11)		5,352			7,115
Total Enbridge Inc. shareholders’ equity		65,182			65,900
Noncontrolling interests		2,894			2,993
		68,076			68,893
Total liabilities and equity		216,973			218,973

Variable Interest Entities (VIEs) (Note 7)

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

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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

The following policy became significant to Enbridge on July 2, 2025:

Noncontrolling Interests

Noncontrolling interests (NCI) represent ownership interests attributable to third parties in certain consolidated subsidiaries. The portion of equity not owned by us in such entities is reflected as NCI within the equity section of the Consolidated Statements of Financial Position and, in the case of Redeemable NCI, within the mezzanine equity section of the Consolidated Statements of Financial Position between long-term liabilities and equity.

Westcoast Energy Limited Partnership’s (Westcoast LP) Class A noncontrolling unitholder has the option, exercisable at any time from and after July 2, 2035, to require the Class B and Class C unitholders of Westcoast LP to redeem all of the Class A units for cash at the then-current fair value, subject to certain limitations. On a quarterly basis, the Redeemable NCI carrying amount is recognized at the higher of the amount resulting from the application of Accounting Standards Codification (ASC) 810 Consolidation and the estimated current redemption value, with measurement adjustments to the carrying amount of Redeemable NCI recognized in retained earnings. The measurement adjustments to Redeemable NCI that are recognized in retained earnings impact our earnings per common share (Note 5).

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.

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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 September 30, 2025	Liquids Pipelines			Gas Transmission			Gas Distribution and Storage			Renewable Power Generation			Eliminations and Other			Consolidated
(millions of Canadian dollars)
Transportation revenue		2,934			1,361			68			—			—			4,363
Storage and other revenue		77			158			122			—			—			357
Gas distribution sales		—			—			1,303			—			—			1,303
Electricity revenue		—			—			—			72			—			72
Commodity sales		—			32			22			—			—			54
Total revenue from contracts with customers		3,011			1,551			1,515			72			—			6,149
Commodity sales		8,101			23			—			—			218			8,342
Other revenue1,2		71			20			1			56			—			148
Intersegment revenue		—			3			(3	)		2			(2	)		—
Total revenue		11,183			1,597			1,513			130			216			14,639

Three months ended September 30, 2024	Liquids Pipelines			Gas Transmission			Gas Distribution and Storage			Renewable Power Generation			Eliminations and Other			Consolidated
(millions of Canadian dollars)
Transportation revenue3		2,906			1,264			58			—			—			4,228
Storage and other revenue		65			143			125			—			—			333
Gas distribution sales3		—			—			1,099			—			—			1,099
Electricity revenue		—			—			—			36			—			36
Commodity sales		—			37			—			—			—			37
Total revenue from contracts with customers		2,971			1,444			1,282			36			—			5,733
Commodity sales		8,725			10			—			—			214			8,949
Other revenue1,2		79			27			(2	)		96			—			200
Intersegment revenue		—			5			1			1			(7	)		—
Total revenue		11,775			1,486			1,281			133			207			14,882

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Nine months ended September 30, 2025	Liquids Pipelines			Gas Transmission			Gas Distribution and Storage			Renewable Power Generation			Eliminations and Other			Consolidated
(millions of Canadian dollars)
Transportation revenue		8,934			4,190			223			—			—			13,347
Storage and other revenue		220			493			431			—			—			1,144
Gas distribution sales		—			—			6,718			—			—			6,718
Electricity revenue		—			—			—			166			—			166
Commodity sales		—			84			22			—			—			106
Total revenue from contracts with customers		9,154			4,767			7,394			166			—			21,481
Commodity sales		24,822			89			—			—			1,052			25,963
Other revenue1,2		228			45			77			223			—			573
Intersegment revenue		—			15			14			6			(35	)		—
Total revenue		34,204			4,916			7,485			395			1,017			48,017

Nine months ended September 30, 2024	Liquids Pipelines			Gas Transmission			Gas Distribution and Storage			Renewable Power Generation			Eliminations and Other			Consolidated
(millions of Canadian dollars)
Transportation revenue3		8,916			3,895			193			—			—			13,004
Storage and other revenue		192			416			351			—			—			959
Gas distribution sales3		—			—			4,223			—			—			4,223
Electricity revenue		—			—			—			137			—			137
Commodity sales		—			115			—			—			—			115
Total revenue from contracts with customers		9,108			4,426			4,767			137			—			18,438
Commodity sales		17,494			62			—			—			751			18,307
Other revenue1,2		213			46			24			228			—			511
Intersegment revenue		—			16			5			5			(26	)		—
Total revenue		26,815			4,550			4,796			370			725			37,256

1Includes realized and unrealized gains and losses from our hedging program which for the three months ended September 30, 2025 were a net $13 million gain (2024 - $54 million gain) and for the nine months ended September 30, 2025 were a net $145 million gain (2024 - $15 million gain).

2Includes revenues from lease contracts for the three months ended September 30, 2025 and 2024 of $116 million and $125 million, respectively, and for the nine months ended September 30, 2025 and 2024 of $415 million and $407 million, respectively.

3These balances reflect a transfer from Transportation revenue to Gas distribution sales of $389 million and $1.1 billion for the three and nine months ended September 30, 2024, respectively.

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

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Contract Balances

	Contract Receivables			Contract Assets			Contract Liabilities
(millions of Canadian dollars)
Balance as at September 30, 2025		2,614			313			2,826
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 have been recognized in advance of payments received for performance obligations we have fulfilled (or have partially fulfilled) and prior to the point in time at which our right to payment is unconditional. Amounts included in contract assets are transferred to accounts receivable when our right to receive the consideration becomes unconditional.

Contract liabilities represent payments received for performance obligations which have not been fulfilled. Contract liabilities primarily relate to make-up rights and deferred revenues. Revenue recognized during the three and nine months ended September 30, 2025 included in contract liabilities at the beginning of the period were $91 million and $380 million, respectively. Increases in contract liabilities from cash received, net of amounts recognized as revenues, during the three and nine months ended September 30, 2025 were $224 million and $435 million, respectively.

Performance Obligations

There were no material revenues recognized in the three and nine months ended September 30, 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 $59.1 billion, of which $2.6 billion and $8.3 billion are expected to be recognized during the remaining three 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 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.

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Recognition and Measurement of Revenues

Three months ended September 30, 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		—			32			42			22			96
Revenues from products and services transferred over time1		3,011			1,519			1,473			50			6,053
Total revenue from contracts with customers		3,011			1,551			1,515			72			6,149

Three months ended September 30, 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		—			37			31			—			68
Revenues from products and services transferred over time1		2,971			1,407			1,251			36			5,665
Total revenue from contracts with customers		2,971			1,444			1,282			36			5,733

Nine months ended September 30, 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		—			84			109			38			231
Revenues from products and services transferred over time1		9,154			4,683			7,285			128			21,250
Total revenue from contracts with customers		9,154			4,767			7,394			166			21,481

Nine months ended September 30, 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		—			115			93			—			208
Revenues from products and services transferred over time1		9,108			4,311			4,674			137			18,230
Total revenue from contracts with customers		9,108			4,426			4,767			137			18,438

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 September 30, 2025	Liquids Pipelines			Gas Transmission			Gas Distribution and Storage			Renewable Power Generation			Total Reportable Segments
(millions of Canadian dollars)
Operating revenues1		11,183			1,597			1,513			130			14,423
Commodity and gas distribution costs		(8,032	)		(12	)		(284	)		(2	)		(8,330	)
Operating and administrative		(1,108	)		(571	)		(719	)		(87	)		(2,485	)
Income from equity investments		230			192			1			32			455
Other income		10			64			49			16			139
Earnings before interest, income taxes and depreciation and amortization		2,283			1,270			560			89			4,202
Eliminations and Other														(379	)
Depreciation and amortization														(1,398	)
Interest expense														(1,262	)
Earnings before income taxes														1,163

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Three months ended September 30, 2024	Liquids Pipelines			Gas Transmission			Gas Distribution and Storage			Renewable Power Generation			Total Reportable Segments
(millions of Canadian dollars)
Operating revenues1		11,775			1,486			1,281			133			14,675
Commodity and gas distribution costs		(8,624	)		(29	)		(203	)		2			(8,854	)
Operating and administrative		(1,104	)		(536	)		(579	)		(74	)		(2,293	)
Income from equity investments		261			182			—			39			482
Other income		17			43			23			2			85
Earnings before interest, income taxes and depreciation and amortization		2,325			1,146			522			102			4,095
Eliminations and Other														295
Depreciation and amortization														(1,317	)
Interest expense														(1,314	)
Earnings before income taxes														1,759

Nine months ended September 30, 2025	Liquids Pipelines			Gas Transmission			Gas Distribution and Storage			Renewable Power Generation			Total Reportable Segments
(millions of Canadian dollars)
Operating revenues1		34,204			4,916			7,485			395			47,000
Commodity and gas distribution costs		(24,623	)		(39	)		(2,471	)		2			(27,131	)
Operating and administrative		(3,268	)		(1,609	)		(2,179	)		(237	)		(7,293	)
Impairment of long-lived assets2		—			—			(330	)		—			(330	)
Income from equity investments		843			665			2			191			1,701
Other income		51			252			163			70			536
Earnings before interest, income taxes and depreciation and amortization		7,207			4,185			2,670			421			14,483
Eliminations and Other														828
Depreciation and amortization														(4,197	)
Interest expense														(3,777	)
Earnings before income taxes														7,337

Nine months ended September 30, 2024	Liquids Pipelines			Gas Transmission			Gas Distribution and Storage			Renewable Power Generation			Total Reportable Segments
(millions of Canadian dollars)
Operating revenues1		26,815			4,550			4,796			370			36,531
Commodity and gas distribution costs		(17,168	)		(117	)		(1,519	)		1			(18,803	)
Operating and administrative		(3,311	)		(1,701	)		(1,486	)		(214	)		(6,712	)
Income from equity investments		798			611			1			265			1,675
Gain on disposition of equity investments (Note 6)		—			1,063			—			28			1,091
Other income		45			100			62			47			254
Earnings before interest, income taxes and depreciation and amortization		7,179			4,506			1,854			497			14,036
Eliminations and Other														(502	)
Depreciation and amortization														(3,783	)
Interest expense														(3,301	)
Earnings before income taxes														6,450

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

2The Gas Distribution and Storage segment includes the impact of an impairment recognized for certain rate-regulated assets related to pension and other disallowances as a result of the Public Utilities Commission of Ohio's (Ohio Commission) June 2025 order related to Enbridge Gas Ohio's rate case.

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Capital Expenditures1

	Three months ended September 30,						Nine months ended September 30,
	2025			2024			2025			2024
(millions of Canadian dollars)
Liquids Pipelines		307			268			900			766
Gas Transmission		933			609			2,228			1,770
Gas Distribution and Storage		914			675			2,310			1,412
Renewable Power Generation		173			92			532			209
Eliminations and Other		20			8			71			59
		2,347			1,652			6,041			4,216

1Capital expenditures are cash basis plus equity component of the allowance for funds used during construction.

Property, Plant and Equipment

	September 30, 2025			December 31, 2024
(millions of Canadian dollars)
Liquids Pipelines		52,269			53,864
Gas Transmission		35,079			34,683
Gas Distribution and Storage		39,200			38,635
Renewable Power Generation		4,076			3,612
Eliminations and Other		322			310
		130,946			131,104

5. EARNINGS PER COMMON SHARE AND DIVIDENDS PER SHARE

NUMERATOR

The numerator used in calculating both basic and diluted earnings per share equals Earnings attributable to common shareholders per the Consolidated Statements of Earnings, less Redemption value adjustment attributable to redeemable NCI per the Consolidated Statements of Changes in Equity.

DENOMINATOR

The denominator of the basic earnings per common share calculation represents the weighted average number of common shares outstanding.

The denominator of the diluted earnings per common share calculation uses the treasury stock method 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. The basic weighted average shares outstanding are adjusted by this dilutive impact to derive the diluted weighted average shares outstanding.

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

	Three months ended September 30,						Nine months ended September 30,
	2025			2024			2025			2024
(number of shares in millions)
Weighted average shares outstanding		2,181			2,177			2,180			2,147
Effect of dilutive options and RSUs		6			3			6			3
Diluted weighted average shares outstanding		2,187			2,180			2,186			2,150

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For the three months ended September 30, 2024, 15.2 million of anti-dilutive stock options with a weighted average exercise price of $55.56 were excluded from the diluted earnings per common share calculation. There were no anti-dilutive stock options outstanding for the three months ended September 30, 2025.

For the nine months ended September 30, 2025 and 2024, 1.6 million and 18.7 million, respectively, of anti-dilutive stock options with a weighted average exercise price of $60.37 and $54.18, 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 December 1, 2025 to shareholders of record on November 14, 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	$0.32411
Preference Shares, Series H	$0.38200
Preference Shares, Series I2	$0.29980
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	$0.31601
Preference Shares, Series 5	US$0.41769
Preference Shares, Series 7	$0.37425
Preference Shares, Series 9	$0.35450
Preference Shares, Series 11	$0.34231
Preference Shares, Series 13	$0.33719
Preference Shares, Series 154	$0.35163
Preference Shares, Series 19	$0.38825

1The quarterly dividend per share paid on Preference Shares, Series G was decreased to $0.32411 from $0.32515 on September 1, 2025 due to the reset of the dividend on a quarterly basis.

2The quarterly dividend per share paid on Preference Shares, Series I was decreased to $0.29980 from $0.30058 on September 1, 2025 due to the reset of the dividend on a quarterly basis.

3The quarterly dividend per share paid on Preference Shares, Series 4 was decreased to $0.31601 from $0.31696 on September 1, 2025 due to the reset of the dividend on a quarterly basis.

4The quarterly dividend per share paid on Preference Shares, Series 15 was increased to $0.35163 from $0.18644 on September 1, 2025 due to the reset of the annual dividend on September 1, 2025.

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6. ACQUISITIONS AND DISPOSITIONS

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.

Public Service Company of North Carolina, Incorporated

On September 30, 2024, through a wholly-owned US subsidiary, we acquired all of the membership interests of Fall North Carolina Holdco LLC, which owns 100% of Public Service Company of North Carolina, Incorporated (PSNC), for cash consideration of $2.7 billion (US$2.0 billion) (the PSNC Acquisition). PSNC is a public utility primarily engaged in the purchase, sale, transportation and distribution of natural gas to residential, commercial and industrial customers in North Carolina. PSNC operates under rates approved by the North Carolina Utilities Commission. Subsequent to its acquisition, PSNC conducts business as Enbridge Gas North Carolina.

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

	September 30, 20241
(millions of Canadian dollars)
Fair value of net assets acquired:
Current assets (a)		303
Property, plant and equipment (b)		4,147
Long-term assets (c)		189
Current liabilities		277
Long-term debt (d)		1,529
Other long-term liabilities (e)		653
Deferred income tax liabilities		365
Goodwill (f)		895
Purchase price:
Cash		2,710

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

a)Current assets consist primarily of cash, trade and other accounts receivable, regulatory assets and inventory. The fair value of trade receivables from customers approximates their carrying value of $70 million due to the short period to maturity. A provision of $2 million for expected credit loss associated with accounts receivable has been recorded.

b)PSNC's property, plant and equipment constitutes an integrated system of rate-regulated natural gas transmission, 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 $114 million of regulatory assets expected to be recovered from customers in future periods through rates and equity interests in a liquefied natural gas (LNG) storage facility in North Carolina and in an intrastate natural gas pipeline.

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d)The fair value of long-term debt was determined based on the current underlying US Treasury interest rates on instruments of similar yield, credit risk and tenor, as well as an implied credit spread based on current market conditions. We recorded a fair value adjustment to reduce long-term debt by $156 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 PSNC 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 PSNC Acquisition, we began consolidating PSNC.

Our supplemental pro forma consolidated financial information for the three and nine months ended September 30, 2024, including the results of operations for PSNC as if the PSNC Acquisition had been completed on January 1, 2023, was as follows:

September 30, 2024	Three months ended			Nine months ended
(unaudited; millions of Canadian dollars)
Operating revenues		15,010			37,921
Earnings attributable to common shareholders		1,276			4,655

Questar Gas Company
On May 31, 2024, through a wholly-owned US subsidiary, we acquired all of the membership interests of Fall West Holdco LLC which owns 100% of Questar Gas Company (Questar) and its related Wexpro companies (Wexpro) for cash consideration of $4.1 billion (US$3.0 billion) (the Questar Acquisition). Questar is a public natural gas utility providing distribution, storage and transmission services to residential, commercial and industrial customers in Utah, southwestern Wyoming and southeastern Idaho. The Utah Public Service Commission, the Wyoming Public Service Commission and the Idaho Public Utilities Commission have granted Questar the necessary regulatory approvals to serve these areas. Wexpro develops and produces cost-of-service gas reserves for Questar and operates under agreements with the states of Utah and Wyoming. Subsequent to its acquisition, Questar conducts business as Enbridge Gas Utah, Enbridge Gas Wyoming and Enbridge Gas Idaho in those respective states.

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

	May 31, 20241
(millions of Canadian dollars)
Fair value of net assets acquired:
Current assets (a)		380
Property, plant and equipment (b)		6,013
Long-term assets (c)		163
Current liabilities		416
Long-term debt (d)		1,343
Other long-term liabilities (e)		919
Deferred income tax liabilities		527
Goodwill (f)		793
Purchase price:
Cash		4,144

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

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a)Current assets consist primarily of cash, trade and other accounts receivable and inventory. The fair value of trade receivables from customers approximates their carrying value of $202 million due to the short period to maturity. A provision of $9 million for expected credit loss associated with accounts receivable has been recorded.

b)Questar's property, plant and equipment constitutes an integrated system of rate-regulated natural gas transmission, distribution and storage assets. Wexpro's property, plant and equipment consists of cost-of-service gas and oil properties developed and produced for Questar. 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 funds collected from Questar by Wexpro and held in trust to fund future asset retirement obligations (ARO), as well as regulatory assets expected to be recovered from customers in future periods through rates.

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 $301 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, as well as ARO. The fair value of the ARO liability was determined using a discounted cash flow approach.

f)Goodwill is primarily attributable to the existing assembled assets and workforce of Questar and Wexpro 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 Questar Acquisition, we began consolidating Questar and Wexpro. For the period beginning May 31, 2024 through to September 30, 2024, operating revenues and earnings attributable to common shareholders generated by Questar and Wexpro were immaterial.

Our supplemental pro forma consolidated financial information for the three and nine months ended September 30, 2024, including the results of operations for Questar and Wexpro as if the Questar Acquisition had been completed on January 1, 2023, was as follows:

September 30, 2024	Three months ended			Nine months ended
(unaudited; millions of Canadian dollars)
Operating revenues		14,882			38,471
Earnings attributable to common shareholders		1,293			4,695

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 Ohio Commission. Subsequent to its acquisition, EOG conducts business as Enbridge Gas Ohio.

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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

1In 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 September 30, 2024, EOG generated $751 million of operating revenues and $170 million of earnings attributable to common shareholders.

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Our supplemental pro forma consolidated financial information for the three and nine months ended September 30, 2024, including the results of operations for EOG as if the EOG Acquisition had been completed on January 1, 2023, was as follows:

September 30, 2024	Three months ended			Nine months ended
(unaudited; millions of Canadian dollars)
Operating revenues		14,882			37,568
Earnings attributable to common shareholders		1,296			4,614

The PSNC Acquisition, Questar Acquisition and EOG Acquisition (together, the Acquisitions) further diversify, and are complementary to, our existing gas distribution operations.

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.

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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 September 30, 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 and nine months ended September 30, 2024, as if the RNG Facilities Acquisition had been completed on January 1, 2023, was also immaterial.

NONCONTROLLING INTEREST INVESTMENT

Westcoast Energy Limited Partnership

On July 1, 2025, Westcoast Energy Inc. (Westcoast) completed a reorganization in which substantially all of the property and assets relating to the British Columbia (BC) Pipeline system were transferred to a newly formed partnership, Westcoast LP. On July 2, 2025, Stonlasec8 Indigenous Investments Limited Partnership (the First Nations Partnership) invested approximately $736 million to subscribe for all of the Class A units of Westcoast LP, resulting in a 12.5% interest in the partnership. The cash consideration of $736 million and a respective Redeemable NCI based on the consideration received less transaction costs were recorded in the Consolidated Statements of Financial Position on close, to reflect the interest held by the First Nations Partnership. Subsequent to the First Nations Partnership's investment, we hold an 87.5% controlling interest in Westcoast LP and continue to manage and operate the BC Pipeline system. Refer to Note 7 - Variable Interest Entities and Note 9 - Redeemable Noncontrolling Interest.

DISPOSITION

Disposition of Alliance Pipeline and Aux Sable Interests

On April 1, 2024, we closed the sale of our 50.0% interest in the Alliance Pipeline, our interest in Aux Sable (including a 42.7% interest in Aux Sable Midstream LLC and Aux Sable Liquid Products L.P., and a 50.0% interest in Aux Sable Canada LP) and our interest in NRGreen Power Limited Partnership (NRGreen) to Pembina Pipeline Corporation for $3.1 billion, including $327 million of non-recourse debt. A gain on disposal of $1.1 billion before tax, which is net of $1.0 billion of the goodwill from our Gas Transmission segment allocated to the disposal group, is included in Gain on disposition of equity investments in the Consolidated Statements of Earnings for the nine months ended September 30, 2024. Our equity investments in the Alliance Pipeline and Aux Sable were previously included in our Gas Transmission segment. Our equity investment in NRGreen was previously included in our Renewable Power Generation segment.

EQUITY INVESTMENT TRANSACTIONS

Joint Venture with WhiteWater/I Squared and MPLX

On May 29, 2024, we formed a joint venture (the Whistler Parent JV) with WhiteWater/I Squared Capital (WhiteWater/I Squared) and MPLX LP (MPLX) that plans to develop, construct, own and operate natural gas pipeline and storage assets connecting Permian Basin natural gas supply to growing LNG and other US Gulf Coast demand. The Whistler Parent JV is owned by WhiteWater/I Squared (50.6%), MPLX (30.4%) and Enbridge (19.0%) and is accounted for as an equity method investment.

In connection with the formation of the Whistler Parent JV, we contributed our 100% interest in the Rio Bravo Pipeline project and $487 million (US$357 million) of cash to the Whistler Parent JV. In addition to our 19.0% equity interest in the Whistler Parent JV, we received a special equity interest in the Whistler Parent JV which provides for a 25.0% economic interest in the Rio Bravo Pipeline project. This interest is subject to certain redemption rights held by the Whistler Parent JV, which was redeemed on July 17, 2025 for net proceeds of $180 million (US$130 million). After the closing on May 29, 2024, we accrued for our share of the post-closing mandatory capital expenditures of approximately US$150 million for the Rio Bravo Pipeline project.

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The contribution of our interest in the Rio Bravo Pipeline project to the Whistler Parent JV in exchange for the equity interests discussed above represents a non-cash transaction in Cash Flows from Investing Activities and does not have an effect on our Consolidated Statements of Cash Flows. This component of the transaction resulted in a reduction of $321 million (US$235 million) to Property, plant and equipment, net and a corresponding increase to Long-term investments in the Consolidated Statements of Financial Position. The cash component of the transaction, as well as subsequent cash payments made for post-closing mandatory capital expenditures, have been reflected as contributions in Cash Flows from Investing Activities.

7. VARIABLE INTEREST ENTITIES

CONSOLIDATED VARIABLE INTEREST ENTITIES

Our consolidated VIEs consist of legal entities of which we are the primary beneficiary. We are the primary beneficiary when our variable interest(s) provide(s) us with (i) the power to direct the activities of the VIE that most significantly impact the entity's economic performance and (ii) the obligation to absorb losses, or the right to receive benefits, from the VIE that could potentially be significant to the VIE. We determine whether we are the primary beneficiary of a VIE by considering qualitative and quantitative factors, including, but not limited to: decision-making responsibilities, the VIE capital structure, risk and reward sharing, contractual agreements with the VIE, voting rights and level of involvement of other parties.

Westcoast Energy Limited Partnership

Westcoast LP is a BC limited partnership which holds and operates our Westcoast BC Pipeline system, serving customers in western Canada and the US Pacific Northwest. The limited partners, Westcoast and the First Nations Partnership, hold 87.49% and 12.5% interests in Westcoast LP, respectively. The remaining 0.01% general partner interest is held by Westcoast Energy GP Inc., a wholly-owned subsidiary.

Westcoast LP is considered a VIE as its limited partners lack substantive participating rights and kick-out rights. In addition to having the obligation to absorb losses and the right to expected returns, we, through Westcoast’s direct interests and the operating agreement between Westcoast and Westcoast LP, have the ability to direct the activities of Westcoast LP's principal operations, thereby making us the primary beneficiary of the VIE.

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The following table includes assets only to be used to settle the liabilities of Westcoast LP. The
creditors of the liabilities of Westcoast LP do not have recourse to us as the primary beneficiary. These assets and liabilities are included in the Consolidated Statements of Financial Position.

September 30,	2025
(millions of Canadian dollars)
Assets
Current assets
Cash and cash equivalents		152
Restricted cash		1
Trade receivables and unbilled revenues		68
Other current assets		35
Inventory		31
		287
Property, plant and equipment, net		5,571
Restricted long-term investments and cash		140
Deferred amounts and other assets		108
Intangible assets, net		11
		6,117
Liabilities
Current liabilities
Trade payables and accrued liabilities		119
Other current liabilities		50
		169
Other long-term liabilities		139
Deferred income taxes		2
		310
		5,807

On July 2, 2025, we entered into a credit agreement with Westcoast LP, pursuant to which we provided a one-year non-revolving term credit facility of up to $100 million. As at September 30, 2025, there have been no drawdowns on the credit facility. We did not provide any other financial support to Westcoast LP during the period ended September 30, 2025.

8. DEBT

CREDIT FACILITIES

The following table provides details of our committed credit facilities as at September 30, 2025:

	Maturity1	Total Facilities			Draws2			Available
(millions of Canadian dollars)
Enbridge Inc.	2027-2049		8,039			6,831			1,208
Enbridge (U.S.) Inc.	2027-2030		10,461			3,782			6,679
Enbridge Pipelines Inc.	2027		2,000			1,089			911
Enbridge Gas Inc.	2027		2,500			1,275			1,225
Total committed credit facilities			23,000			12,977			10,023

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

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

In July 2025, we renewed approximately $8.8 billion of our 364-day extendible credit facilities, extending the maturity dates to July 2027, which includes a one-year term out provision from July 2026. We also renewed approximately $7.8 billion of our five-year credit facilities, extending the maturity dates to July 2030. Further, we extended the maturity dates of our three-year credit facilities to July 2028.

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In July 2025, Enbridge Gas Inc. (Enbridge Gas Ontario) and Enbridge Pipelines Inc. extended the maturity dates of their $2.5 billion and $2.0 billion 364-day extendible credit facilities, respectively, to July 2027, which includes one-year term out provisions from July 2026.

In addition to the committed credit facilities noted above, we maintain $1.6 billion of uncommitted demand letter of credit facilities, of which $994 million was unutilized as at September 30, 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 2027 to 2049.

As at September 30, 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 $11.7 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 nine months ended September 30, 2025, we completed the following long-term debt issuances totaling $4.6 billion and US$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
	June 2025	4.60%	senior notes due June 2028	US$400
	June 2025	4.90%	senior notes due June 2030	US$600
	June 2025	5.55%	senior notes due June 2035	US$900
	June 2025	5.95%	senior notes due April 2054	US$350
	September 2025	5.15%	fixed-to-fixed subordinated notes due December 20552	$1,000
Enbridge Gas Inc.
	September 2025	4.16%	medium-term notes due September 2035	$500
	September 2025	4.84%	medium-term notes due September 2055	$300
The East Ohio Gas Company
	June 2025	5.68%	senior notes due June 2035	US$250
	June 2025	6.32%	senior notes due June 2055	US$250

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

2For the initial 5.25 years, the notes carry a fixed interest rate. On December 17, 2030, the interest rate will be reset to equal the Five-Year Government of Canada bond yield plus a margin of 2.39%.

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LONG-TERM DEBT REPAYMENTS

During the nine months ended September 30, 2025, we completed the following long-term debt repayments totaling US$3.0 billion, $2.0 billion and €21 million:

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
	June 2025	2.44%	medium-term notes	$550
Enbridge Gas Inc.
	September 2025	3.31%	medium-term notes	$400
	September 2025	3.19%	medium-term notes	$200
Enbridge Pipelines (Southern Lights) L.L.C.
	June 2025	3.98%	senior notes	US$47
Enbridge Pipelines Inc.
	February 2025	4.10%	medium-term notes1	$100
	September 2025	3.45%	medium-term notes	$600
Enbridge Southern Lights LP
	June 2025	4.01%	senior notes	$11
Westcoast Energy Inc.
	July 2025	8.85%	debentures	$150
Enbridge Energy Partners, L.P.
	July 2025	5.88%	senior notes2	US$500
Spectra Energy Partners, LP
	March 2025	3.50%	senior notes	US$500
Blauracke GMBH
	April 2025	2.10%	senior notes	€21
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
The East Ohio Gas Company
	June 2025	1.30%	senior notes	US$500

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

2The notes carried an original maturity date in October 2025.

SUBORDINATED TERM NOTES

As at September 30, 2025 and December 31, 2024, our fixed-to-floating rate and fixed-to-fixed rate subordinated term notes had a principal value of $16.1 billion and $15.5 billion, respectively.

FAIR VALUE ADJUSTMENT

As at September 30, 2025 and December 31, 2024, the fair value adjustments to decrease total debt assumed in historical acquisitions were $440 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 September 30, 2025, we were in compliance with all such debt covenant provisions.

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9. REDEEMABLE NONCONTROLLING INTEREST

Westcoast Energy Limited Partnership

The First Nations Partnership has the option, exercisable at any time from and after July 2, 2035, to require the Class B and Class C unitholders of Westcoast LP to redeem all of the Class A units for cash at the then-current fair value, subject to certain limitations. As a result of this redemption feature, we have classified the Class A units as Redeemable NCI within the mezzanine equity section of the Consolidated Statements of Financial Position. As at September 30, 2025, the outstanding Class B and Class C units of Westcoast LP are held by us.

Designated capital programs within Westcoast LP will be funded by us in exchange for Class C units. The Class C units will not have any economic or voting entitlements until after the respective program has been completed or substantially completed. Following completion or substantial completion, the First Nations Partnership has an option to purchase the respective Class C units up to its then-current ownership interest in Westcoast LP.

The changes in our Redeemable NCI were as follows:

For the three and nine months ended September 30,	2025
(millions of Canadian dollars)
Balance at beginning of period		—
Proceeds from investment by redeemable noncontrolling interest in subsidiary		736
Transaction costs, net of deferred tax benefit		(27	)
Earnings attributable to redeemable noncontrolling interest		16
Distributions declared to unitholder		(17	)
Redemption value adjustment		28
Balance at end of period		736

10. SHARE CAPITAL

On May 15, 2024, we filed prospectus supplements in Canada and the US to establish an at-the-market equity issuance program (the ATM Program) that allowed us to issue and sell, at our discretion, up to $2.75 billion (or the US dollar equivalent) of our common shares from treasury to the public from time to time at the market prices prevailing at the time of sale through the Toronto Stock Exchange, the New York Stock Exchange or any other marketplace in Canada or the US where the common shares may be traded.

During the period from May 15, 2024 to July 31, 2024, 51,298,629 common shares were issued and sold under the ATM Program at average prices of CAD$48.72 and US$35.77 per common share for aggregate gross proceeds of $2.50 billion ($2.48 billion, net of aggregate commissions paid of $16.3 million and other issuance costs). On August 1, 2024, we terminated the ATM Program. Net proceeds from sales of common shares under the ATM Program were used to partially fund the Questar Acquisition and the PSNC Acquisition and to pay related fees and expenses.

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11. COMPONENTS OF ACCUMULATED OTHER COMPREHENSIVE INCOME

Changes in Accumulated other comprehensive income (AOCI) attributable to our common shareholders for the nine months ended September 30, 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		(22	)		12			216			(2,048	)		26			62			(1,754	)
Other comprehensive (income)/loss reclassified to earnings
Interest rate contracts1		26			—			—			—			—			—			26
Foreign exchange contracts2		—			(3	)		—			—			—			—			(3	)
Amortization of pension and OPEB actuarial gain3		—			—			—			—			—			(24	)		(24	)
		4			9			216			(2,048	)		26			38			(1,755	)
Tax impact
Income tax on amounts retained in AOCI		—			4			—			—			—			(13	)		(9	)
Income tax on amounts reclassified to earnings		(4	)		1			—			—			—			4			1
		(4	)		5			—			—			—			(9	)		(8	)
Balance as at September 30, 2025		407			—			(1,817	)		6,404			27			331			5,352

	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		15			(34	)		(357	)		1,498			3			—			1,125
Other comprehensive (income)/loss reclassified to earnings
Interest rate contracts1		22			—			—			—			—			—			22
Commodity contracts4		(1	)		—			—			—			—			—			(1	)
Foreign exchange contracts2		—			43			—			—			—			—			43
Amortization of pension and OPEB actuarial gain3		—			—			—			—			—			(14	)		(14	)
		36			9			(357	)		1,498			3			(14	)		1,175
Tax impact
Income tax on amounts retained in AOCI		(4	)		8			—			—			—			—			4
Income tax on amounts reclassified to earnings		(3	)		(10	)		—			—			—			3			(10	)
		(7	)		(2	)		—			—			—			3			(6	)
Balance as at September 30, 2024		349			(16	)		(1,085	)		4,151			14			59			3,472

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.

4Reported within Transportation and other services revenues in the Consolidated Statements of Earnings.

12. 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.

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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 2.8%.

We are exposed to changes in the fair value of fixed rate debt that arise as a result of changes in market interest rates. Pay floating-receive fixed interest rate swaps are used, when applicable, to hedge against future changes to the fair value of fixed rate debt which mitigates the impact of fluctuations in fair value. Executed fixed-to-floating interest rate swaps have an average swap rate of 2.8%.

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 is used to hedge against the effect of future interest rate movements. We have established a program including some of our subsidiaries to partially mitigate our exposure to long-term interest rate variability on forecasted term debt issuances via execution of floating-to-fixed interest rate swaps with an average swap rate of 3.5%.

Commodity Price Risk

Our earnings, cash flows and OCI are exposed to changes in commodity prices as a result of our ownership interests in certain assets and investments, as well as through the activities of our energy marketing subsidiaries. These commodities include natural gas, crude oil, power and natural gas liquids (NGL). We employ financial and physical derivative instruments to fix a portion of the variable price exposures that arise from physical transactions involving these commodities. For our US Gas Utilities, changes in derivatives' fair values are deferred as regulatory assets or liabilities until settlement. 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.

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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.

September 30, 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		—			—			20			20			(9	)		11
Interest rate contracts		2			6			14			22			(14	)		8
Commodity contracts		—			—			399			399			(155	)		244
		2			6			433			441			(178	)		263
Deferred amounts and other assets
Foreign exchange contracts		—			—			23			23			(16	)		7
Interest rate contracts		29			—			100			129			(34	)		95
Commodity contracts		—			—			155			155			(29	)		126
		29			—			278			307			(79	)		228
Other current liabilities
Foreign exchange contracts		—			—			(466	)		(466	)		9			(457	)
Interest rate contracts		(12	)		—			(30	)		(42	)		14			(28	)
Commodity contracts		—			—			(266	)		(266	)		155			(111	)
		(12	)		—			(762	)		(774	)		178			(596	)
Other long-term liabilities
Foreign exchange contracts		—			—			(993	)		(993	)		16			(977	)
Interest rate contracts		(16	)		(5	)		(73	)		(94	)		34			(60	)
Commodity contracts		—			—			(91	)		(91	)		29			(62	)
		(16	)		(5	)		(1,157	)		(1,178	)		79			(1,099	)
Total net derivative asset/(liability)
Foreign exchange contracts		—			—			(1,416	)		(1,416	)		—			(1,416	)
Interest rate contracts		3			1			11			15			—			15
Commodity contracts		—			—			197			197			—			197
		3			1			(1,208	)		(1,204	)		—			(1,204	)

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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:

September 30, 2025	2025				2026			2027			2028			2029		Thereafter			Total
Foreign exchange contracts - US dollar forwards - purchase (millions of US dollars)		936			4			—			—			—			—			940
Foreign exchange contracts - US dollar forwards - sell (millions of US dollars)		1,976			5,872			5,201			4,032			1,398			150			18,629
Foreign exchange contracts - US dollar collars - sell (millions of US dollars)		—			120			—			—			—			—			120
Foreign exchange contracts - British pound (GBP) forwards - sell (millions of GBP)		12			28			32			—			—			—			72
Foreign exchange contracts - Euro forwards - sell (millions of Euro)		31			121			81			67			66			129			495
Interest rate contracts - short-term pay fixed rate (millions of Canadian dollars)		1,052			3,905			2,849			2,223			1,003			—			11,032
Interest rate contracts - receive fixed rate (millions of Canadian dollars)		378			1,500			1,500			1,500			1,500			7,211			13,589
Interest rate contracts - long-term pay fixed rate (millions of Canadian dollars)1		661			3,352			174			—			—			—			4,187
Interest rate contracts - costless collar (millions of Canadian dollars)		497			1,976			1,849			78			—			—			4,400
Commodity contracts - natural gas (billions of cubic feet)2		23			118			63			24			12			6			246
Commodity contracts - crude oil (millions of barrels)2		(8	)		11			13			1			1			1			19
Commodity contracts - power (megawatt per hour (MW/H))		141			142			85			30			29			(2	)	34			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.

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Derivatives Designated as Fair Value Hedges

The following table presents interest rate and 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) or Interest expense in the Consolidated Statements of Earnings. Any excluded components are included in the Consolidated Statements of Comprehensive Income.

	Three months ended September 30,						Nine months ended September 30,
		2025			2024			2025			2024
(millions of Canadian dollars)
Unrealized gain/(loss) on derivative		1			71			(13	)		(21	)
Unrealized gain/(loss) on hedged item		(1	)		(67	)		(2	)		33
Realized gain/(loss) on derivative		—			(11	)		25			36
Realized loss on hedged item		—			—			(23	)		(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 September 30,						Nine months ended September 30,
	2025			2024			2025			2024
(millions of Canadian dollars)
Amount of unrealized gain/(loss) recognized in OCI
Cash flow hedges
Interest rate contracts		(8	)		(144	)		(22	)		4
Commodity contracts		1			5			(1	)		20
Other contracts		—			—			—			1
Fair value hedges
Foreign exchange contracts		—			(8	)		12			(34	)
		(7	)		(147	)		(11	)		(9	)
Amount of (income)/loss reclassified from AOCI to earnings
Foreign exchange contracts¹		—			12			(3	)		43
Interest rate contracts²		9			10			26			22
Commodity contracts3		—			—			—			(1	)
		9			22			23			64

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

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

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

We estimate that a loss of $1 million from AOCI related to open 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 September 30, 2025.

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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 September 30,						Nine months ended September 30,
	2025			2024			2025			2024
(millions of Canadian dollars)
Foreign exchange contracts1		(467	)		203			766			(736	)
Interest rate contracts2		(8	)		(161	)		(48	)		(39	)
Commodity contracts3		205			96			331			(21	)
Other contracts4		—			2			(3	)		1
Total unrealized derivative fair value gain/(loss), net		(270	)		140			1,046			(795	)

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

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

3For the respective nine months ended periods, reported within Transportation and other services revenues (2025 - $101 million gain; 2024 - $14 million loss), Commodity sales (2025 - $46 million loss; 2024 - $91 million loss), Commodity costs (2025 - $206 million gain; 2024 - $103 million gain) and Operating and administrative expense (2025 - $21 million gain; 2024 - $33 million loss) in the Consolidated Statements of Earnings. The fair value change in our US Gas Utilities is deferred as regulatory assets/(liabilities) (2025 - $49 million gain; 2024 - $14 million gain).

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 September 30, 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:

	September 30, 2025			December 31, 2024
(millions of Canadian dollars)
Canadian financial institutions		168			344
US financial institutions		149			128
European financial institutions		58			116
Asian financial institutions		28			53
Other1		332			332
		735			973

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

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As at September 30, 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 September 30, 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 utilities' 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 have restricted long-term investments in exchange-traded funds and common shares held in trust in accordance with the regulatory requirements of the Canada Energy Regulator (CER) 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.

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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 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.

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Fair Value of Derivatives

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

September 30, 2025	Level 1			Level 2			Level 3			Total Gross Derivative Instruments
(millions of Canadian dollars)
Financial assets
Current derivative assets
Foreign exchange contracts		—			20			—			20
Interest rate contracts		—			22			—			22
Commodity contracts		48			70			281			399
		48			112			281			441
Long-term derivative assets
Foreign exchange contracts		—			23			—			23
Interest rate contracts		—			129			—			129
Commodity contracts		2			9			144			155
		2			161			144			307
Financial liabilities
Current derivative liabilities
Foreign exchange contracts		—			(466	)		—			(466	)
Interest rate contracts		—			(42	)		—			(42	)
Commodity contracts		(29	)		(73	)		(164	)		(266	)
		(29	)		(581	)		(164	)		(774	)
Long-term derivative liabilities
Foreign exchange contracts		—			(993	)		—			(993	)
Interest rate contracts		—			(94	)		—			(94	)
Commodity contracts		(7	)		(13	)		(71	)		(91	)
		(7	)		(1,100	)		(71	)		(1,178	)
Total net financial asset/(liability)
Foreign exchange contracts		—			(1,416	)		—			(1,416	)
Interest rate contracts		—			15			—			15
Commodity contracts		14			(7	)		190			197
		14			(1,408	)		190			(1,204	)

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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:

September 30, 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		7		Forward gas price		1.30			19.49			5.10		$/mmbtu2
Crude		20		Forward crude price		65.36			87.86			82.84		$/barrel
Power		(7	)	Forward power price		37.64			179.56			69.88		$/MW/H
Commodity contracts - physical¹
Natural gas		(11	)	Forward gas price		0.08			13.54			4.57		$/mmbtu2
Crude		(10	)	Forward crude price		66.60			114.43			84.80		$/barrel
Power		(7	)	Forward power price		27.40			131.49			72.14		$/MW/H
Commodity options3
Natural gas		198		Forward gas price		3.12			11.41			6.95		$/mmbtu2
				Price volatility	3.0%			79.0%			52.0%
		190

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.

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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:

	Nine months ended September 30,
	2025			2024
(millions of Canadian dollars)
Level 3 net derivative liability at beginning of period		(52	)		(131	)
Total gain/(loss), unrealized
Included in earnings1		84			1
Included in OCI		(1	)		19
Included in regulatory assets/liabilities		44			—
Settlements		115			2
Level 3 net derivative asset/(liability) at end of period		190			(109	)

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 September 30, 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 nine months ended September 30, 2025 and 2024, we recognized unrealized foreign exchange gains of $297 million and losses of $244 million, respectively, on the translation of US dollar-denominated debt, in OCI. During the nine months ended September 30, 2025 and 2024, we recognized realized losses of $81 million and $113 million, respectively, associated with the settlement of US dollar-denominated debt that had matured during the period, in OCI.

Fair Value of Other Financial Instruments

Certain long-term investments in other entities with no actively quoted prices are classified as Fair Value Measurement Alternative (FVMA) investments and are recorded at cost less impairment. The carrying value of FVMA investments totaled $188 million and $187 million as at September 30, 2025 and December 31, 2024, respectively.

We have restricted long-term investments and cash held in trust for the purpose of funding pipeline abandonment in accordance with the CER's regulatory requirements under the LMCI, to cover future pipeline decommissioning costs in the state of Minnesota and to satisfy retirement obligations as Wexpro properties are abandoned. These investments are classified as available-for-sale, recognized at fair value and included in Restricted long-term investments and cash in the Consolidated Statements of Financial Position. As at September 30, 2025, the fair value of investments in Level 1 and Level 2 was $838 million and $407 million, respectively (December 31, 2024 - $491 million and $507 million, respectively). Our Level 2 investments had a cost basis of $408 million as at September 30, 2025 (December 31, 2024 - $540 million). There were unrealized holding gains of $50 million and $96 million on these investments for the three and nine months ended September 30, 2025, respectively (2024 - gains of $46 million and $45 million, respectively). During the nine months ended September 30, 2025, we purchased and sold investments totaling $1.1 billion and $995 million, respectively (2024 - purchases of $319 million and sales of $240 million). The resulting net cash flow impact is presented under Cash Flows from Investing Activities in the Consolidated Statements of Cash Flows.

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We have a wholly-owned captive insurance subsidiary 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 September 30, 2025, the fair value of investments in equity funds and debt securities held by our captive insurance subsidiary was nil and $1.2 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 September 30, 2025 and December 31, 2024. 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 nil and $1 million for the three and nine months ended September 30, 2025, respectively (2024 - gains of $14 million and $35 million, respectively).

As at September 30, 2025 and December 31, 2024, our long-term debt, including finance lease liabilities, had a carrying value before debt issuance costs of $102.9 billion and $101.6 billion, respectively, and a fair value of $101.7 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.

13. INCOME TAXES

The effective income tax rates for the three months ended September 30, 2025 and 2024 were 27.2% and 17.7%, respectively, and for the nine months ended September 30, 2025 and 2024 were 22.9% and 22.3%, respectively.

The period-over-period increase in the effective income tax rate for the three months ended was due to higher US minimum tax, the prior year tax benefits relating to the state apportionment income tax rate change due to the PSNC Acquisition (Note 6), and certain rate-regulated adjustments, partially offset by higher US investment tax credits relative to the decrease in earnings over the comparative periods.

The period-over-period increase in the effective income tax rates for the nine-months ended was due to higher US minimum tax, the prior year tax benefits relating to the state apportionment income tax rate change due to the Acquisitions (Note 6), the non-taxable portion of the gain on the prior year disposition of Alliance Pipeline and Aux Sable (Note 6), and certain rate-regulated adjustments, partially offset by higher US investment tax credits and the prior year write-down of non-deductible goodwill on the Gas Transmission segment relative to the increase in earnings over the comparative periods.

14. OTHER INCOME/(EXPENSE)

	Three months ended September 30,						Nine months ended September 30,
	2025			2024			2025			2024
(millions of Canadian dollars)
Realized foreign currency gain/(loss)		(80	)		(34	)		(366	)		80
Unrealized foreign currency gain/(loss)		(425	)		255			824			(816	)
Net defined pension and OPEB credit		71			44			215			133
Other		137			111			519			397
		(297	)		376			1,192			(206	)

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15. 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.

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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

East Tennessee

East Tennessee Natural Gas, LLC (East Tennessee) filed a rate case on April 29, 2025. On May 29, 2025, the Federal Energy Regulatory Commission (FERC) issued an order accepting and suspending tariff records, subject to refund, conditions, and establishing hearing procedures. In compliance with the order, East Tennessee has made a motion filing to implement the rates to be effective November 1, 2025, subject to refund. Settlement discussions with shippers commenced in the third quarter of 2025.

Vector

Vector Pipeline L.P. (Vector) filed a rate case on May 30, 2025. On June 30, 2025, the FERC issued an order accepting and suspending tariff records filed in this rate case, subject to refund and establishing hearing procedures. In compliance with the order, Vector placed the rate reductions into effect on July 1, 2025. Additionally, on July 1, 2025, the chief administrative law judge issued an order consolidating Vector’s outstanding review of rates initiated by the FERC in 2024 with Vector’s May 30, 2025 rate case filing. Settlement discussions with shippers commenced in the third quarter of 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 incentive rate setting (Price Cap IR) 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 addresses cost allocation and the harmonization of rates, rate classes and services and is anticipated to be completed in 2026.

In December 2023, the OEB issued its Decision and Order on Phase 1 (Phase 1 Decision). Enbridge Gas Ontario initiated various appeals of select aspects of the Phase 1 Decision, including a review motion with the OEB that concluded in April 2025 with the OEB denying its motion to vary the Phase 1 Decision which disallowed recoverability of certain undepreciated capital. Enbridge Gas Ontario continues to pursue appeal and judicial review applications to the Ontario Divisional Court that challenge some of the OEB’s Phase 1 findings with respect to depreciation, equity thickness and undepreciated capital. Hearing dates in March 2026 have been scheduled for the hearing of the appeal and judicial review applications.

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In November 2024, the OEB issued its Decision approving the Phase 2 Partial Settlement Proposal (Phase 2 Settlement). The Phase 2 Settlement established a Price Cap IR mechanism to be used for determining rates for 2025-2028. The Price Cap IR 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 the OEB rendered its Decision in May 2025. Rates effective January 1, 2025 were set using the Price Cap IR mechanism.

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 Decision. The OEB also revised the formula for calculating ROE by reducing flotation costs by 25 basis points. The new formula will be applicable to Enbridge Gas Ontario at its next rebasing expected in 2029. Until then, rates will continue to reflect the embedded 2024 ROE formula value of 9.21%.

Enbridge Gas Ohio

In October 2023, Enbridge Gas Ohio filed its first rates application with the Public Utilities Commission of Ohio (Ohio Commission) since 2007 proposing a base rate annual revenue increase (compared to current rates) of US$212 million, 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, including an ROE of 10.40%. The application was subsequently amended to reduce the annual revenue increase from US$212 million to US$60 million.

In June 2025, the Ohio Commission ordered a decrease to annual revenue, compared to current rates, of US$26.3 million, utilizing an ROE of 9.79%, an increase to the equity thickness to 51.9%, and the continuation of the Pipeline Infrastructure Replacement and Capital Expenditure Programs. The order also resulted in disallowances of $330 million (US$240 million), including regulatory assets related to pension balances of $280 million (US$204 million) and other disallowances of $50 million (US$36 million), which were recognized for the period ended June 30, 2025.

In July 2025, Enbridge Gas Ohio filed an application for rehearing regarding certain aspects of the Order. The Ohio Commission corrected some accounting errors in its Order addressing the rehearing application resulting in an additional US$12 million revenue requirement and a total annual revenue requirement of US$895 million. The Ohio Commission also required Enbridge Gas Ohio to make an additional cost of service filing reflecting the Ohio Commission’s decisions. The Ohio Commission approved Enbridge Gas Ohio’s filing on October 15, 2025. New rates were put into effect on November 1, 2025.

Enbridge Gas North Carolina

In April 2025, Enbridge Gas North Carolina filed its first rates application since 2021 with the North Carolina Utilities Commission. This rate case proposed the recovery of costs to deliver natural gas to customers and investments in infrastructure to support service reliability and customer growth. Enbridge Gas North Carolina proposed a total revenue requirement of US$854 million.

In September 2025, a joint stipulation of settlement was filed and is pending approval by the North Carolina Utilities Commission. If approved, updated rates would be effective November 1, 2025 and would reflect a revenue increase of US$34 million and a total revenue requirement of US$801 million.

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Enbridge Gas Utah

In May 2025, Enbridge Gas Utah filed its first rates application since 2022 with the Utah Public Service Commission. This rate case proposed the recovery of costs to deliver natural gas to customers and investments in infrastructure to support service reliability and customer growth. Enbridge Gas Utah proposed a total revenue requirement of US$657 million. On September 26, 2025, Enbridge Gas Utah filed a settlement reflecting a revenue increase of US$62 million and a total revenue requirement of US$604 million. A decision on the filing is expected before the end of the year with new rates expected to take effect on January 1, 2026.

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.

In June 2025, Enbridge Gas Ohio closed a two-tranche offering consisting of 10-year senior notes and 30-year senior notes for an aggregate principal amount of US$500 million, which mature in June 2035 and June 2055, respectively.

In June 2025, we closed a four-tranche offering consisting of three-year senior notes, five-year senior notes, 10-year senior notes and re-opened existing 30-year senior notes for an aggregate principal of US$2.3 billion, which mature in June 2028, June 2030, June 2035 and April 2054, respectively.

In July 2025, we renewed approximately $8.8 billion of our 364-day extendible credit facilities, extending the maturity dates to July 2027, which includes a one-year term out provision from July 2026. We also renewed approximately $7.8 billion of our five-year credit facilities, extending the maturity dates to July 2030. Further, we extended the maturity dates of our three-year credit facilities to July 2028.

In July 2025, Enbridge Gas Ontario and Enbridge Pipelines Inc. extended the maturity dates of their $2.5 billion and $2.0 billion 364-day extendible credit facilities, respectively, to July 2027, which includes one-year term out provisions from July 2026.

On July 28, 2025, Enbridge Energy Partners, L.P. (EEP) redeemed at par all of the outstanding US$500 million 5.88% senior notes that carried an original maturity date in October 2025.

In September 2025, Enbridge Gas Ontario closed a two-tranche offering consisting of 10-year medium-term notes and 30-year medium-term notes for an aggregate principal amount of $0.8 billion, which mature in September 2035 and September 2055, respectively.

In September 2025, we closed an offering consisting of 30-year non-call 5.15% fixed-to-fixed subordinated notes for a principal amount of $1.0 billion, which mature in December 2055.

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 September 30, 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 12. Risk Management and Financial Instruments for more information on our interest rate hedging program.

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RESULTS OF OPERATIONS

	Three months ended September 30,						Nine months ended September 30,
	2025			2024			2025			2024
(millions of Canadian dollars, except per share amounts)
Segment earnings/(loss) before interest, income taxes and depreciation and amortization1
Liquids Pipelines		2,283			2,325			7,207			7,179
Gas Transmission		1,270			1,146			4,185			4,506
Gas Distribution and Storage		560			522			2,670			1,854
Renewable Power Generation		89			102			421			497
Eliminations and Other		(379	)		295			828			(502	)
Earnings before interest, income taxes and depreciation and amortization1		3,823			4,390			15,311			13,534
Depreciation and amortization		(1,398	)		(1,317	)		(4,197	)		(3,783	)
Interest expense		(1,262	)		(1,314	)		(3,777	)		(3,301	)
Income tax expense		(316	)		(312	)		(1,679	)		(1,437	)
Earnings attributable to noncontrolling interests and redeemable noncontrolling interest		(59	)		(56	)		(227	)		(167	)
Preference share dividends		(106	)		(98	)		(311	)		(286	)
Earnings attributable to common shareholders		682			1,293			5,120			4,560
Earnings per common share attributable to common shareholders		0.30			0.59			2.34			2.12
Diluted earnings per common share attributable to common shareholders		0.30			0.59			2.33			2.12

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

EARNINGS ATTRIBUTABLE TO COMMON SHAREHOLDERS

Three months ended September 30, 2025, compared with the three months ended September 30, 2024

Earnings attributable to common shareholders were negatively impacted by $414 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 $394 million ($299 million after-tax) in 2025, compared with a net unrealized gain of $112 million ($92 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; and

•the absence in 2025 of a deferred tax recovery of $59 million due to a change in state apportionment as a result of the acquisition of Public Service Company of North Carolina, Incorporated (PSNC).

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.

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After taking into consideration the factors above, the remaining $197 million decrease in earnings attributable to common shareholders is primarily explained 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 Enbridge Gas North Carolina and other assets placed into service after Q3 2024; and

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

The factors above were partially offset by:

•higher contributions from our Gas Transmission segment primarily due to recognition of increased revenue attributable to Algonquin and Texas Eastern rate case settlements, contributions from the Texas Eastern Venice Extension project, and favorable contracting and lower operating costs on our US Gas Transmission assets; and

•full-quarter contribution from the acquisition of Enbridge Gas North Carolina and increased revenue requirement from recovery of capital investments at Enbridge Gas Ohio both in our Gas Distribution and Storage segment.

Nine months ended September 30, 2025, compared with the nine months ended September 30, 2024

Earnings attributable to common shareholders were positively impacted by $300 million due to certain infrequent or other non-operating factors, primarily explained by the following:

•a non-cash, net unrealized derivative fair value gain of $944 million ($742 million after-tax) in 2025, compared with a net unrealized loss of $773 million ($586 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; and

•equity earnings of $87 million ($65 million after-tax) from our investment in DCP Midstream, LP (DCP), as a result of DCP's gain on disposition from certain pipeline assets; partially offset by

•the absence in 2025 of a gain on sale of $1.1 billion ($765 million after-tax) on the disposition of interests in the Alliance Pipeline, Aux Sable and NRGreen;

•an impairment of $330 million ($261 million after-tax) of certain rate-regulated assets related to pension and other disallowances as a result of the Ohio Commission's June 2025 order related to Enbridge Gas Ohio's rate case; and

•the absence in 2025 of a deferred tax recovery of $141 million due to a change in state apportionment as a result of the Acquisitions.

After taking into consideration the factors above, the remaining $260 million increase in earnings attributable to common shareholders is primarily explained by:

•three full quarters of contributions from the US Gas Utilities 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, higher storage optimization and pricing, and higher distribution margin in our Gas Distribution and Storage segment;

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

•equity earnings related to a litigation settlement in our Liquids Pipelines segment.

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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 three full quarters' ownership of the US Gas Utilities;

•lower interest income due to investing in 2024, cash sources from the pre-funding of the Acquisitions in Eliminations and Other;

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

•lower contributions from our Gas Transmission segment due to the sale of our interests in Alliance Pipeline and Aux Sable in April 2024 and lower earnings from our Tomorrow RNG renewable natural gas production facilities due to lower Renewable Identification Number (RIN) pricing and timing of RIN sales.

BUSINESS SEGMENTS

LIQUIDS PIPELINES

	Three months ended September 30,						Nine months ended September 30,
	2025			2024			2025			2024
(millions of Canadian dollars)
Earnings before interest, income taxes and depreciation and amortization		2,283			2,325			7,207			7,179

Three months ended September 30, 2025, compared with the three months ended September 30, 2024

EBITDA was negatively impacted by $42 million, primarily explained by lower contributions from the Flanagan South and Spearhead Pipelines of the Gulf Coast and Mid-Continent System.

Nine months ended September 30, 2025, compared with the nine months ended September 30, 2024

EBITDA was positively impacted by $23 million due to certain infrequent or other non-operating factors, primarily explained by:

•a non-cash, net unrealized gain of $54 million in 2025, compared with a net unrealized gain of $20 million in 2024, reflecting changes in the mark-to-market value of derivative financial instruments used to manage commodity price risks; partially offset by

•a net negative adjustment to crude oil inventory of $13 million in 2025, compared with a net positive adjustment of $3 million in 2024.

After taking into consideration the factors above, the remaining $5 million increase is primarily explained by the following significant business factors:

•equity earnings attributable to a litigation settlement;

•favorable Regional Oil Sands results primarily from higher volumes;

•higher Mainline System contributions as a result of higher demand, annual escalators and surcharge effective July 1, 2024, and lower power costs from operational efficiencies and lower mill rates; 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 spot volumes on the Flanagan South and Spearhead Pipelines; and

•lower contributions from the Bakken System due to lower volumes.

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GAS TRANSMISSION

	Three months ended September 30,						Nine months ended September 30,
	2025			2024			2025			2024
(millions of Canadian dollars)
Earnings before interest, income taxes and depreciation and amortization		1,270			1,146			4,185			4,506

Three months ended September 30, 2025, compared with the three months ended September 30, 2024

EBITDA was positively impacted by a non-cash gain of $16 million from the redemption of Enbridge's special 25.0% economic interest in the Rio Bravo Pipeline Project by the Whistler Parent JV.

The remaining $108 million increase is primarily explained by the following significant business factors:

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

•contributions from the Texas Eastern Venice Extension project since service commencement in late 2024;

•higher revenues at Aitken Creek due to favorable storage spreads; and

•favorable contracting and lower operating costs on our US Gas Transmission assets; partially offset by

•lower earnings at Tomorrow RNG primarily due to lower RIN pricing and timing of RIN sales.

Nine months ended September 30, 2025, compared with the nine months ended September 30, 2024

EBITDA was negatively impacted by $896 million due to certain infrequent or other non-operating factors, primarily explained by:

•the absence in 2025 of a gain on sale of $1.1 billion on the disposition of interests in the Alliance Pipeline and Aux Sable; and

•a non-cash, net unrealized loss of $30 million in 2025, compared with a net unrealized loss of $4 million in 2024, reflecting changes in the mark-to-market value of derivative financial instruments used to manage commodity price risks; partially offset by

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

•a net positive adjustment of $25 million in 2025 to the gas inventory at Aitken Creek compared to a net negative adjustment of $47 million in 2024;

•the absence in 2025 of a loss of $29 million as a result of the contribution of our 100% interest in the Rio Bravo Pipeline project to the Whistler Parent JV; and

•a gain of $16 million from the redemption of Enbridge's special 25.0% economic interest in the Rio Bravo Pipeline Project by the Whistler Parent JV.

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The remaining $575 million increase is primarily explained by the following significant business factors:

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

•contributions from the Texas Eastern Venice Extension project since service commencement in late 2024;

•contributions from the acquisition of equity interests in the Whistler Parent JV and the Delaware Basin Residue in the second and fourth quarters of 2024, respectively, and the Matterhorn Express Pipeline in the second quarter of 2025;

•higher revenues at Aitken Creek due to favorable storage spreads;

•favorable contracting on our US Gas Transmission assets;

•higher earnings from our investment in DCP; 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; and

•lower earnings at Tomorrow RNG primarily due to lower RIN pricing and timing of RIN sales.

GAS DISTRIBUTION AND STORAGE

	Three months ended September 30,						Nine months ended September 30,
	2025			2024			2025			2024
(millions of Canadian dollars)
Earnings before interest, income taxes and depreciation and amortization		560			522			2,670			1,854

Three months ended September 30, 2025, compared with the three months ended September 30, 2024

EBITDA was positively impacted by $38 million primarily explained by full-quarter contributions from the acquisition of Enbridge Gas North Carolina and increased revenue requirement from recovery of capital investments at Enbridge Gas Ohio.

Nine months ended September 30, 2025, compared with the nine months ended September 30, 2024

EBITDA was negatively impacted by $330 million due to an impairment of certain rate-regulated assets related to pension and other disallowances as a result of the Ohio Commission's June 2025 order related to Enbridge Gas Ohio's rate case.

The remaining $1.1 billion increase is primarily explained by the following significant business factors:

•three full quarters of contributions from the US Gas Utilities;

•when compared with the normal forecast embedded in rates, the positive impact of weather on EBITDA for Enbridge Gas Ontario was approximately $20 million in 2025 compared to a negative impact of approximately $105 million in the same period of 2024;

•higher distribution margin resulting from increases in rates and customer base at Enbridge Gas Ontario; and

•higher storage optimization and pricing at Enbridge Gas Ontario.

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RENEWABLE POWER GENERATION

	Three months ended September 30,						Nine months ended September 30,
	2025			2024			2025			2024
(millions of Canadian dollars)
Earnings before interest, income taxes and depreciation and amortization		89			102			421			497

Three months ended September 30, 2025, compared with the three months ended September 30, 2024

EBITDA was negatively impacted by $27 million primarily explained by a non-cash, net unrealized gain of $2 million in 2025, compared with a net unrealized gain of $28 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 $14 million increase is primarily explained by higher revenue from sale of renewable energy certificates compared to the third quarter of 2024.

Nine months ended September 30, 2025, compared with the nine months ended September 30, 2024

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

•the absence in 2025 of a gain on sale of $29 million related to the disposition of our interest in NRGreen; and

•a realized loss of $139 million, partially offset by a non-cash, net unrealized gain of $110 million in 2025, compared with a net unrealized loss of $8 million in 2024, reflecting changes in the mark-to-market value of derivative financial instruments used to manage foreign exchange and commodity price risks; partially offset by

•a $27 million gain on the disposition of our interest in East-West Tie Limited Partnership in the first quarter of 2025.

The remaining $51 million decrease is primarily explained by lower contributions from European offshore wind facilities, including weaker wind resources.

ELIMINATIONS AND OTHER

	Three months ended September 30,						Nine months ended September 30,
	2025			2024			2025			2024
(millions of Canadian dollars)
Earnings/(loss) before interest, income taxes and depreciation and amortization		(379	)		295			828			(502	)

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.

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Three months ended September 30, 2025, compared with the three months ended September 30, 2024

EBITDA was negatively impacted by $616 million primarily explained by a non-cash, net unrealized loss of $397 million in 2025, compared with a net unrealized gain of $206 million in 2024, reflecting changes in the mark-to-market value of derivative financial instruments used to manage foreign exchange and commodity price risk.

After taking into consideration the non-operating factors above, the remaining $58 million decrease in EBITDA is primarily explained by higher realized foreign exchange losses on hedge settlements in 2025.

Nine months ended September 30, 2025, compared with the nine months ended September 30, 2024

EBITDA was positively impacted by $1.8 billion, primarily due to certain infrequent or non-operating factors, explained by:

•a non-cash, net unrealized gain of $962 million in 2025, compared with a net unrealized loss of $745 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 a workforce reduction in February 2024; partially offset by

•a non-cash, net unrealized gain of $1 million in 2025, compared with a net gain of $35 million in 2024, reflecting changes in the fair value of investments held by our captive insurance subsidiaries; and

•$86 million of integration costs incurred related to the Acquisitions in 2025, compared to $55 million of integration and transaction costs in 2024.

After taking into consideration the non-operating factors above, the remaining $426 million decrease in EBITDA 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.

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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)
LIQUIDS PIPELINES
				No significant
	Southern Illinois			expenditures to	Pre-
1.	Connector3	100%	US$0.5 billion	date	construction		2028
				No significant
				expenditures to	Pre-
2.	Pelican CO2 Hub	50%	US$0.3 billion	date	construction	2029
GAS TRANSMISSION
3.	Texas Eastern Modernization	100%	US$0.4 billion	US$236 million	Under construction	2025 - 2026
	T-North Expansion				Under
4.	(Aspen Point)	100%4	$1.2 billion	$622 million	construction	2026
5.	Tennessee Ridgeline Expansion	100%	US$1.1 billion	US$377 million	Pre-construction	2026
6.	Woodfibre LNG5	30%	US$2.9 billion	US$1.3 billion	Under construction	2027
7.	T-South Expansion (Sunrise)	100%4	$4.0 billion	$433 million	Pre-construction	2028
	T-North Expansion				Pre-
8.	(Birch Grove)	100%4	$0.4 billion	$8 million	construction	2028
9.	Canyon System Pipelines	100%	US$1.0 billion	US$74 million	Pre-construction		2029
	Algonquin Reliable			No significant
	Affordable Resilient			expenditures to	Pre-
10.	Enhancement	100%	US$0.3 billion	date	construction		2029
				No significant
	USGC Storage Growth			expenditures to	Pre-
11.	Program	100%	US$0.5 billion	date	construction	2028 - 2033
GAS DISTRIBUTION AND STORAGE
12.	Moriah Energy Center6	100%	US$0.6 billion	US$343 million	Under construction	2027
13.	T-15 Reliability Project6,7	100%	US$0.7 billion	US$55 million	Pre-construction	2027 - 2028
RENEWABLE POWER GENERATION
14.	Sequoia Solar	100%	US$1.1 billion	US$676 million	Under construction	2025 - 2026
15.	Clear Fork Solar	100%	US$0.9 billion	US$89 million	Pre-construction		2027
	Calvados Offshore		$1.0 billion	$444 million	Under
16.	Wind8	21.7%	(€0.6 billion)	(€303 million)	construction	2027

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

2 Expenditures to date and status of the project are determined as at September 30, 2025.

3 Includes amounts for the construction of the Southern Illinois Connector Pipeline, which is expected to be 50% jointly-owned with Energy Transfer, costs to upgrade the Energy Transfer Crude Oil Pipeline, in which we have a 27.6% ownership interest, as well as amounts fully attributable to Enbridge.

4 Our redeemable noncontrolling interest holder, Stonlasec8 Indigenous Investments Limited Partnership, will have the opportunity to participate in designated capital programs once they have been completed or substantially completed. As a result, our ownership interest in the program(s) may change in future periods. Refer to Part I. Item 1. Financial Statements - Note 9. Redeemable Noncontrolling Interest.

5 Our expected investment is approximately US$2.3 billion, with the remainder financed through non-recourse project level debt.

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6 Previously approved projects that were acquired by Enbridge through the acquisition of PSNC in the third quarter of 2024.

7 Includes 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.

8 Our investment 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.

LIQUIDS PIPELINES

•Southern Illinois Connector - The construction of a new 24-inch pipeline from Wood River to Patoka, Illinois, connecting the Platte Pipeline to our jointly-owned Energy Transfer Crude Oil Pipeline. In addition, the project includes new pump stations to provide incremental capacity to the Platte system. Incremental volumes are secured under long-term take-or-pay agreements with investment grade customers. The project has an expected in-service date in 2028.

•Pelican CO2 Hub - A 50/50 joint venture with a subsidiary of Occidental Petroleum Corporation (Oxy) to design, construct and operate a carbon dioxide transportation and sequestration hub in the Louisiana Mississippi River corridor. Oxy will manage the sequestration portions of the project, while Enbridge will manage the pipeline. Development is supported by a long-term take-or-pay offtake agreement with an investment grade counterparty and the facility is expected to enter service in 2029.

GAS TRANSMISSION

•T-North Expansion (Birch Grove) - An expansion of our British Columbia (BC) Pipeline system 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.

•Woodfibre LNG Commercial Update - Enbridge and its partners have agreed to updated commercial terms for Woodfibre LNG. The preferred return will be set closer to completion of construction, de-risking Enbridge's return on capital, and our expected share of capital costs was updated in the second quarter of 2025.

•Canyon System Pipelines - A component of the Canyon System Pipelines project serving bp's Tiber offshore production facility in the US Gulf Coast (USGC). This project includes both crude oil and natural gas pipeline extensions and is expected to enter service in 2029. The Canyon System Pipelines project was previously sanctioned to support bp's Kaskida offshore development and includes a 24/26-inch oil pipeline connecting to Shell Pipeline Company LP's Green Canyon 19 Platform and a 12-inch gas pipeline connecting to our existing Magnolia Gas Gathering Pipeline.

•Algonquin Reliable Affordable Resilient Enhancement - An enhancement of our Algonquin Pipeline to serve incremental demand across the northeastern US. The project is anticipated to enhance supply reliability and improve affordability by reducing winter price volatility for customers. We expect the project to enter service in 2029.

•USGC Storage Growth Program - An expansion of our Egan Hub and Moss Bluff natural gas storage facilities in the USGC, to provide 16 billion cubic feet (Bcf) and 7 Bcf of new site capacity, respectively. Egan Hub will be expanded over two phases, with each phase expected to enter service in 2030 and 2033, respectively. The expansion of our Moss Bluff facility is expected to enter service in 2028. These projects are expected to improve site injection and withdrawal rates, optimizing existing capacity, and to offer storage capacity to USGC liquefied natural gas facilities during periods of high demand.

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RENEWABLE POWER GENERATION

•Clear Fork Solar - A 600-megawatt solar farm located near San Antonio, Texas, fully contracted under a long-term offtake agreement. The project has an expected in-service date in 2027.

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 $4.4 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 facilitate 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 help 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 September 30, 2025:

	Maturity1	Total Facilities			Draws2			Available
(millions of Canadian dollars)
Enbridge Inc.	2027-2049		8,039			6,831			1,208
Enbridge (U.S.) Inc.	2027-2030		10,461			3,782			6,679
Enbridge Pipelines Inc.	2027		2,000			1,089			911
Enbridge Gas Inc.	2027		2,500			1,275			1,225
Total committed credit facilities			23,000			12,977			10,023

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

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

In July 2025, we renewed approximately $8.8 billion of our 364-day extendible credit facilities, extending the maturity dates to July 2027, which includes a one-year term out provision from July 2026. We also renewed approximately $7.8 billion of our five-year credit facilities, extending the maturity dates to July 2030. Further, we extended the maturity dates of our three-year credit facilities to July 2028.

In July 2025, Enbridge Gas Ontario and Enbridge Pipelines Inc. extended the maturity dates of their $2.5 billion and $2.0 billion 364-day extendible credit facilities, respectively, to July 2027, which includes a one-year term out provision from July 2026.

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In addition to the committed credit facilities noted above, we maintain $1.6 billion of uncommitted demand letter of credit facilities, of which $994 million was unutilized as at September 30, 2025. As at December 31, 2024, we had $1.4 billion of uncommitted demand letter of credit facilities, of which $931 million was unutilized.

As at September 30, 2025, our net available liquidity totaled $11.4 billion (December 31, 2024 - $14.4 billion), consisting of available credit facilities of $10.0 billion (December 31, 2024 - $12.6 billion) and unrestricted cash and cash equivalents of $1.4 billion (December 31, 2024 - $1.8 billion) as reported in the Consolidated Statements of Financial Position.

Our credit facility agreements and term debt indentures include standard events of default and covenant provisions whereby accelerated repayment and/or termination of the agreements may result if we were to default on payment or violate certain covenants. As at September 30, 2025, we were in compliance with all such debt covenant provisions.

LONG-TERM DEBT ISSUANCES

During the nine months ended September 30, 2025, we completed the following long-term debt issuances totaling $4.6 billion and US$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
	June 2025	4.60%	senior notes due June 2028	US$400
	June 2025	4.90%	senior notes due June 2030	US$600
	June 2025	5.55%	senior notes due June 2035	US$900
	June 2025	5.95%	senior notes due April 2054	US$350
	September 2025	5.15%	fixed-to-fixed subordinated notes due December 20552	$1,000
Enbridge Gas Inc.
	September 2025	4.16%	medium-term notes due September 2035	$500
	September 2025	4.84%	medium-term notes due September 2055	$300
The East Ohio Gas Company
	June 2025	5.68%	senior notes due June 2035	US$250
	June 2025	6.32%	senior notes due June 2055	US$250

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

2For the initial 5.25 years, the notes carry a fixed interest rate. On December 17, 2030, the interest rate will be reset to equal the Five-Year Government of Canada bond yield plus a margin of 2.39%.

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LONG-TERM DEBT REPAYMENTS

During the nine months ended September 30, 2025, we completed the following long-term debt repayments totaling US$3.0 billion, $2.0 billion and €21 million:

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
	June 2025	2.44%	medium-term notes	$550
Enbridge Gas Inc.
	September 2025	3.31%	medium-term notes	$400
	September 2025	3.19%	medium-term notes	$200
Enbridge Pipelines (Southern Lights) L.L.C.
	June 2025	3.98%	senior notes	US$47
Enbridge Pipelines Inc.
	February 2025	4.10%	medium-term notes1	$100
	September 2025	3.45%	medium-term notes	$600
Enbridge Southern Lights LP
	June 2025	4.01%	senior notes	$11
Westcoast Energy Inc.
	July 2025	8.85%	debentures	$150
Enbridge Energy Partners, L.P.
	July 2025	5.88%	senior notes2	US$500
Spectra Energy Partners, LP
	March 2025	3.50%	senior notes	US$500
Blauracke GMBH
	April 2025	2.10%	senior notes	€21
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
The East Ohio Gas Company
	June 2025	1.30%	senior notes	US$500

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

2The notes carried an original maturity date in October 2025.

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 $103 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 September 30, 2025 and December 31, 2024, we had negative working capital positions of $1.1 billion and $2.9 billion, respectively. During the nine months ended September 30, 2025, the major contributing factor to the negative 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.

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SOURCES AND USES OF CASH

	Nine months ended September 30,
		2025			2024
(millions of Canadian dollars)
Operating activities		9,159			8,938
Investing activities		(7,187	)		(15,915	)
Financing activities		(2,292	)		2,943
Effect of translation of foreign denominated cash and cash equivalents and restricted cash		(28	)		151
Net change in cash and cash equivalents and restricted cash		(348	)		(3,883	)

Significant sources and uses of cash for the nine months ended September 30, 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, Questar, PSNC and Tomorrow RNG, as well as our contributions to acquire an equity interest in the Whistler Parent JV in 2024; partially offset by the absence of proceeds received from the disposition of our interests in the Alliance Pipeline, Aux Sable and NRGreen in 2024 and higher 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, and share redemptions. Cash used in financing activities is also impacted by changes in distributions to, and contributions from, noncontrolling interests and redeemable noncontrolling interest. 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 the same period in 2024;

•absence of the at-the-market equity issuance program in 2025, which resulted in the issuance of 51,298,629 common shares for aggregate net proceeds of $2.5 billion in 2024; and

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

The factors above were partially offset by proceeds of $712 million, net of transaction costs, received from Stonlasec8 Indigenous Investments Limited Partnership for their noncontrolling interest investment in our BC Pipeline system.

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SUMMARIZED FINANCIAL INFORMATION

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

Consenting SEP notes and EEP notes under Guarantees

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

1As at September 30, 2025, the aggregate outstanding principal amount of SEP notes was approximately US$1.7 billion.

2As at September 30, 2025, the aggregate outstanding principal amount of EEP notes was approximately US$1.9 billion.

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Enbridge Notes under Guarantees

USD Denominated1	CAD Denominated2
1.60% Senior Notes due 2026	3.20% Senior Notes due 2027
5.90% Senior Notes due 2026	5.70% Senior Notes due 2027
4.25% Senior Notes due 2026	3.55% Senior Notes due 2028
5.25% Senior Notes due 2027	4.90% Senior Notes due 2028
3.70% Senior Notes due 2027	6.10% Senior Notes due 2028
4.60% Senior Notes due 2028	Floating Rate Senior Notes due 2028
6.00% Senior Notes due 2028	2.99% Senior Notes due 2029
5.30% Senior Notes due 2029	4.21% Senior Notes due 2030
3.13% Senior Notes due 2029	3.90% Senior Notes due 2030
4.90% Senior Notes due 2030	7.22% Senior Notes due 2030
6.20% Senior Notes due 2030	7.20% Senior Notes due 2032
5.70% Sustainability-Linked Senior Notes due 2033	6.10% Sustainability-Linked Senior Notes due 2032
2.50% Sustainability-Linked Senior Notes due 2033	5.36% Sustainability-Linked Senior Notes due 2033
5.63% Senior Notes due 2034	3.10% Sustainability-Linked Senior Notes due 2033
5.55% Senior Notes due 2035	4.73% Senior Notes due 2034
4.50% Senior Notes due 2044	4.56% Senior Notes due 2035
5.50% Senior Notes due 2046	5.57% Senior Notes due 2035
4.00% Senior Notes due 2049	5.75% Senior Notes due 2039
3.40% Senior Notes due 2051	5.12% Senior Notes due 2040
6.70% Senior Notes due 2053	4.24% Senior Notes due 2042
5.95% Senior Notes due 2054	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
	4.56% Senior Notes due 2064

1As at September 30, 2025, the aggregate outstanding principal amount of the Enbridge US dollar-denominated notes was approximately US$18.3 billion.

2As at September 30, 2025, the aggregate outstanding principal amount of the Enbridge Canadian dollar-denominated notes was approximately $14.5 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.

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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

Nine months ended September 30,	2025
(millions of Canadian dollars)
Operating loss		(24	)
Earnings		1,736
Earnings attributable to common shareholders		1,425

Summarized Combined Statements of Financial Position

	September 30, 2025			December 31, 2024
(millions of Canadian dollars)
Cash and cash equivalents		654			2,000
Accounts receivable from affiliates		4,021			3,901
Short-term loans receivable from affiliates		5,230			3,892
Other current assets		358			499
Long-term loans receivable from affiliates		37,453			54,416
Other long-term assets		1,984			2,139
Accounts payable to affiliates		2,104			2,252
Short-term loans payable to affiliates		1,786			1,188
Trade payables and accrued liabilities		395			661
Other current liabilities		1,375			8,047
Long-term loans payable to affiliates		23,322			36,576
Other long-term liabilities		69,438			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.

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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

MICHIGAN LINE 5 DUAL PIPELINES - STRAITS OF MACKINAC EASEMENT

Michigan Attorney General Lawsuit

In 2019, the Michigan Attorney General initiated legal action in the Michigan Ingham County Circuit Court (Michigan Circuit Court) seeking to invalidate the 1953 easement that authorizes the operation of Enbridge’s Line 5 pipeline in the Straits of Mackinac. The Attorney General’s case was later moved to US federal court in December 2021, following 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.

In June 2024, the US Court of Appeals for the Sixth Circuit (Sixth Circuit) ruled that the case should proceed in state court. Enbridge’s request for a rehearing was denied in August 2024. Oral argument on long-standing cross motions for summary disposition was held in January 2025 in the Michigan Circuit Court. We anticipate a decision on the motions for summary disposition in late 2025 or early 2026.

Separately, in January 2025, Enbridge petitioned the US Supreme Court to review the Sixth Circuit’s decision. The Court granted the petition in June 2025 and is expected to hear the case in early 2026, with a decision anticipated in the first half of 2026. In the interim, Enbridge requested that the Michigan Circuit Court pause proceedings pending the US Supreme Court’s ruling. This motion was denied.

In parallel, the US Army Corps of Engineers (Army Corps) announced in April 2025 that the Line 5 Tunnel Project qualifies for review under emergency and special processing procedures, potentially expediting federal permitting.

Enbridge Lawsuit

On November 24, 2020, Enbridge filed in the US District Court in the Western District of Michigan (US District Court) a complaint for declaratory and injunctive relief, seeking to prevent the Governor of Michigan and Director of the Michigan Department of Natural Resources (Michigan State Officials) from interfering with the continued operation of Line 5. The Government of Canada has reiterated its support for the pipeline, emphasizing the relevance of the 1977 Transit Pipelines Treaty and the matter’s importance to Canada. The case remains in federal court.

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In January 2022, Michigan State Officials moved to dismiss the case, while Enbridge filed for summary judgment. On July 5, 2024, the US District Court denied the state’s motion to dismiss, prompting an immediate appeal to the Sixth Circuit. The US District Court stayed the case pending the outcome of the appeal.

On April 23, 2025, the Sixth Circuit affirmed the US District Court’s ruling and a petition for rehearing en banc was denied on June 16, 2025. On June 24, 2025, the case was administratively transferred back to the US District Court and Michigan State Officials filed their Answer to Enbridge’s complaint.

A case management order was issued on July 14, 2025, setting out a briefing schedule for Enbridge’s summary judgment motion and the state’s motion to abstain. On September 12, 2025, the US filed a statement of interest in the case and briefing concluded on October 10, 2025, with oral argument on the motions scheduled for November 12, 2025. We anticipate a decision on the motions in the first half of 2026.

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.

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.

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ITEM 4. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

Disclosure controls and procedures are designed to provide reasonable assurance that information required to be disclosed by us in the reports filed with, or submitted to, securities regulatory authorities, including under the Exchange Act, is recorded, processed, summarized and reported within the time periods specified under Canadian and US securities law. 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 September 30, 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 September 30, 2025 and found no change that has materially affected, or is reasonably likely to materially affect, internal control over financial reporting.

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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 remain 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 and may impact our business operations, include, among others (as of the date of this report):

•global tariff on steel and aluminum;

•tariff on Canadian goods that are non-compliant under the United States-Mexico-Canada Agreement (USMCA), excluding crude oil, natural gas, and natural gas liquids; and

•other periodic retaliatory tariffs on Canada.

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 announced retaliatory measures against the US and/or are in the process of negotiating with the US on tariff agreements. These announcements have led to significant uncertainty and market volatility during the first three quarters 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 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. The US Government has also stated its interest in renegotiating and altering the USMCA, which could further impact the energy market and our business.

Any of the foregoing could significantly adversely impact our business, operations or financial results.

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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*		Amendment to Executive Employment Agreement between Enbridge Employee Services, Inc. and Cynthia Hanson, dated September 29, 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)

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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:		November 7, 2025		By:		/s/ Gregory L. Ebel
						Gregory L. Ebel
						President and Chief Executive Officer
						(Principal Executive Officer)
Date:		November 7, 2025		By:		/s/ Patrick R. Murray
						Patrick R. Murray
						Executive Vice President and Chief Financial Officer
						(Principal Financial Officer)

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FAQ

What period does Enbridge (ENB) cover in its latest quarterly report?

The report covers the quarter ended September 30, 2025.

What are Enbridge’s primary business segments?

The filing highlights Liquids Pipelines, Gas Transmission, Gas Distribution and Storage, and Renewable Power Generation.

How many Enbridge common shares were outstanding?

There were 2,181,275,613 common shares outstanding as of October 31, 2025.

Which notable transactions are referenced by ENB?

The report references the US gas utilities acquisitions from Dominion Energy, the PSNC acquisition on September 30, 2024, and the Whistler Parent JV formed May 29, 2024.

What is Enbridge’s NYSE trading symbol?

Enbridge’s common shares trade under the symbol ENB on the New York Stock Exchange.

In what currency are amounts presented?

Unless otherwise noted, amounts are presented in Canadian dollars.