0001232384-26-000015 | 40-F | XBRL Viewer

Print Document

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - Offsetting of Derivative Instruments (Details) - CAD ($) $ in Millions	Dec. 31, 2025	Dec. 31, 2024
Derivative Instrument Assets
Gross Derivative Instruments	$ 599	$ 469
Amounts Available for Offset	(420)	(339)
Net Amounts	179	130
Derivative Instrument Liabilities
Gross Derivative Instruments	(529)	(716)
Amounts Available for Offset	420	339
Net Amounts	(109)	(377)
Cash collateral provided by the Company	93	133
Letters of credit provided by the Company	73	59
Cash collateral received by the Company (less than)	1	1
Letters of credit received by the Company	102	75
Credit Risk Related Contingent Features
Aggregate fair value of derivative instruments in a net liability position	5	10
Foreign exchange
Derivative Instrument Assets
Gross Derivative Instruments	66	51
Amounts Available for Offset	(48)	(49)
Net Amounts	18	2
Derivative Instrument Liabilities
Gross Derivative Instruments	(83)	(238)
Amounts Available for Offset	48	49
Net Amounts	(35)	(189)
Interest rate
Derivative Instrument Assets
Gross Derivative Instruments	25
Amounts Available for Offset	(5)
Net Amounts	20
Derivative Instrument Liabilities
Gross Derivative Instruments	(42)	(139)
Amounts Available for Offset	5	0
Net Amounts	(37)	(139)
Power \| Commodities
Derivative Instrument Assets
Gross Derivative Instruments	508	418
Amounts Available for Offset	(367)	(290)
Net Amounts	141	128
Derivative Instrument Liabilities
Gross Derivative Instruments	(404)	(339)
Amounts Available for Offset	367	290
Net Amounts	$ (37)	$ (49)

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - Counterparty Credit Risk (Details) $ in Millions	12 Months Ended
	Dec. 31, 2025 CAD ($)	Dec. 31, 2024 CAD ($)	Dec. 31, 2023 CAD ($)	Dec. 31, 2025 USD ($)
Derivative [Line Items]
Expected credit loss provision (Note 27)	$ 83,000,000	$ (22,000,000)	$ (83,000,000)
Expected credit loss provision	351,000,000			$ 251
Provision for other credit losses	0	0
Financing receivable, recorded investment, past due	0	0
Past due or impaired	0	0
TGNH
Derivative [Line Items]
Expected credit loss provision (Note 27)	84,000,000	(23,000,000)	(73,000,000)
Expected credit loss provision	(141,000,000)	(59,000,000)
Mexico Natural Gas Pipelines
Derivative [Line Items]
Expected credit loss provision (Note 27)	$ 1,000,000	$ (1,000,000)	$ 10,000,000

- Definition

Amount of allowance for credit loss on financing receivable. Excludes allowance for financing receivable covered under loss sharing agreement.

+ References + Details

COMMON SHARES - Common Shares (Details) - Common shares	Oct. 01, 2024 shares
TC Energy
Class of Stock [Line Items]
Spinoff of Liquids Pipelines business (in shares)	1
South Bow Canadian Infrastructure Holdings Ltd
Class of Stock [Line Items]
Spinoff of Liquids Pipelines business (in shares)	0.2

- Definition

Line items represent financial concepts included in a table. These concepts are used to disclose reportable information associated with domain members defined in one or many axes to the table.

+ References

Reference 1: http://www.xbrl.org/2003/role/disclosureRef
-Topic 815
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 8A
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480434/815-10-50-8A

Reference 2: http://www.xbrl.org/2003/role/disclosureRef
-Topic 505
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 2
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147481112/505-10-50-2

Reference 3: http://www.xbrl.org/2009/role/commonPracticeRef
-Topic 235
-SubTopic 10
-Name Accounting Standards Codification
-Section S50
-Paragraph 1
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480738/235-10-S50-1

Reference 4: http://www.xbrl.org/2003/role/disclosureRef
-Topic 480
-SubTopic 10
-Name Accounting Standards Codification
-Section S50
-Paragraph 1
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147479857/480-10-S50-1

Reference 5: http://www.xbrl.org/2003/role/exampleRef
-Topic 505
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 13
-Subparagraph (d)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147481112/505-10-50-13

Reference 6: http://www.xbrl.org/2003/role/recommendedDisclosureRef
-Topic 272
-SubTopic 10
-Name Accounting Standards Codification
-Section 45
-Paragraph 3
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147483014/272-10-45-3

Reference 7: http://www.xbrl.org/2003/role/disclosureRef
-Topic 272
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 1
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482987/272-10-50-1

Reference 8: http://www.xbrl.org/2009/role/commonPracticeRef
-Topic 235
-SubTopic 10
-Name Accounting Standards Codification
-Section S99
-Paragraph 1
-Subparagraph (SX 210.4-08(d))
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480678/235-10-S99-1

Reference 9: http://www.xbrl.org/2003/role/disclosureRef
-Topic 505
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 13
-Subparagraph (a)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147481112/505-10-50-13

Reference 10: http://www.xbrl.org/2003/role/disclosureRef
-Topic 505
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 13
-Subparagraph (b)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147481112/505-10-50-13

Reference 11: http://www.xbrl.org/2003/role/disclosureRef
-Topic 505
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 13
-Subparagraph (e)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147481112/505-10-50-13

Reference 12: http://www.xbrl.org/2003/role/disclosureRef
-Topic 505
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 13
-Subparagraph (h)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147481112/505-10-50-13

Reference 13: http://www.xbrl.org/2003/role/disclosureRef
-Topic 505
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 14
-Subparagraph (b)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147481112/505-10-50-14

Reference 14: http://www.xbrl.org/2003/role/disclosureRef
-Topic 505
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 18
-Subparagraph (c)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147481112/505-10-50-18

Reference 15: http://www.xbrl.org/2003/role/disclosureRef
-Topic 210
-SubTopic 10
-Name Accounting Standards Codification
-Section S99
-Paragraph 1
-Subparagraph (SX 210.5-02(27)(b))
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480566/210-10-S99-1

Reference 16: http://www.xbrl.org/2003/role/disclosureRef
-Topic 210
-SubTopic 10
-Name Accounting Standards Codification
-Section S99
-Paragraph 1
-Subparagraph (SX 210.5-02(28))
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480566/210-10-S99-1

Reference 17: http://www.xbrl.org/2003/role/disclosureRef
-Topic 210
-SubTopic 10
-Name Accounting Standards Codification
-Section S99
-Paragraph 1
-Subparagraph (SX 210.5-02(29))
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480566/210-10-S99-1

Reference 18: http://www.xbrl.org/2003/role/disclosureRef
-Topic 946
-SubTopic 10
-Name Accounting Standards Codification
-Section S99
-Paragraph 3
-Subparagraph (SX 210.6-03(i)(2))
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147479886/946-10-S99-3

Reference 19: http://www.xbrl.org/2003/role/disclosureRef
-Topic 946
-SubTopic 10
-Name Accounting Standards Codification
-Section S99
-Paragraph 3
-Subparagraph (SX 210.6-03(i)(1))
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147479886/946-10-S99-3

Reference 20: http://www.xbrl.org/2003/role/disclosureRef
-Topic 946
-SubTopic 10
-Name Accounting Standards Codification
-Section S99
-Paragraph 3
-Subparagraph (SX 210.6-03(i)(2)(i))
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147479886/946-10-S99-3

Reference 21: http://www.xbrl.org/2003/role/disclosureRef
-Topic 946
-SubTopic 10
-Name Accounting Standards Codification
-Section S99
-Paragraph 3
-Subparagraph (SX 210.6-03(i)(2)(ii))
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147479886/946-10-S99-3

+ Details

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - Derivatives in Fair Value Hedging Relationships (Details) - CAD ($) $ in Millions	Dec. 31, 2025	Dec. 31, 2024
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Fair value hedging adjustments, discontinued hedges	$ 39	$ 41
Long-term debt \| Carrying Amount
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Long-term debt	(4,068)	(3,935)
Long-term debt \| Fair Value
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Adjustments	$ (22)	$ 98

- Definition

Line items represent financial concepts included in a table. These concepts are used to disclose reportable information associated with domain members defined in one or many axes to the table.

+ References + Details

NON-CONTROLLING INTERESTS (Details) - CAD ($) $ in Millions	12 Months Ended
NON-CONTROLLING INTERESTS (Details) - CAD ($) $ in Millions	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023	Jun. 30, 2023
Non-controlling interests
Net income (loss) attributable to non-controlling interests (Note 22)	$ 575	$ 681	$ 146
Non-Controlling Interests	$ 9,604	10,768
Common Class A \| Texas Wind Farms
Non-controlling interests
Business acquisition, percentage of voting interests acquired				100.00%
Common Class B \| Texas Wind Farms
Non-controlling interests
Business acquisition, percentage of voting interests acquired				100.00%
Columbia Gas and Columbia Gulf
Non-controlling interests
Noncontrolling Interests Ownership	40.00%
Net income (loss) attributable to non-controlling interests (Note 22)	$ 631	571	143
Non-Controlling Interests	$ 8,779	9,844
Portland Natural Gas Transmission System
Non-controlling interests
Noncontrolling Interests Ownership	0.00%
Net income (loss) attributable to non-controlling interests (Note 22)	$ 0	30	41
Non-Controlling Interests	$ 0	0
Texas Wind Farms
Non-controlling interests
Noncontrolling Interests Ownership	100.00%
Net income (loss) attributable to non-controlling interests (Note 22)	$ (38)	(29)	(38)
Non-Controlling Interests	$ 123	168
TGNH
Non-controlling interests
Noncontrolling Interests Ownership	13.01%
Net income (loss) attributable to non-controlling interests (Note 22)	$ (18)	109	$ 0
Non-Controlling Interests	$ 702	$ 756

COMMITMENTS, CONTINGENCIES AND GUARANTEES (Tables)

12 Months Ended

Dec. 31, 2025

Commitments and Contingencies Disclosure [Abstract]

Schedule of Guarantees

The carrying value of these guarantees has been recorded in Other long-term liabilities on the Consolidated balance sheet. Information regarding the Company’s guarantees were as follows:


at December 31		2025		2024
	Term	Potential Exposure1	Carrying Value	Potential Exposure1	Carrying Value
(millions of Canadian $)

Bruce Power	Renewable to 2065	88	—	88	—
Sur de Texas	Renewable to 2053	78	—	93	—
Other jointly-owned entities	to 2032	54	1	59	1
		220	1	240	1

1TC Energy's share of the potential estimated current or contingent exposure.

JUNIOR SUBORDINATED NOTES

12 Months Ended

Dec. 31, 2025

Junior Subordinated Notes [Abstract]

JUNIOR SUBORDINATED NOTES


at December 31		2025			2024
	Maturity Date	Outstanding	Effective Interest Rate1		Outstanding	Effective Interest Rate1
(millions of Canadian $, unless otherwise noted)

TRANSCANADA PIPELINES LIMITED
US$750 issued 2015 at 5.88%2,3,4	—	—	—		1,080	7.5	%
$1,000 issued 2025 at 5.20%5	2056	1,000	5.3	%	—	—
US$750 issued 2025 at 7.00%6	2065	1,028	7.2	%	—	—
US$1,000 issued 2007 at 6.35%7	2067	1,372	6.0	%	1,440	6.2	%
US$1,200 issued 2016 at 6.13%3,4	2076	1,646	7.6	%	1,729	8.0	%
US$1,500 issued 2017 at 5.55%3,4	2077	2,057	6.7	%	2,161	7.2	%
$1,500 issued 2017 at 4.90%3,4	2077	1,500	5.6	%	1,500	6.8	%
US$1,100 issued 2019 at 5.75%3,4	2079	1,509	7.3	%	1,584	7.7	%
$500 issued 2021 at 4.45%3,8	2081	500	4.5	%	500	5.7	%
US$800 issued 2022 at 5.85%3,8	2082	1,097	7.1	%	1,152	7.3	%
US$370 issued 2025 at 6.25%	2085	508	6.6	%	—	—
		12,217			11,146
Unamortized debt discount and issue costs		(123)			(98)
		12,094			11,048

1The effective interest rate is calculated by discounting the expected future interest payments using the coupon rate and any estimated future rate resets, adjusted for issue costs and discounts.

2In May 2025, TCPL exercised its option to fully repay and retire the US$750 million junior subordinated notes that had a maturity date of 2075.

3The junior subordinated notes were issued to TransCanada Trust (the Trust), a financing trust subsidiary wholly-owned by TCPL. While the obligations of the Trust are fully and unconditionally guaranteed by TCPL on a subordinated basis, the Trust is not consolidated in TC Energy's financial statements since TCPL does not have a variable interest in the Trust and the only substantive assets of the Trust are junior subordinated notes of TCPL.

4The coupon rate is initially a fixed interest rate for the first 10 years and converts to a floating rate thereafter.

5The coupon rate is initially a fixed interest rate for the first five years and resets every five years thereafter, subject to a rate-reset minimum.

6The coupon rate is initially a fixed interest rate for the first five years and resets every five years thereafter.

7Junior subordinated notes of US$1.0 billion were issued in 2007 at a fixed rate of 6.35 per cent and converted in 2017 to bear interest at a floating rate.

8The coupon rate is initially a fixed interest rate for the first 10 years and resets every five years thereafter.

Junior Subordinated Notes Issued

The Junior subordinated notes are subordinated in right of payment to existing and future senior indebtedness of TCPL.

In October 2025, TCPL issued US$370 million of junior subordinated notes maturing in 2085 with a fixed interest rate of 6.25 per cent. The junior subordinated notes are callable at TCPL's option at any time on or after November 1, 2030 at 100 per cent of the principal amount plus accrued and unpaid interest to the date of redemption.

In August 2025, TCPL issued $1.0 billion of junior subordinated notes maturing in 2056 with a fixed interest rate of 5.20 per cent per year until February 15, 2031. The rate on the junior subordinated notes will reset every five years commencing February 2031 until February 2056 to the then Five-Year Government of Canada Yield, as defined in the document governing the subordinated notes, plus 2.148 per cent per annum, subject to a rate-reset minimum. The junior subordinated notes are callable at TCPL's option at any time from November 15, 2030 to February 15, 2031 and on each interest payment and reset date thereafter at 100 per cent of the principal amount plus accrued and unpaid interest to the date of redemption.

In February 2025, TCPL issued US$750 million of junior subordinated notes maturing in 2065 with a fixed interest rate of 7.00 per cent per year until June 1, 2030, and resetting every five years thereafter. The rate on the junior subordinated notes will reset every five years commencing June 2030 until June 2065 to the then Five-Year Treasury Rate, as defined in the document governing the subordinated notes, plus 2.614 per cent per annum. The junior subordinated notes are callable at TCPL's option at any time from March 1, 2030 to June 1, 2030 and on each interest payment and reset date thereafter at 100 per cent of the principal amount plus accrued and unpaid interest to the date of redemption.

Pursuant to the terms of the junior subordinated notes issued in 2025, TCPL has the option to defer payment of interest for one or more periods of up to ten years without giving rise to an event of default and without permitting acceleration of payment. TC Energy and TCPL would be prohibited from declaring or paying dividends during any deferral period.

Junior Subordinated Notes Retired/Repaid

In May 2025, TCPL exercised its option to fully repay and retire the US$750 million junior subordinated notes that had a maturity date of 2075, bearing interest at 5.88 per cent to TransCanada Trust (the Trust). The related unamortized debt issue costs of $11 million were included in Interest expense in the Consolidated statement of income. All of the proceeds from the repayment were used by the Trust to fund the redemption price of the US$750 million in aggregate principal amount of outstanding Trust Notes - Series 2015-A, in May 2025 pursuant to their terms.

ACCOUNTING CHANGES	12 Months Ended
ACCOUNTING CHANGES	Dec. 31, 2025
Accounting Changes and Error Corrections [Abstract]
ACCOUNTING CHANGES	ACCOUNTING CHANGES Changes in Accounting Policies for 2025 Income Taxes In December 2023, the FASB issued new guidance to enhance the transparency and usefulness of income tax disclosures through improvements to the rate reconciliation and income taxes paid information. The new guidance requires entities to disclose specific categories in the rate reconciliation and sets specific disaggregation requirements for reconciling items that meet certain thresholds. Additionally, entities are required to disclose disaggregated information on income taxes paid, income from continuing operations before tax and income tax expense from continuing operations. This new guidance was effective for annual periods beginning January 1, 2025. The Company adopted the guidance on a retrospective basis. The adoption of this guidance did not have a material impact on the Company's financial position or results of operations. Refer to Note 18, Income taxes, for additional information and the effects of the new guidance. Future Accounting Changes Disaggregation of Income Statement Expenses In November 2024, the FASB issued new guidance requiring additional disclosure on the nature of expenses included in the income statement. The new standard requires disclosures about specific types of expenses included in the expense captions presented on the face of the income statement as well as disclosures about selling expenses. The new guidance is effective for annual periods beginning January 1, 2027 and interim periods beginning January 1, 2028. Early adoption is permitted. The guidance is applied prospectively with retrospective application permitted. The Company is currently assessing the impact of the standard on the Company's consolidated financial statements. Internal-Use Software In September 2025, the FASB issued updated guidance for accounting for internal-use software costs. The updated guidance removes references to project development stages and outlines revised guidance for when capitalization begins for internal-use software costs. The guidance is effective for annual and interim periods beginning January 1, 2028. Early adoption is permitted as of the beginning of an annual reporting period. The guidance can be applied prospectively, retrospectively, or with a modified transition approach. The Company is currently assessing the impact of the standard on the Company's consolidated financial statements. Hedge Accounting Improvements In November 2025, the FASB issued new guidance to further align hedge accounting with the economics of an entity's risk management activities. The amendments are intended to allow entities to achieve and maintain hedge accounting for highly effective hedges of forecasted transactions. The new guidance is effective for interim and annual reporting periods beginning January 1, 2027. Early adoption is permitted. The guidance is applied on a prospective basis for all hedging relationships that exist at the date of adoption. The Company is currently assessing the impact of the standard on the Company's consolidated financial statements. Government Grants In December 2025, the FASB established authoritative guidance on the recognition, measurement and presentation requirements for government grants received. The new guidance is effective for annual and interim periods beginning January 1, 2029. Early adoption is permitted. The guidance can be applied with a modified prospective, a modified retrospective, or a retrospective approach. The Company is currently assessing the impact of the standard on the Company's consolidated financial statements.

- Definition

The entire disclosure for change in accounting principle. Includes, but is not limited to, nature, reason, and method of adopting amendment to accounting standards or other change in accounting principle.

+ References

Reference 1: http://www.xbrl.org/2003/role/disclosureRef
-Topic 250
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 1
-Subparagraph (c)(1)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147483443/250-10-50-1

Reference 2: http://www.xbrl.org/2003/role/disclosureRef
-Topic 105
-SubTopic 10
-Name Accounting Standards Codification
-Section 65
-Paragraph 9
-Subparagraph (e)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147479343/105-10-65-9

Reference 3: http://www.xbrl.org/2003/role/disclosureRef
-Topic 718
-SubTopic 10
-Name Accounting Standards Codification
-Section 65
-Paragraph 17
-Subparagraph (d)(2)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480336/718-10-65-17

Reference 4: http://www.xbrl.org/2003/role/disclosureRef
-Topic 718
-SubTopic 10
-Name Accounting Standards Codification
-Section 65
-Paragraph 17
-Subparagraph (d)(1)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480336/718-10-65-17

Reference 5: http://www.xbrl.org/2003/role/disclosureRef
-Topic 280
-SubTopic 10
-Name Accounting Standards Codification
-Section 65
-Paragraph 1
-Subparagraph (b)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147476173/280-10-65-1

Reference 6: http://www.xbrl.org/2003/role/disclosureRef
-Topic 250
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 1
-Subparagraph (b)(4)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147483443/250-10-50-1

Reference 7: http://www.xbrl.org/2003/role/disclosureRef
-Topic 105
-SubTopic 10
-Name Accounting Standards Codification
-Section 65
-Paragraph 7
-Subparagraph (a)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147479343/105-10-65-7

Reference 8: http://www.xbrl.org/2003/role/disclosureRef
-Topic 805
-SubTopic 60
-Name Accounting Standards Codification
-Section 65
-Paragraph 1
-Subparagraph (g)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147476176/805-60-65-1

Reference 9: http://www.xbrl.org/2003/role/disclosureRef
-Topic 848
-SubTopic 10
-Name Accounting Standards Codification
-Section 65
-Paragraph 2
-Subparagraph (c)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147483550/848-10-65-2

Reference 10: http://www.xbrl.org/2003/role/disclosureRef
-Topic 740
-SubTopic 323
-Name Accounting Standards Codification
-Section 65
-Paragraph 2
-Subparagraph (g)(2)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147478666/740-323-65-2

Reference 11: http://www.xbrl.org/2003/role/disclosureRef
-Topic 740
-SubTopic 323
-Name Accounting Standards Codification
-Section 65
-Paragraph 2
-Subparagraph (g)(4)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147478666/740-323-65-2

Reference 12: http://www.xbrl.org/2003/role/disclosureRef
-Topic 740
-SubTopic 323
-Name Accounting Standards Codification
-Section 65
-Paragraph 2
-Subparagraph (g)(1)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147478666/740-323-65-2

Reference 13: http://www.xbrl.org/2003/role/disclosureRef
-Topic 848
-SubTopic 10
-Name Accounting Standards Codification
-Section 65
-Paragraph 2
-Subparagraph (d)(1)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147483550/848-10-65-2

Reference 14: http://www.xbrl.org/2003/role/disclosureRef
-Topic 848
-SubTopic 10
-Name Accounting Standards Codification
-Section 65
-Paragraph 1
-Subparagraph (e)(1)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147483550/848-10-65-1

Reference 15: http://www.xbrl.org/2003/role/disclosureRef
-Topic 944
-SubTopic 40
-Name Accounting Standards Codification
-Section 65
-Paragraph 2
-Subparagraph (g)(2)(i)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480016/944-40-65-2

Reference 16: http://www.xbrl.org/2003/role/disclosureRef
-Topic 944
-SubTopic 40
-Name Accounting Standards Codification
-Section 65
-Paragraph 2
-Subparagraph (g)(2)(ii)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480016/944-40-65-2

Reference 17: http://www.xbrl.org/2003/role/disclosureRef
-Topic 944
-SubTopic 40
-Name Accounting Standards Codification
-Section 65
-Paragraph 2
-Subparagraph (g)(2)(iii)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480016/944-40-65-2

Reference 18: http://www.xbrl.org/2003/role/disclosureRef
-Topic 944
-SubTopic 40
-Name Accounting Standards Codification
-Section 65
-Paragraph 2
-Subparagraph (g)(2)(iv)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480016/944-40-65-2

Reference 19: http://www.xbrl.org/2003/role/disclosureRef
-Topic 944
-SubTopic 40
-Name Accounting Standards Codification
-Section 65
-Paragraph 2
-Subparagraph (h)(2)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480016/944-40-65-2

Reference 20: http://www.xbrl.org/2003/role/disclosureRef
-Topic 250
-SubTopic 10
-Name Accounting Standards Codification
-Section S99
-Paragraph 5
-Subparagraph (SAB Topic 11.M.Q2)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480530/250-10-S99-5

Reference 21: http://www.xbrl.org/2003/role/disclosureRef
-Topic 815
-SubTopic 20
-Name Accounting Standards Codification
-Section 65
-Paragraph 6
-Subparagraph (i)(1)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480528/815-20-65-6

Reference 22: http://www.xbrl.org/2003/role/disclosureRef
-Topic 250
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 1
-Subparagraph (a)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147483443/250-10-50-1

Reference 23: http://www.xbrl.org/2003/role/disclosureRef
-Topic 326
-SubTopic 10
-Name Accounting Standards Codification
-Section 65
-Paragraph 4
-Subparagraph (e)(1)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147479654/326-10-65-4

Reference 24: http://www.xbrl.org/2003/role/disclosureRef
-Topic 326
-SubTopic 10
-Name Accounting Standards Codification
-Section 65
-Paragraph 4
-Subparagraph (e)(2)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147479654/326-10-65-4

Reference 25: http://www.xbrl.org/2003/role/disclosureRef
-Topic 250
-SubTopic 10
-Name Accounting Standards Codification
-Section S99
-Paragraph 6
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480530/250-10-S99-6

Reference 26: http://www.xbrl.org/2003/role/disclosureRef
-Topic 470
-SubTopic 20
-Name Accounting Standards Codification
-Section 65
-Paragraph 4
-Subparagraph (f)(1)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147481538/470-20-65-4

Reference 27: http://www.xbrl.org/2003/role/disclosureRef
-Topic 470
-SubTopic 20
-Name Accounting Standards Codification
-Section 65
-Paragraph 4
-Subparagraph (e)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147481538/470-20-65-4

Reference 28: http://www.xbrl.org/2003/role/disclosureRef
-Topic 250
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 1
-Subparagraph (b)(1)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147483443/250-10-50-1

Reference 29: http://www.xbrl.org/2003/role/disclosureRef
-Name Accounting Standards Codification
-Topic 250
-Publisher FASB
-URI https://asc.fasb.org/250/tableOfContent

Reference 30: http://www.xbrl.org/2003/role/disclosureRef
-Topic 815
-SubTopic 40
-Name Accounting Standards Codification
-Section 65
-Paragraph 1
-Subparagraph (e)(1)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480175/815-40-65-1

+ Details

LONG-TERM DEBT - Narrative (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Debt Disclosure [Abstract]
Interest payments, net of interest capitalized	$ 3,284	$ 3,398	$ 2,931

PREFERRED SHARES (Tables)

12 Months Ended

Dec. 31, 2025

Preferred Stock, Number of Shares, Par Value and Other Disclosure [Abstract]

Schedule of Preferred Shares


at December 31, 2025	Number of Shares Outstanding	Current Yield			Annual Dividend Per Share1,2	Redemption Price Per Share	Redemption and Conversion Option Date		Right to Convert Into	Carrying Value December 313
										2025	2024	2023
	(thousands)									(millions of Canadian $)

Cumulative First Preferred Shares
Series 1	18,424	4.94	%	4	$1.23475	$25.00	December 31, 2029		Series 2	456	456	360
Series 2	3,576	Floating		5	Floating	$25.00	December 31, 2029		Series 1	83	83	179
Series 3	11,715	4.10	%	4	$1.0255	$25.00	June 30, 2030	6	Series 4	289	246	246
Series 4	2,285	Floating		5	Floating	$25.00	June 30, 2030	6	Series 3	54	97	97
Series 5	12,071	1.95	%		$0.48725	$25.00	January 30, 2026		Series 6	294	294	294
Series 6	1,929	Floating		5	Floating	$25.00	January 30, 2026		Series 5	48	48	48
Series 7	24,000	5.99	%	4	$1.49625	$25.00	April 30, 2029		Series 8	589	589	589
Series 9	16,703	5.08	%	4	$1.27	$25.00	October 30, 2029		Series 10	410	410	442
Series 10	1,297	Floating		5	Floating	$25.00	October 30, 2029		Series 9	32	32	—
Series 11	—	—			—	—	—		—	—	244	244

										2,255	2,499	2,499

1Each of the even-numbered series of preferred shares, if in existence, will be entitled to receive floating rate cumulative quarterly preferential dividends per share at an annualized rate equal to the 90-day Government of Canada Treasury bill rate (T-Bill rate) plus 1.92 per cent (Series 2), 1.28 per cent (Series 4), 1.54 per cent (Series 6), 2.38 per cent (Series 8), or 2.35 per cent (Series 10). These rates reset quarterly with the then current T-Bill rate.

2The odd-numbered series of preferred shares, if in existence, will be entitled to receive fixed rate cumulative quarterly preferential dividends, which will reset on the redemption and conversion option date and every fifth year thereafter, at an annualized rate equal to the then Five-Year Government of Canada bond yield plus 1.92 per cent (Series 1), 1.28 per cent (Series 3), 1.54 per cent (Series 5), 2.38 per cent (Series 7), or 2.35 per cent (Series 9).

3Net of underwriting commissions and deferred income taxes.

4The fixed rate dividend for Series 3 preferred shares increased from 1.69 per cent to 4.10 per cent on June 30, 2025, and is due to reset on every fifth anniversary thereafter. The fixed rate dividends for Series 1, Series 7 and Series 9 preferred shares increased from 3.48 per cent to 4.94 per cent on December 31, 2024, 3.90 per cent to 5.99 per cent on April 30, 2024 and from 3.76 per cent to 5.08 per cent on October 30, 2024, respectively, and are due to reset on every fifth anniversary thereafter. No Series 7 preferred shares were converted on the April 30, 2024 conversion date.

5The floating quarterly dividend rate for the Series 2 preferred shares is 4.14 per cent for the period starting December 31, 2025 to, but excluding, March 31, 2026. The floating quarterly dividend rate for the Series 4 preferred shares is 3.50 per cent for the period starting December 31, 2025 to, but excluding, March 31, 2026. The floating quarterly dividend rate for the Series 6 preferred shares is 3.97 per cent for the period starting October 30, 2025 to, but excluding, January 30, 2026 The floating quarterly dividend rate for the Series 10 preferred shares is 4.78 per cent for the period starting October 30, 2025 to, but excluding, January 30, 2026. These rates will reset each quarter going forward.

6Adjusted to July 2, 2030 to account for applicable business days.

- Definition

Tabular disclosure of an entity's stock, including par or stated value per share, number and dollar amount of share subscriptions, shares authorized, shares issued, shares outstanding, number and dollar amount of shares held in an employee trust, dividend per share, total dividends, share conversion features, par value plus additional paid in capital, the value of treasury stock and other information necessary to a fair presentation, and EPS information. Stock by class includes common, convertible, and preferred stocks which are not redeemable or redeemable solely at the option of the issuer. Includes preferred stock with redemption features that are solely within the control of the issuer and mandatorily redeemable stock if redemption is required to occur only upon liquidation or termination of the reporting entity. If more than one issue is outstanding, state the title of each issue and the corresponding dollar amount; dollar amount of any shares subscribed but unissued and the deduction of subscriptions receivable there from; number of shares authorized, issued, and outstanding.

+ References

Reference 1: http://fasb.org/us-gaap/role/ref/legacyRef
-Name Accounting Standards Codification
-Section S99
-Paragraph 1
-Subparagraph (SX 210.5-02(27))
-SubTopic 10
-Topic 210
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480566/210-10-S99-1

Reference 2: http://fasb.org/us-gaap/role/ref/legacyRef
-Topic 210
-SubTopic 10
-Name Accounting Standards Codification
-Section S99
-Paragraph 1
-Subparagraph (SX 210.5-02(28))
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480566/210-10-S99-1

Reference 3: http://fasb.org/us-gaap/role/ref/legacyRef
-Topic 210
-SubTopic 10
-Name Accounting Standards Codification
-Section S99
-Paragraph 1
-Subparagraph (SX 210.5-02(29))
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480566/210-10-S99-1

Reference 4: http://fasb.org/us-gaap/role/ref/legacyRef
-Topic 505
-SubTopic 10
-Name Accounting Standards Codification
-Section S99
-Paragraph 1
-Subparagraph (SX 210.3-04)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480008/505-10-S99-1

Reference 5: http://fasb.org/us-gaap/role/ref/legacyRef
-Name Accounting Standards Codification
-Topic 505
-SubTopic 10
-Section 50
-Paragraph 3
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147481112/505-10-50-3

Reference 6: http://fasb.org/us-gaap/role/ref/legacyRef
-Name Accounting Standards Codification
-Topic 505
-SubTopic 10
-Section 50
-Paragraph 4
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147481112/505-10-50-4

Reference 7: http://fasb.org/us-gaap/role/ref/legacyRef
-Name Accounting Standards Codification
-Topic 505
-SubTopic 10
-Section 50
-Paragraph 5
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147481112/505-10-50-5

Reference 8: http://fasb.org/us-gaap/role/ref/legacyRef
-Name Accounting Standards Codification
-Topic 505
-SubTopic 10
-Section 45
-Paragraph 2
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147481142/505-10-45-2

Reference 9: http://fasb.org/us-gaap/role/ref/legacyRef
-Name Accounting Standards Codification
-Topic 505
-SubTopic 10
-Section 50
-Paragraph 10
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147481112/505-10-50-10

Reference 10: http://fasb.org/us-gaap/role/ref/legacyRef
-Name Accounting Standards Codification
-Topic 505
-SubTopic 10
-Section 50
-Paragraph 8
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147481112/505-10-50-8

Reference 11: http://fasb.org/us-gaap/role/ref/legacyRef
-Topic 505
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 6
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147481112/505-10-50-6

Reference 12: http://fasb.org/us-gaap/role/ref/legacyRef
-Topic 505
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 7
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147481112/505-10-50-7

+ Details

Cover Page	12 Months Ended
Cover Page	Dec. 31, 2025 shares
Entity Information [Line Items]
Document Type	40-F
Document Registration Statement	false
Document Annual Report	true
Document Period End Date	Dec. 31, 2025
Current Fiscal Year End Date	--12-31
Entity Registrant Name	TC ENERGY CORPORATION
Entity File Number	1-31690
Entity Incorporation, State or Country Code	Z4
Entity Primary SIC Number	4922
Entity Address, Address Line One	TC Energy Tower, 450 - 1 Street S.W.
Entity Address, City or Town	Calgary
Entity Address, State or Province	AB
Entity Address, Country	CA
Entity Address, Postal Zip Code	T2P 5H1
City Area Code	403
Local Phone Number	920-2000
Title of 12(b) Security	Common Shares (including Rights under Shareholder Rights Plan) of TC Energy Corporation
Trading Symbol	TRP
Security Exchange Name	NYSE
Annual Information Form	true
Audited Annual Financial Statements	true
Entity Common Stock, Shares Outstanding	1,040,835,168
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Emerging Growth Company	false
ICFR Auditor Attestation Flag	true
Document Financial Statement Error Correction [Flag]	false
Entity Central Index Key	0001232384
Amendment Flag	false
Document Fiscal Year Focus	2025
Document Fiscal Period Focus	FY
TRANSCANADA PIPELINES LIMITED
Entity Information [Line Items]
Entity Registrant Name	TRANSCANADA PIPELINES LIMITED
Entity File Number	1-8887
Entity Tax Identification Number	52-2179728
Security Reporting Obligation	15(d)
Entity Common Stock, Shares Outstanding	992,720,977
Entity Central Index Key	0000099070
Amendment Flag	false
Document Fiscal Year Focus	2025
Document Fiscal Period Focus	FY
Business contact
Entity Information [Line Items]
Entity Address, Address Line One	700 Louisiana Street
Entity Address, Address Line Two	Suite 700
Entity Address, City or Town	Houston
Entity Address, State or Province	TX
Entity Address, Postal Zip Code	77002-2700
Contact Personnel Name	TransCanada PipeLine USA Ltd
City Area Code	832
Local Phone Number	320-5201

EQUITY INVESTMENTS - Ownership Information of Equity Investments (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Equity Investments
Income (Loss) from Equity Investments	$ 1,274	$ 1,558	$ 1,310
Equity Investments	$ 11,358	10,636
TQM \| Canadian Natural Gas Pipelines
Equity Investments
Ownership interest percentage	50.00%
Income (Loss) from Equity Investments	$ 17	17	17
Equity Investments	158	$ 160
Coastal GasLink \| Canadian Natural Gas Pipelines
Equity Investments
Ownership interest percentage		35.00%
Income (Loss) from Equity Investments	95	$ 17	203
Equity Investments	$ 896	1,006
Northern Border \| U.S. Natural Gas Pipelines
Equity Investments
Ownership interest percentage	50.00%
Income (Loss) from Equity Investments	$ 145	130	101
Equity Investments	$ 766	647
Millennium \| U.S. Natural Gas Pipelines
Equity Investments
Ownership interest percentage	47.50%
Income (Loss) from Equity Investments	$ 70	95	109
Equity Investments	$ (22)	(21)
Iroquois \| U.S. Natural Gas Pipelines
Equity Investments
Ownership interest percentage	50.00%
Income (Loss) from Equity Investments	$ 70	100	98
Equity Investments	216	221
Other \| U.S. Natural Gas Pipelines
Equity Investments
Income (Loss) from Equity Investments	16	16	16
Equity Investments	137	135
Other \| Power and Energy Solutions
Equity Investments
Income (Loss) from Equity Investments	0	0	(2)
Equity Investments	$ 0	42
Sur de Texas \| Mexico Natural Gas Pipelines
Equity Investments
Ownership interest percentage	60.00%
Income (Loss) from Equity Investments	$ 94	283	78
Equity Investments	$ 1,427	1,403
Bruce Power \| Power and Energy Solutions
Equity Investments
Ownership interest percentage	48.30%
Income (Loss) from Equity Investments	$ 767	900	$ 690
Equity Investments	$ 7,780	$ 7,043

PREFERRED SHARES - Schedule of Preferred Shares (Details) - CAD ($) $ / shares in Units, shares in Thousands, $ in Millions						1 Months Ended				12 Months Ended
	Nov. 28, 2025	Jun. 30, 2025	Dec. 31, 2024	Oct. 31, 2024	Apr. 30, 2024	Jun. 29, 2025	Dec. 30, 2024	Oct. 30, 2024	Apr. 29, 2024	Dec. 31, 2025	Dec. 31, 2023
Class of Stock [Line Items]
Preferred shares			$ 2,499							$ 2,255	$ 2,499
Series 1
Class of Stock [Line Items]
Number of shares outstanding (in shares)										18,424
Current yield (as a percent)			4.94%				3.48%			4.94%
Annual dividend ( in Canadian dollars per share)										$ 1.23475
Redemption price per share (in Canadian dollars per share)										$ 25.00
Preferred shares			$ 456							$ 456	360
Series 1 \| Government of Canada, Five-Year Bond Yield
Class of Stock [Line Items]
Fixed percentage added to government of Canada bond or treasury bill rate, for calculating dividend yield per annum (as a percent)										1.92%
Series 2
Class of Stock [Line Items]
Number of shares outstanding (in shares)										3,576
Current yield (as a percent)										4.14%
Redemption price per share (in Canadian dollars per share)										$ 25.00
Preferred shares			83							$ 83	179
Series 2 \| Government of Canada, Treasury Bill Rate
Class of Stock [Line Items]
Fixed percentage added to government of Canada bond or treasury bill rate, for calculating dividend yield per annum (as a percent)										1.92%
Series 3
Class of Stock [Line Items]
Number of shares outstanding (in shares)										11,715
Current yield (as a percent)		4.10%				1.69%				4.10%
Annual dividend ( in Canadian dollars per share)										$ 1.0255
Redemption price per share (in Canadian dollars per share)										$ 25.00
Preferred shares			246							$ 289	246
Series 3 \| Government of Canada, Five-Year Bond Yield
Class of Stock [Line Items]
Fixed percentage added to government of Canada bond or treasury bill rate, for calculating dividend yield per annum (as a percent)										1.28%
Series 4
Class of Stock [Line Items]
Number of shares outstanding (in shares)										2,285
Current yield (as a percent)										3.50%
Redemption price per share (in Canadian dollars per share)										$ 25.00
Preferred shares			97							$ 54	97
Series 4 \| Government of Canada, Treasury Bill Rate
Class of Stock [Line Items]
Fixed percentage added to government of Canada bond or treasury bill rate, for calculating dividend yield per annum (as a percent)										1.28%
Series 5
Class of Stock [Line Items]
Number of shares outstanding (in shares)										12,071
Current yield (as a percent)										1.95%
Annual dividend ( in Canadian dollars per share)										$ 0.48725
Redemption price per share (in Canadian dollars per share)										$ 25.00
Preferred shares			294							$ 294	294
Series 5 \| Government of Canada, Five-Year Bond Yield
Class of Stock [Line Items]
Fixed percentage added to government of Canada bond or treasury bill rate, for calculating dividend yield per annum (as a percent)										1.54%
Series 6
Class of Stock [Line Items]
Number of shares outstanding (in shares)										1,929
Current yield (as a percent)										3.97%
Redemption price per share (in Canadian dollars per share)										$ 25.00
Preferred shares			48							$ 48	48
Series 6 \| Government of Canada, Treasury Bill Rate
Class of Stock [Line Items]
Fixed percentage added to government of Canada bond or treasury bill rate, for calculating dividend yield per annum (as a percent)										1.54%
Series 7
Class of Stock [Line Items]
Number of shares outstanding (in shares)										24,000
Current yield (as a percent)					5.99%				3.90%	5.99%
Annual dividend ( in Canadian dollars per share)										$ 1.49625
Redemption price per share (in Canadian dollars per share)										$ 25.00
Preferred shares			589							$ 589	589
Series 7 \| Government of Canada, Five-Year Bond Yield
Class of Stock [Line Items]
Fixed percentage added to government of Canada bond or treasury bill rate, for calculating dividend yield per annum (as a percent)										2.38%
Series 9
Class of Stock [Line Items]
Number of shares outstanding (in shares)										16,703
Current yield (as a percent)				5.08%				3.76%		5.08%
Annual dividend ( in Canadian dollars per share)										$ 1.27
Redemption price per share (in Canadian dollars per share)										$ 25.00
Preferred shares			410							$ 410	442
Series 9 \| Government of Canada, Five-Year Bond Yield
Class of Stock [Line Items]
Fixed percentage added to government of Canada bond or treasury bill rate, for calculating dividend yield per annum (as a percent)										2.35%
Series 10
Class of Stock [Line Items]
Number of shares outstanding (in shares)										1,297
Current yield (as a percent)										4.78%
Redemption price per share (in Canadian dollars per share)										$ 25.00
Preferred shares			32							$ 32	0
Series 10 \| Government of Canada, Treasury Bill Rate
Class of Stock [Line Items]
Fixed percentage added to government of Canada bond or treasury bill rate, for calculating dividend yield per annum (as a percent)										2.35%
Series 11
Class of Stock [Line Items]
Number of shares outstanding (in shares)										0
Current yield (as a percent)										0.00%
Annual dividend ( in Canadian dollars per share)	$ 0.2094375									$ 0
Redemption price per share (in Canadian dollars per share)	$ 25.00									$ 0
Preferred shares			$ 244							$ 0	$ 244
Even numbered series of preferred shares
Class of Stock [Line Items]
Period of Government of Canada bond or treasury bill considered for calculation of dividend yield per annum										90 days
Series 8 \| Government of Canada, Treasury Bill Rate
Class of Stock [Line Items]
Fixed percentage added to government of Canada bond or treasury bill rate, for calculating dividend yield per annum (as a percent)										2.38%
Odd numbered series of preferred shares
Class of Stock [Line Items]
Period of time preferred stock or bond is considered for dividend yield calculation										5 years

SEGMENTED INFORMATION (Tables)

12 Months Ended

Dec. 31, 2025

Segment Reporting [Abstract]

Schedule of Segment Reporting Information, by Segment

Information regarding the Company's business segments is as follows:


year ended December 31, 2025	Canadian Natural Gas Pipelines	U.S. Natural Gas Pipelines	Mexico Natural Gas Pipelines	Power and Energy Solutions	Corporate		Total
(millions of Canadian $)						1

Revenues	5,785	7,145	1,450	845	14		15,239
Intersegment revenues2	—	99	—	52	(151)		—
	5,785	7,244	1,450	897	(137)		15,239
Income (loss) from equity investments	112	301	94	767	—		1,274





Operating costs2	(2,210)	(2,581)	(262)	(778)	123		(5,708)
Depreciation and amortization	(1,523)	(1,037)	(96)	(113)	—		(2,769)

Segmented Earnings (Losses)	2,164	3,927	1,186	773	(14)		8,036
Interest expense							(3,407)
Allowance for funds used during construction							453
Foreign exchange gains (losses), net							157
Interest income and other							205
Income (Loss) from Continuing Operations before Income Taxes							5,444
Income tax (expense) recovery from continuing operations							(1,138)
Net Income (Loss) from Continuing Operations							4,306
Net Income (Loss) from Discontinued Operations, Net of Tax							(212)
Net Income (Loss)							4,094
Net (income) loss attributable to non-controlling interests							(575)
Net Income (Loss) Attributable to Controlling Interests							3,519
Preferred share dividends							(119)
Net Income (Loss) Attributable to Common Shares							3,400

Capital Spending3
Capital expenditures	1,340	3,316	522	61	31		5,270
Capital projects in development	—	—	—	16	—		16
Contributions to equity investments	65	141	—	845	—		1,051
	1,405	3,457	522	922	31		6,337

1Includes intersegment eliminations.

2The Company records intersegment sales at contracted rates. For segmented reporting, these transactions are included as Intersegment revenues in the segment providing the service and Operating costs in the segment receiving the service. These transactions are eliminated on consolidation. Intersegment profit is recognized when the product or service has been provided to third parties or otherwise realized.

3Included in Investing activities in the Consolidated statement of cash flows.


year ended December 31, 2024	Canadian Natural Gas Pipelines	U.S. Natural Gas Pipelines	Mexico Natural Gas Pipelines	Power and Energy Solutions	Corporate		Total
(millions of Canadian $)						1

Revenues	5,600	6,339	870	954	8		13,771
Intersegment revenues2	—	99	—	49	(148)		—
	5,600	6,438	870	1,003	(140)		13,771

Income (loss) from equity investments	34	341	283	900	—		1,558


Operating costs2	(2,246)	(2,381)	(132)	(700)	9	3	(5,450)
Depreciation and amortization	(1,382)	(955)	(92)	(101)	(5)	3	(2,535)
Other segment items4	10	610	—	—	—		620
Segmented Earnings (Losses)	2,016	4,053	929	1,102	(136)		7,964
Interest expense							(3,019)
Allowance for funds used during construction							784
Foreign exchange gains (losses), net							(147)
Interest income and other							324
Income (Loss) from Continuing Operations before Income Taxes							5,906
Income tax (expense) recovery from continuing operations							(922)
Net Income (Loss) from Continuing Operations							4,984
Net income (loss) from Discontinued Operations, Net of Tax							395
Net Income (Loss)							5,379
Net Income (loss) attributable to non-controlling interests							(681)
Net Income (Loss) Attributable to Controlling Interests							4,698
Preferred share dividends							(104)
Net Income (Loss) Attributable to Common Shares							4,594

Capital Spending5
Capital expenditures	1,273	2,568	2,228	62	50		6,181
Capital projects in development	—	5	—	45	—		50
Contributions to equity investments6	827	2	—	717	—		1,546
	2,100	2,575	2,228	824	50		7,777
Discontinued operations							127
							7,904

1Includes intersegment eliminations.

3Includes shared costs and depreciation previously allocated to the Liquids Pipelines segment. Refer to Note 4, Discontinued operations, for additional information.

4Other segment items include a Net gain (loss) on sale of assets.

5Included in Investing activities in the Consolidated statement of cash flows.

6Contributions to equity investments in the Canadian Natural Gas Pipelines segment of $3.1 billion are offset by the equivalent amount in Other distributions from equity investments, although they are reported on a gross basis in the Company’s Consolidated statement of cash flows. Refer to Note 10, Equity investments, for additional information.


year ended December 31, 2023	Canadian Natural Gas Pipelines	U.S. Natural Gas Pipelines	Mexico Natural Gas Pipelines	Power and Energy Solutions	Corporate		Total
(millions of Canadian $)						1

Revenues	5,173	6,229	846	1,019	—		13,267
Intersegment revenues2	—	101	—	22	(123)		—
	5,173	6,330	846	1,041	(123)		13,267
Income (loss) from equity investments	220	324	78	688	—		1,310
Impairment of equity investment	(2,100)	—	—	—	—		(2,100)




Operating costs2	(2,058)	(2,189)	(39)	(633)	(15)	3	(4,934)
Depreciation and amortization	(1,325)	(934)	(89)	(92)	(6)	3	(2,446)



Segmented Earnings (Losses)	(90)	3,531	796	1,004	(144)		5,097
Interest expense							(2,966)
Allowance for funds used during construction							575
Foreign exchange gains (losses), net							320
Interest income and other							272
Income (Loss) from Continuing Operations before Income Taxes							3,298
Income tax (expense) recovery from continuing operations							(842)
Net Income (Loss) from Continuing Operations							2,456
Net Income (Loss) from Discontinued Operations, Net of Tax							612
Net Income (Loss)							3,068
Net (income) loss attributable to non-controlling interests							(146)
Net Income (Loss) Attributable to Controlling Interests							2,922
Preferred share dividends							(93)
Net Income (Loss) Attributable to Common Shares							2,829

Capital Spending4
Capital expenditures	2,953	2,536	2,292	144	33		7,958
Capital projects in development	—	—	—	142	—		142
Contributions to equity investments	3,231	124	—	794	—		4,149
	6,184	2,660	2,292	1,080	33		12,249
Discontinued operations							49
							12,298

1Includes intersegment eliminations.

3Includes shared costs and depreciation previously allocated to the Liquids Pipelines segment. Refer to Note 4, Discontinued operations, for additional information.

4Included in Investing activities in the Consolidated statement of cash flows.


at December 31	2025	2024
(millions of Canadian $)

Total Assets by Segment
Canadian Natural Gas Pipelines	31,371	31,167
U.S. Natural Gas Pipelines	56,617	56,304
Mexico Natural Gas Pipelines	16,342	15,995
Power and Energy Solutions	10,764	10,217
Corporate	3,460	4,189
	118,554	117,872
Discontinued Operations	197	371
	118,751	118,243

Schedule of Revenue from External Customers by Geographic Areas


year ended December 31	2025	2024	2023
(millions of Canadian $)

Revenues
Canada – domestic	5,617	5,579	5,337
Canada – export	968	953	821
United States	7,204	6,369	6,263
Mexico	1,450	870	846
	15,239	13,771	13,267

Schedule of Long-Lived Assets by Country


at December 31	2025	2024
(millions of Canadian $)

Plant, Property and Equipment
Canada	26,078	26,354
United States	40,976	40,580
Mexico	4,000	10,567
	71,054	77,501

COMMON SHARES (Tables)

12 Months Ended

Dec. 31, 2025

Common Stock, Number of Shares, Par Value and Other Disclosure [Abstract]

Schedule of Common Shares


	Number of Shares	Amount
	(thousands)	(millions of Canadian $)

Outstanding at January 1, 2023	1,017,962	28,995
Dividend reinvestment and share purchase plan	19,464	1,003
Exercise of options	62	4
Outstanding at December 31, 2023	1,037,488	30,002

Exercise of options	1,607	99
Outstanding at December 31, 2024	1,039,095	30,101




Exercise of options	1,740	117
Outstanding at December 31, 2025	1,040,835	30,218

Schedule of Weighted Average Shares


Weighted Average Common Shares Outstanding
at December 31
(millions)	2025	2024	2023

Basic	1,040	1,038	1,030
Diluted	1,040	1,038	1,030

Schedule of Stock Options Activity


	Number of Options	Weighted Average Exercise Prices1	Weighted Average Remaining Contractual Life
	(thousands)		(years)

Options outstanding at January 1, 2025	4,474	$60.69

Options exercised	(1,740)	$59.34
Options forfeited/expired	(373)	$62.77
Options Outstanding at December 31, 2025	2,361	$61.37	2.8
Options Exercisable at December 31, 2025	1,898	$63.22	2.4

1 Exercise prices of TC Energy stock options were adjusted in 2024 for the change in value of the TC Energy common shares following the Spinoff Transaction.

Schedule of Options Valuation Assumptions

The Company used a binomial model for determining the fair value of options granted and applied the following weighted average assumptions:


year ended December 31	2023

Weighted average fair value	$7.88
Expected life (years)1	5.1
Interest rate	2.9	%
Volatility2	24	%
Dividend yield	6.3	%

1Expected life is based on historical exercise activity.

2Volatility is derived based on the average of both the historical and implied volatility of the Company's common shares.

Schedule of Additional Option Information

The following table summarizes additional stock option information:


year ended December 31	2025	2024	2023
(millions of Canadian $, unless otherwise noted)

Total intrinsic value of options exercised	20	17	—
Total fair value of options that have vested	62	99	76
Total options vested	0.8 million	1.5 million	1.5 million

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - U.S. Dollar-Denominated Debt Designated as Net Investment Hedges (Details) - Designated as a net investment hedge $ in Millions, $ in Millions	Dec. 31, 2025 CAD ($)	Dec. 31, 2025 USD ($)	Dec. 31, 2024 CAD ($)	Dec. 31, 2024 USD ($)
Derivative [Line Items]
Notional amount	$ 25,700		$ 26,000
Fair value	$ 25,800		$ 25,700
US$ denominated
Derivative [Line Items]
Notional amount		$ 18,700		$ 18,000
Fair value		$ 18,800		$ 17,800

- Definition

Fair value portion of debt instrument payable, including, but not limited to, notes payable and loans payable.

+ References

Reference 1: http://www.xbrl.org/2009/role/commonPracticeRef
-Topic 820
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 2
-Subparagraph (bbb)(2)(i)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482106/820-10-50-2

Reference 2: http://www.xbrl.org/2009/role/commonPracticeRef
-Topic 820
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 2
-Subparagraph (bbb)(2)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482106/820-10-50-2

Reference 3: http://www.xbrl.org/2009/role/commonPracticeRef
-Topic 820
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 2
-Subparagraph (bbb)(1)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482106/820-10-50-2

Reference 4: http://www.xbrl.org/2003/role/disclosureRef
-Topic 825
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 28
-Subparagraph (c)(1)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482907/825-10-50-28

Reference 5: http://www.xbrl.org/2003/role/disclosureRef
-Topic 825
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 11
-Subparagraph (b)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482907/825-10-50-11

Reference 6: http://www.xbrl.org/2003/role/disclosureRef
-Topic 825
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 11
-Subparagraph (a)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482907/825-10-50-11

Reference 7: http://www.xbrl.org/2003/role/disclosureRef
-Topic 825
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 10
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482907/825-10-50-10

Reference 8: http://www.xbrl.org/2009/role/commonPracticeRef
-Topic 820
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 2
-Subparagraph (b)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482106/820-10-50-2

Reference 9: http://www.xbrl.org/2009/role/commonPracticeRef
-Topic 820
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 2E
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482106/820-10-50-2E

Reference 10: http://www.xbrl.org/2003/role/exampleRef
-Topic 470
-SubTopic 20
-Name Accounting Standards Codification
-Section 55
-Paragraph 69B
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147481568/470-20-55-69B

Reference 11: http://www.xbrl.org/2003/role/exampleRef
-Topic 470
-SubTopic 20
-Name Accounting Standards Codification
-Section 55
-Paragraph 69C
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147481568/470-20-55-69C

Reference 12: http://www.xbrl.org/2003/role/disclosureRef
-Topic 470
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 1D
-Subparagraph (c)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147481139/470-20-50-1D

+ Details

FOREIGN EXCHANGE (GAINS) LOSSES, NET (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Components of OCI related to derivatives
Foreign exchange (gains) losses	$ (157)	$ 147	$ (320)
Derivative instruments held for trading (Note 27)
Components of OCI related to derivatives
Foreign exchange (gains) losses	(352)	418	(401)
Other
Components of OCI related to derivatives
Foreign exchange (gains) losses	$ 195	$ (271)	$ 81

- Definition

Line items represent financial concepts included in a table. These concepts are used to disclose reportable information associated with domain members defined in one or many axes to the table.

+ References

Reference 1: http://www.xbrl.org/2003/role/disclosureRef
-Topic 815
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 4C
-Subparagraph (a)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480434/815-10-50-4C

Reference 2: http://www.xbrl.org/2003/role/exampleRef
-Topic 815
-SubTopic 10
-Name Accounting Standards Codification
-Section 55
-Paragraph 182
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480401/815-10-55-182

Reference 3: http://www.xbrl.org/2003/role/disclosureRef
-Topic 815
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 4D
-Subparagraph (a)(5)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480434/815-10-50-4D

Reference 4: http://www.xbrl.org/2003/role/disclosureRef
-Topic 815
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 4D
-Subparagraph (a)(4)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480434/815-10-50-4D

Reference 5: http://www.xbrl.org/2003/role/disclosureRef
-Topic 815
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 4D
-Subparagraph (a)(3)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480434/815-10-50-4D

Reference 6: http://www.xbrl.org/2003/role/disclosureRef
-Topic 815
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 4D
-Subparagraph (a)(2)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480434/815-10-50-4D

Reference 7: http://www.xbrl.org/2003/role/disclosureRef
-Topic 815
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 4A
-Subparagraph (b)(1)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480434/815-10-50-4A

Reference 8: http://www.xbrl.org/2003/role/disclosureRef
-Topic 815
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 4D
-Subparagraph (a)(6)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480434/815-10-50-4D

Reference 9: http://www.xbrl.org/2003/role/disclosureRef
-Topic 815
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 4D
-Subparagraph (a)(1)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480434/815-10-50-4D

Reference 10: http://www.xbrl.org/2003/role/disclosureRef
-Topic 815
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 4A
-Subparagraph (b)(2)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480434/815-10-50-4A

Reference 11: http://www.xbrl.org/2003/role/disclosureRef
-Topic 815
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 4C
-Subparagraph (b)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480434/815-10-50-4C

Reference 12: http://www.xbrl.org/2003/role/disclosureRef
-Topic 815
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 4CCC
-Subparagraph (c)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480434/815-10-50-4CCC

Reference 13: http://www.xbrl.org/2003/role/disclosureRef
-Topic 815
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 4CCC
-Subparagraph (b)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480434/815-10-50-4CCC

Reference 14: http://www.xbrl.org/2003/role/disclosureRef
-Topic 815
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 4CCC
-Subparagraph (a)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480434/815-10-50-4CCC

Reference 15: http://www.xbrl.org/2003/role/disclosureRef
-Topic 815
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 4CC
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480434/815-10-50-4CC

Reference 16: http://www.xbrl.org/2003/role/disclosureRef
-Topic 815
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 4C
-Subparagraph (g)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480434/815-10-50-4C

Reference 17: http://www.xbrl.org/2003/role/disclosureRef
-Topic 815
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 4C
-Subparagraph (f)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480434/815-10-50-4C

Reference 18: http://www.xbrl.org/2003/role/disclosureRef
-Topic 815
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 4C
-Subparagraph (d)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480434/815-10-50-4C

Reference 19: http://www.xbrl.org/2003/role/disclosureRef
-Topic 815
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 4C
-Subparagraph (c)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480434/815-10-50-4C

Reference 20: http://www.xbrl.org/2003/role/disclosureRef
-Topic 815
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 4C
-Subparagraph (bb)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480434/815-10-50-4C

Reference 21: http://www.xbrl.org/2003/role/disclosureRef
-Topic 815
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 4D
-Subparagraph (b)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480434/815-10-50-4D

Reference 22: http://www.xbrl.org/2003/role/disclosureRef
-Topic 815
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 4E
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480434/815-10-50-4E

+ Details

LEASES - (Lessor) Narrative (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Leases [Abstract]
Fixed portion of the operating lease income	$ 109	$ 114	$ 112
Cost for facilities accounted for as operating leases	697	697
Accumulated depreciation for facilities accounted for as operating leases	$ 371	$ 351

VARIABLE INTEREST ENTITIES (Tables)

12 Months Ended

Dec. 31, 2025

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Schedule of Variable Interest Entities

The consolidated VIEs whose assets cannot be used for purposes other than for the settlement of the VIE’s obligations, or are not considered a business, were as follows:


at December 31
(millions of Canadian $)	2025	2024

ASSETS
Current Assets
Cash and cash equivalents	167	311
Accounts receivable	989	839
Inventories	211	205
Other current assets	65	121
	1,432	1,476
Plant, Property and Equipment	49,445	49,904
Equity Investments	979	865
Restricted Investments	1,150	950
Regulatory Assets	109	53
Goodwill	456	479
Other Long-Term Assets	93	59
	53,664	53,786
LIABILITIES
Current Liabilities
Notes payable	535	—
Accounts payable and other	1,703	1,866

Accrued interest	216	202
Current portion of long-term debt	575	2,062
	3,029	4,130
Regulatory Liabilities	1,458	1,232
Other Long-Term Liabilities	51	70
Deferred Income Tax Liabilities	7	7
Long-Term Debt	13,904	12,387
	18,449	17,826

The carrying value of these VIEs and the maximum exposure to loss as a result of the Company's involvement with these VIEs were as follows:


at December 31
(millions of Canadian $)	2025	2024

Balance Sheet Exposure

Equity Investments
Bruce Power	7,780	7,043

Coastal GasLink	896	1,006
Other equity investments	158	160

Off-Balance Sheet Exposure1
Bruce Power	1,955	1,877
Coastal GasLink2	200	265
Other equity investments	—	2
Maximum exposure to loss	10,989	10,353

1Includes maximum potential exposure to guarantees and future funding commitments.

2TC Energy is contractually obligated to fund the capital costs to complete the Coastal GasLink pipeline by funding the remaining equity requirements of Coastal GasLink LP through incremental capacity on the subordinated loan agreement with Coastal GasLink LP until final costs are determined. In December 2024, TC Energy made an equity contribution of $3,137 million to Coastal GasLink LP, which used the funds to repay the $3,147 million balance owing to TC Energy under the subordinated loan agreement. The repayment reduced the Company's funding commitment under the subordinated loan agreement to $228 million. In October 2025, TC Energy made an additional $65 million in equity contributions to Coastal GasLink LP, which reduced the Company's funding commitment under the subordinated loan agreement to $163 million. In addition to the subordinated loan agreement, TC Energy has entered into an equity contribution agreement to fund a maximum of $37 million for its proportionate share of the equity requirements related to the Cedar Link project.

- Definition

Tabular disclosure of the significant judgments and assumptions made in determining whether a variable interest (as defined) held by the entity requires the variable interest entity (VIE) (as defined) to be consolidated and (or) disclose information about its involvement with the VIE, individually or in aggregate (as applicable); the nature of restrictions, if any, on the consolidated VIE's assets and on the settlement of its liabilities reported by an entity in its statement of financial position, including the carrying amounts of such assets and liabilities; the nature of, and changes in, the risks associated with involvement in the VIE; how involvement with the VIE affects the entity's financial position, financial performance, and cash flows; the lack of recourse if creditors (or beneficial interest holders) of the consolidated VIE have no recourse to the general credit of the primary beneficiary (if applicable); the terms of arrangements, giving consideration to both explicit arrangements and implicit variable interests, if any, that could require the entity to provide financial support to the VIE, including events or circumstances that could expose the entity to a loss; the methodology used by the entity for determining whether or not it is the primary beneficiary of the variable interest entity; the significant factors considered and judgments made in determining that the power to direct the activities of a VIE that most significantly impact the VIE's economic performance are shared (as defined); the carrying amounts and classification of assets and liabilities of the VIE included in the statement of financial position; the entity's maximum exposure to loss, if any, as a result of its involvement with the VIE, including how the maximum exposure is determined and significant sources of the entity's exposure to the VIE; a comparison of the carrying amounts of the assets and liabilities and the entity's maximum exposure to loss; information about any liquidity arrangements, guarantees, and (or) other commitments by third parties that may affect the fair value or risk of the entity's variable interest in the VIE; whether or not the entity has provided financial support or other support (explicitly or implicitly) to the VIE that it was not previously contractually required to provide or whether the entity intends to provide that support, including the type and amount of the support and the primary reasons for providing the support; and supplemental information the entity determines necessary to provide.

+ References + Details

DISCONTINUED OPERATIONS (Tables)

12 Months Ended

Dec. 31, 2025

Discontinued Operations and Disposal Groups [Abstract]

Schedule of Discontinued Operations

Income from Discontinued Operations


year ended December 31
(millions of Canadian $)	2025	2024	2023

Revenues	—	2,217	2,667
Income (Loss) from Equity Investments	—	50	67
Operating and Other Expenses
Plant operating costs and other	216	806	814
Commodity purchases resold	—	387	437
Property taxes	—	84	116
Depreciation and amortization	—	253	332
Asset impairment charge and other	29	21	(4)
	245	1,551	1,695
Segmented Earnings (Losses) from Discontinued Operations	(245)	716	1,039
Financial Charges
Interest expense	—	218	297
Interest income and other	(28)	(21)	30
	(28)	197	327
Income (Loss) from Discontinued Operations before Income Taxes	(217)	519	712
Income tax expense (recovery)	(5)	124	100
Net Income (Loss) from Discontinued Operations, Net of Tax	(212)	395	612

Assets and Liabilities of Discontinued Operations


at December 31
(millions of Canadian $)	2025	2024

ASSETS
Current Assets
Other current assets	197	235
	197	235
Other Long-Term Assets	—	136
	197	371
LIABILITIES
Current Liabilities
Accounts payable and other	181	170
	181	170
Other Long-Term Liabilities	—	110
	181	280

Cash Flows from Discontinued Operations


year ended December 31
(millions of Canadian $)	2025	2024	2023

Net cash (used in) provided by operations	(185)	670	1,026
Net cash (used in) provided by investing activities	24	(89)	87

- Definition

Tabular disclosure of information related to a disposal group. Includes, but is not limited to, a discontinued operation, disposal classified as held-for-sale or disposed of by means other than sale or disposal of an individually significant component.

+ References

Reference 1: http://fasb.org/us-gaap/role/ref/legacyRef
-Name Accounting Standards Codification
-Section 50
-Paragraph 3
-SubTopic 10
-Topic 360
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482099/360-10-50-3

Reference 2: http://www.xbrl.org/2009/role/commonPracticeRef
-Topic 360
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 3A
-Subparagraph (b)(2)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482099/360-10-50-3A

Reference 3: http://www.xbrl.org/2009/role/commonPracticeRef
-Topic 360
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 3A
-Subparagraph (b)(1)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482099/360-10-50-3A

Reference 4: http://fasb.org/us-gaap/role/ref/legacyRef
-Topic 205
-SubTopic 20
-Name Accounting Standards Codification
-Section 45
-Paragraph 11
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147483475/205-20-45-11

Reference 5: http://fasb.org/us-gaap/role/ref/legacyRef
-Topic 205
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 3A
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147483499/205-20-50-3A

Reference 6: http://fasb.org/us-gaap/role/ref/legacyRef
-Topic 205
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 4A
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147483499/205-20-50-4A

Reference 7: http://fasb.org/us-gaap/role/ref/legacyRef
-Topic 205
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 4B
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147483499/205-20-50-4B

Reference 8: http://fasb.org/us-gaap/role/ref/legacyRef
-Topic 205
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 5A
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147483499/205-20-50-5A

Reference 9: http://fasb.org/us-gaap/role/ref/legacyRef
-Topic 205
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 5B
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147483499/205-20-50-5B

Reference 10: http://fasb.org/us-gaap/role/ref/legacyRef
-Topic 205
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 5C
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147483499/205-20-50-5C

Reference 11: http://fasb.org/us-gaap/role/ref/legacyRef
-Topic 205
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 5D
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147483499/205-20-50-5D

Reference 12: http://fasb.org/us-gaap/role/ref/legacyRef
-Topic 205
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 7
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147483499/205-20-50-7

Reference 13: http://fasb.org/us-gaap/role/ref/legacyRef
-Topic 360
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 3A
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482099/360-10-50-3A

Reference 14: http://fasb.org/us-gaap/role/ref/legacyRef
-Name Accounting Standards Codification
-Section 50
-Paragraph 1
-SubTopic 20
-Topic 205
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147483499/205-20-50-1

Reference 15: http://fasb.org/us-gaap/role/ref/legacyRef
-Name Accounting Standards Codification
-Topic 205
-SubTopic 20
-Section 50
-Paragraph 3
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147483499/205-20-50-3

+ Details

EMPLOYEE POST-RETIREMENT BENEFITS - Savings, Payments, Future Benefits and Assumptions (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Other post-retirement benefit plans, Savings Plan and DC Plans
Company's expected funding contributions for savings plan and DC Plans	$ 76
Health care benefits
Assumed average annual rate of increase in the per capita cost of covered health care benefits	6.70%
Percentage level to which average annual rate was assumed to decrease	4.85%
Pension Benefit Plans
DB Plans
Company's expected funding contributions	$ 0
Estimated future benefit payments, which reflect expected future service
2026	223
2027	224
2028	226
2029	228
2030	230
2031 to 2035	$ 1,158
Weighted average actuarial assumptions adopted in measuring the benefit obligations
Discount rate	5.10%	4.90%
Rate of compensation increase	3.05%	3.05%
Weighted average actuarial assumptions adopted in measuring the net benefit plan costs
Discount rate	4.90%	4.75%	5.15%
Expected long-term rate of return on plan assets	6.75%	6.60%	6.45%
Rate of compensation increase	3.05%	3.15%	3.25%
Net benefit cost
Service cost	$ 101	$ 108	$ 93
Other components of net benefit cost
Interest cost	162	160	158
Expected return on plan assets	(250)	(248)	(234)
Amortization of past service cost	0	0	0
Amortization of regulatory asset	0	0	0
Other components of net benefit cost	(88)	(88)	(76)
Net Benefit Cost Recognized	13	20	17
Pre-tax amounts recognized in AOCI
Net loss (gain)	(114)	(24)	71
Pre-tax amounts recognized in OCI
Amortization of net gain (loss) from AOCI to net income	0	6	0
Funded status adjustment	(91)	(101)	33
Total pre-tax amounts recognized in OCI	(91)	$ (95)	$ 33
Other Post-Retirement Benefit Plans
DB Plans
Company's expected funding contributions	8
Estimated future benefit payments, which reflect expected future service
2026	22
2027	22
2028	22
2029	21
2030	21
2031 to 2035	$ 98
Weighted average actuarial assumptions adopted in measuring the benefit obligations
Discount rate	5.45%	5.45%
Rate of compensation increase	0.00%	0.00%
Weighted average actuarial assumptions adopted in measuring the net benefit plan costs
Discount rate	5.45%	5.15%	5.45%
Expected long-term rate of return on plan assets	4.75%	4.50%	4.50%
Rate of compensation increase	0.00%	0.00%	0.00%
Net benefit cost
Service cost	$ 1	$ 1	$ 3
Other components of net benefit cost
Interest cost	15	14	16
Expected return on plan assets	(16)	(14)	(16)
Amortization of past service cost	(2)	0	0
Amortization of regulatory asset	0	(2)	0
Other components of net benefit cost	(3)	(2)	0
Net Benefit Cost Recognized	(2)	(1)	3
Pre-tax amounts recognized in AOCI
Net loss (gain)	(13)	0	6
Pre-tax amounts recognized in OCI
Amortization of net gain (loss) from AOCI to net income	0	0	0
Funded status adjustment	(13)	(6)	(18)
Total pre-tax amounts recognized in OCI	$ (13)	$ (6)	$ (18)

LONG-TERM DEBT - Principal Repayments (Details) $ in Millions	Dec. 31, 2025 CAD ($)
Repayments of Long-term Debt [Abstract]
2026	$ 1,545
2027	3,122
2028	5,196
2029	1,309
2030	$ 4,573

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - Net Change in Fair Value of Derivative Assets and Liabilities Classified as Level III (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024
Net change in the Level III fair value category
Fair Value, Liability, Recurring Basis, Still Held, Unrealized Gain (Loss), Statement of Income or Comprehensive Income [Extensible Enumeration]	Revenues	Revenues
Unrealized gains (losses) attributed to derivatives in the Level III category	$ 21	$ 54
Commodity contracts \| Power
Net change in the Level III fair value category
Balance at beginning of year	72	(11)
Net gains (losses) included in Net income (loss)	21	54
Transfers to Level II	(4)	29
Purchases	(1)	0
Settlements	(14)	0
Balance at end of year	$ 74	$ 72

INCOME TAXES - Geographic Components of Income/(Loss) (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Income Tax Disclosure [Abstract]
Canada	$ 1,959	$ 1,469	$ (194)
Foreign	3,485	4,437	3,492
Income (Loss) from Continuing Operations before Income Taxes	$ 5,444	$ 5,906	$ 3,298

- Definition

Amount of income (loss) from continuing operations, including income (loss) from equity method investments, before deduction of income tax expense (benefit), and income (loss) attributable to noncontrolling interest.

+ References

Reference 1: http://www.xbrl.org/2003/role/exampleRef
-Topic 220
-SubTopic 40
-Name Accounting Standards Codification
-Section 55
-Paragraph 4
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147476153/220-40-55-4

Reference 2: http://www.xbrl.org/2003/role/exampleRef
-Topic 220
-SubTopic 40
-Name Accounting Standards Codification
-Section 55
-Paragraph 21
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147476153/220-40-55-21

Reference 3: http://www.xbrl.org/2003/role/exampleRef
-Topic 220
-SubTopic 40
-Name Accounting Standards Codification
-Section 55
-Paragraph 14
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147476153/220-40-55-14

Reference 4: http://www.xbrl.org/2003/role/disclosureRef
-Topic 942
-SubTopic 235
-Name Accounting Standards Codification
-Section S50
-Paragraph 1
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147478671/942-235-S50-1

Reference 5: http://www.xbrl.org/2003/role/disclosureRef
-Topic 942
-SubTopic 235
-Name Accounting Standards Codification
-Section S99
-Paragraph 1
-Subparagraph (SX 210.9-05(b)(2))
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147477314/942-235-S99-1

Reference 6: http://www.xbrl.org/2009/role/commonPracticeRef
-Topic 280
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 22
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482810/280-10-50-22

Reference 7: http://www.xbrl.org/2003/role/exampleRef
-Topic 280
-SubTopic 10
-Name Accounting Standards Codification
-Section 55
-Paragraph 48
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482785/280-10-55-48

Reference 8: http://www.xbrl.org/2009/role/commonPracticeRef
-Topic 280
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 32
-Subparagraph (f)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482810/280-10-50-32

Reference 9: http://www.xbrl.org/2009/role/commonPracticeRef
-Topic 280
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 30
-Subparagraph (b)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482810/280-10-50-30

Reference 10: http://www.xbrl.org/2009/role/commonPracticeRef
-Topic 270
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 1
-Subparagraph (i)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482964/270-10-50-1

Reference 11: http://www.xbrl.org/2009/role/commonPracticeRef
-Topic 280
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 32
-Subparagraph (ee)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482810/280-10-50-32

Reference 12: http://fasb.org/us-gaap/role/ref/otherTransitionRef
-Topic 280
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 32
-Subparagraph (c)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482810/280-10-50-32

Reference 13: http://www.xbrl.org/2003/role/disclosureRef
-Topic 944
-SubTopic 220
-Name Accounting Standards Codification
-Section S99
-Paragraph 1
-Subparagraph (SX 210.7-04(11))
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147477250/944-220-S99-1

Reference 14: http://www.xbrl.org/2003/role/exampleRef
-Topic 280
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 31
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482810/280-10-50-31

Reference 15: http://fasb.org/us-gaap/role/ref/legacyRef
-Topic 220
-SubTopic 10
-Name Accounting Standards Codification
-Section S99
-Paragraph 2
-Subparagraph (SX 210.5-03(10))
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147483621/220-10-S99-2

Reference 16: http://fasb.org/us-gaap/role/ref/legacyRef
-Topic 942
-SubTopic 220
-Name Accounting Standards Codification
-Section S99
-Paragraph 1
-Subparagraph (SX 210.9-04(15))
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147478524/942-220-S99-1

+ Details

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - Fair Value of Non-Derivative Financial Instruments (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024
Carrying and fair values of non-derivative financial instruments
Outstanding	$ (46,928)	$ (48,172)
Junior subordinated notes (Note 20)	(12,094)	(11,048)
Long-term debt	4,000	4,000
Interest rate swap agreements
Carrying and fair values of non-derivative financial instruments
Unrealized gain (loss) on hedged item	(122)	128
Level II \| Carrying Amount
Carrying and fair values of non-derivative financial instruments
Outstanding	(46,792)	(47,931)
Junior subordinated notes (Note 20)	(12,094)	(11,048)
Total liabilities	(58,886)	(58,979)
Level II \| Fair Value
Carrying and fair values of non-derivative financial instruments
Outstanding	(47,720)	(48,318)
Junior subordinated notes (Note 20)	(12,061)	(10,824)
Total liabilities	$ (59,781)	$ (59,142)

COMMON SHARES - Reconciliation and Weighted Average Common Shares Outstanding (Details) - CAD ($) shares in Thousands, $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Number of Shares
Outstanding at the beginning of the period (in shares)	1,039,000
Exercise of options (in shares)	1,740
Outstanding at the end of the period (in shares)	1,041,000	1,039,000
Amount
Outstanding at the beginning of the period	$ 30,101
Outstanding at the end of the period	$ 30,218	$ 30,101
Common shares
Number of Shares
Outstanding at the beginning of the period (in shares)	1,039,095	1,037,488	1,017,962
Dividend reinvestment and share purchase plan (in shares)			19,464
Exercise of options (in shares)	1,740	1,607	62
Outstanding at the end of the period (in shares)	1,040,835	1,039,095	1,037,488
Amount
Outstanding at the beginning of the period	$ 30,101	$ 30,002	$ 28,995
Dividend reinvestment and share purchase plan			1,003
Exercise of options	117	99	4
Outstanding at the end of the period	$ 30,218	$ 30,101	$ 30,002

ACCOUNTING POLICIES (Details) - CAD ($) $ in Millions	3 Months Ended	12 Months Ended
ACCOUNTING POLICIES (Details) - CAD ($) $ in Millions	Jun. 30, 2025	Dec. 31, 2025
Property, Plant and Equipment [Line Items]
Reclassification of net investment hedge losses from AOCI to non-controlling interests (NCI) related to the sale	$ 348	$ (348)
Reclassification of net investment hedge losses from AOCI to non-controlling interests related to sale percent	40.00%	40.00%
Reclassification of net investment hedge losses related to the spinoff	$ 542
Employee Post-Retirement Benefits
Moving average period of basis used to determine expected return on plan assets		5 years
Portion amortized out of AOCI and into net income		10.00%
Minimum \| Corporate
Property, Plant and Equipment [Line Items]
Annual depreciation rate on straight-line basis		4.00%
Minimum \| Pipeline \| Natural Gas Pipelines
Property, Plant and Equipment [Line Items]
Annual depreciation rate on straight-line basis		0.625%
Minimum \| Power generation and natural gas storage plant, equipment and structures \| Power and Energy Solutions
Property, Plant and Equipment [Line Items]
Annual depreciation rate on straight-line basis		2.00%
Maximum \| Corporate
Property, Plant and Equipment [Line Items]
Annual depreciation rate on straight-line basis		20.00%
Maximum \| Pipeline \| Natural Gas Pipelines
Property, Plant and Equipment [Line Items]
Annual depreciation rate on straight-line basis		6.67%
Maximum \| Power generation and natural gas storage plant, equipment and structures \| Power and Energy Solutions
Property, Plant and Equipment [Line Items]
Annual depreciation rate on straight-line basis		20.00%

LONG-TERM DEBT - Issued (Details) $ in Millions, $ in Millions	1 Months Ended
	Nov. 30, 2025 CAD ($)	Nov. 30, 2025 USD ($)	Oct. 31, 2025 USD ($)	Sep. 30, 2025 USD ($)	Mar. 31, 2025 USD ($)	Feb. 28, 2025 CAD ($)	Sep. 30, 2024 USD ($)	Aug. 31, 2024 USD ($)	Jan. 31, 2024 USD ($)	Aug. 31, 2023 USD ($)	Jun. 30, 2023 USD ($)	May 31, 2023 USD ($)	Mar. 31, 2023 CAD ($)	Mar. 31, 2023 USD ($)	Jan. 31, 2023 USD ($)
Medium Term Notes Due November 2055 \| TRANSCANADA PIPELINES LIMITED
Debt Instrument [Line Items]
Amount	$ 850
Interest Rate	5.13%	5.13%
Medium Term Notes Due February 2035 \| TRANSCANADA PIPELINES LIMITED
Debt Instrument [Line Items]
Amount						$ 1,000
Interest Rate						4.58%
Term Loan August 2024 \| TRANSCANADA PIPELINES LIMITED
Debt Instrument [Line Items]
Amount								$ 1,242
Senior Unsecured Term Loan Due May 2026 \| TRANSCANADA PIPELINES LIMITED
Debt Instrument [Line Items]
Amount												$ 1,024
Senior Unsecured Notes Due March 2026 \| TRANSCANADA PIPELINES LIMITED
Debt Instrument [Line Items]
Amount														$ 850
Interest Rate													6.20%	6.20%
Senior Unsecured Notes One Due March 2026 \| TRANSCANADA PIPELINES LIMITED
Debt Instrument [Line Items]
Amount														$ 400
Medium Term Notes Due July 2030 \| TRANSCANADA PIPELINES LIMITED
Debt Instrument [Line Items]
Amount													$ 1,250
Interest Rate													5.28%	5.28%
Medium Term Notes Due March 2026 \| TRANSCANADA PIPELINES LIMITED
Debt Instrument [Line Items]
Amount													$ 600
Interest Rate													5.42%	5.42%
Medium Term Notes One Due March 2026 \| TRANSCANADA PIPELINES LIMITED
Debt Instrument [Line Items]
Amount													$ 400
Senior Unsecured Notes Due November 2032 \| COLUMBIA PIPELINES HOLDING COMPANY LLC
Debt Instrument [Line Items]
Amount		$ 750
Interest Rate	5.00%	5.00%
Senior Unsecured Notes due October 2031 \| COLUMBIA PIPELINES HOLDING COMPANY LLC
Debt Instrument [Line Items]
Amount							$ 400
Interest Rate							5.10%
Senior Unsecured Notes Due January 2034 \| COLUMBIA PIPELINES HOLDING COMPANY LLC
Debt Instrument [Line Items]
Amount									$ 500
Interest Rate									5.68%
Senior Unsecured Notes Due August 2028 \| COLUMBIA PIPELINES HOLDING COMPANY LLC
Debt Instrument [Line Items]
Amount										$ 700
Interest Rate										6.04%
Senior Unsecured Notes Due August 2026 \| COLUMBIA PIPELINES HOLDING COMPANY LLC
Debt Instrument [Line Items]
Amount										$ 300
Interest Rate										6.06%
Unsecured Term Loan Due October 2028 \| GREAT LAKES GAS TRANSMISSION LIMITED PARTNERSHIP
Debt Instrument [Line Items]
Amount			$ 205
Senior Unsecured Notes Due September 2031 \| ANR PIPELINE COMPANY
Debt Instrument [Line Items]
Amount				$ 250
Interest Rate				5.23%
Senior Unsecured Notes Due September 2035 \| ANR PIPELINE COMPANY
Debt Instrument [Line Items]
Amount				$ 350
Interest Rate				5.69%
Senior Unsecured Notes Due February 2035 \| COLUMBIA PIPELINES OPERATING COMPANY LLC
Debt Instrument [Line Items]
Amount					$ 550
Interest Rate					5.44%
Senior Unsecured Notes Due February 2055 \| COLUMBIA PIPELINES OPERATING COMPANY LLC
Debt Instrument [Line Items]
Amount					$ 450
Interest Rate					5.96%
Senior Unsecured Notes Due October 2054 \| COLUMBIA PIPELINES OPERATING COMPANY LLC
Debt Instrument [Line Items]
Amount							$ 400
Interest Rate							5.70%
Senior Unsecured Notes Due November 2033 \| COLUMBIA PIPELINES OPERATING COMPANY LLC
Debt Instrument [Line Items]
Amount										$ 1,500
Interest Rate										6.04%
Senior Unsecured Notes Due November 2053 \| COLUMBIA PIPELINES OPERATING COMPANY LLC
Debt Instrument [Line Items]
Amount										$ 1,250
Interest Rate										6.54%
Senior Unsecured Notes Due August 2030 \| COLUMBIA PIPELINES OPERATING COMPANY LLC
Debt Instrument [Line Items]
Amount										$ 750
Interest Rate										5.93%
Senior Unsecured Notes Due August 2043 \| COLUMBIA PIPELINES OPERATING COMPANY LLC
Debt Instrument [Line Items]
Amount										$ 600
Interest Rate										6.50%
Senior Unsecured Notes Due August 2063 \| COLUMBIA PIPELINES OPERATING COMPANY LLC
Debt Instrument [Line Items]
Amount										$ 500
Interest Rate										6.71%
Senior Unsecured Notes due June 2030 \| GAS TRANSMISSION NORTHWEST LLC
Debt Instrument [Line Items]
Amount											$ 50
Interest Rate											4.92%
Senior Unsecured Term Loan Due January 2028 \| TC ENERGÍA MEXICANA, S. DE R.L. DE C.V.
Debt Instrument [Line Items]
Amount															$ 1,800
Senior Unsecured Revolving Credit Facility Due January 2028 \| TC ENERGÍA MEXICANA, S. DE R.L. DE C.V.
Debt Instrument [Line Items]
Amount															$ 500

SEGMENTED INFORMATION

12 Months Ended

Dec. 31, 2025

Segment Reporting [Abstract]

SEGMENTED INFORMATION

The Company’s chief operating decision maker is the President and Chief Executive Officer. The chief operating decision maker uses segmented earnings (losses) to assess the performance of the business segments, assist with capital investment decisions and benchmark to TC Energy’s competitors.

Information regarding the Company's business segments is as follows:


year ended December 31, 2025	Canadian Natural Gas Pipelines	U.S. Natural Gas Pipelines	Mexico Natural Gas Pipelines	Power and Energy Solutions	Corporate		Total
(millions of Canadian $)						1

Revenues	5,785	7,145	1,450	845	14		15,239
Intersegment revenues2	—	99	—	52	(151)		—
	5,785	7,244	1,450	897	(137)		15,239
Income (loss) from equity investments	112	301	94	767	—		1,274





Operating costs2	(2,210)	(2,581)	(262)	(778)	123		(5,708)
Depreciation and amortization	(1,523)	(1,037)	(96)	(113)	—		(2,769)

Segmented Earnings (Losses)	2,164	3,927	1,186	773	(14)		8,036
Interest expense							(3,407)
Allowance for funds used during construction							453
Foreign exchange gains (losses), net							157
Interest income and other							205
Income (Loss) from Continuing Operations before Income Taxes							5,444
Income tax (expense) recovery from continuing operations							(1,138)
Net Income (Loss) from Continuing Operations							4,306
Net Income (Loss) from Discontinued Operations, Net of Tax							(212)
Net Income (Loss)							4,094
Net (income) loss attributable to non-controlling interests							(575)
Net Income (Loss) Attributable to Controlling Interests							3,519
Preferred share dividends							(119)
Net Income (Loss) Attributable to Common Shares							3,400

Capital Spending3
Capital expenditures	1,340	3,316	522	61	31		5,270
Capital projects in development	—	—	—	16	—		16
Contributions to equity investments	65	141	—	845	—		1,051
	1,405	3,457	522	922	31		6,337

1Includes intersegment eliminations.

3Included in Investing activities in the Consolidated statement of cash flows.


year ended December 31, 2024	Canadian Natural Gas Pipelines	U.S. Natural Gas Pipelines	Mexico Natural Gas Pipelines	Power and Energy Solutions	Corporate		Total
(millions of Canadian $)						1

Revenues	5,600	6,339	870	954	8		13,771
Intersegment revenues2	—	99	—	49	(148)		—
	5,600	6,438	870	1,003	(140)		13,771

Income (loss) from equity investments	34	341	283	900	—		1,558


Operating costs2	(2,246)	(2,381)	(132)	(700)	9	3	(5,450)
Depreciation and amortization	(1,382)	(955)	(92)	(101)	(5)	3	(2,535)
Other segment items4	10	610	—	—	—		620
Segmented Earnings (Losses)	2,016	4,053	929	1,102	(136)		7,964
Interest expense							(3,019)
Allowance for funds used during construction							784
Foreign exchange gains (losses), net							(147)
Interest income and other							324
Income (Loss) from Continuing Operations before Income Taxes							5,906
Income tax (expense) recovery from continuing operations							(922)
Net Income (Loss) from Continuing Operations							4,984
Net income (loss) from Discontinued Operations, Net of Tax							395
Net Income (Loss)							5,379
Net Income (loss) attributable to non-controlling interests							(681)
Net Income (Loss) Attributable to Controlling Interests							4,698
Preferred share dividends							(104)
Net Income (Loss) Attributable to Common Shares							4,594

Capital Spending5
Capital expenditures	1,273	2,568	2,228	62	50		6,181
Capital projects in development	—	5	—	45	—		50
Contributions to equity investments6	827	2	—	717	—		1,546
	2,100	2,575	2,228	824	50		7,777
Discontinued operations							127
							7,904

1Includes intersegment eliminations.

3Includes shared costs and depreciation previously allocated to the Liquids Pipelines segment. Refer to Note 4, Discontinued operations, for additional information.

4Other segment items include a Net gain (loss) on sale of assets.

5Included in Investing activities in the Consolidated statement of cash flows.


year ended December 31, 2023	Canadian Natural Gas Pipelines	U.S. Natural Gas Pipelines	Mexico Natural Gas Pipelines	Power and Energy Solutions	Corporate		Total
(millions of Canadian $)						1

Revenues	5,173	6,229	846	1,019	—		13,267
Intersegment revenues2	—	101	—	22	(123)		—
	5,173	6,330	846	1,041	(123)		13,267
Income (loss) from equity investments	220	324	78	688	—		1,310
Impairment of equity investment	(2,100)	—	—	—	—		(2,100)




Operating costs2	(2,058)	(2,189)	(39)	(633)	(15)	3	(4,934)
Depreciation and amortization	(1,325)	(934)	(89)	(92)	(6)	3	(2,446)



Segmented Earnings (Losses)	(90)	3,531	796	1,004	(144)		5,097
Interest expense							(2,966)
Allowance for funds used during construction							575
Foreign exchange gains (losses), net							320
Interest income and other							272
Income (Loss) from Continuing Operations before Income Taxes							3,298
Income tax (expense) recovery from continuing operations							(842)
Net Income (Loss) from Continuing Operations							2,456
Net Income (Loss) from Discontinued Operations, Net of Tax							612
Net Income (Loss)							3,068
Net (income) loss attributable to non-controlling interests							(146)
Net Income (Loss) Attributable to Controlling Interests							2,922
Preferred share dividends							(93)
Net Income (Loss) Attributable to Common Shares							2,829

Capital Spending4
Capital expenditures	2,953	2,536	2,292	144	33		7,958
Capital projects in development	—	—	—	142	—		142
Contributions to equity investments	3,231	124	—	794	—		4,149
	6,184	2,660	2,292	1,080	33		12,249
Discontinued operations							49
							12,298

1Includes intersegment eliminations.

3Includes shared costs and depreciation previously allocated to the Liquids Pipelines segment. Refer to Note 4, Discontinued operations, for additional information.

4Included in Investing activities in the Consolidated statement of cash flows.


at December 31	2025	2024
(millions of Canadian $)

Total Assets by Segment
Canadian Natural Gas Pipelines	31,371	31,167
U.S. Natural Gas Pipelines	56,617	56,304
Mexico Natural Gas Pipelines	16,342	15,995
Power and Energy Solutions	10,764	10,217
Corporate	3,460	4,189
	118,554	117,872
Discontinued Operations	197	371
	118,751	118,243

Geographic Information


year ended December 31	2025	2024	2023
(millions of Canadian $)

Revenues
Canada – domestic	5,617	5,579	5,337
Canada – export	968	953	821
United States	7,204	6,369	6,263
Mexico	1,450	870	846
	15,239	13,771	13,267


at December 31	2025	2024
(millions of Canadian $)

Plant, Property and Equipment
Canada	26,078	26,354
United States	40,976	40,580
Mexico	4,000	10,567
	71,054	77,501

- Definition

The entire disclosure for reporting segments including data and tables. Reportable segments include those that meet any of the following quantitative thresholds a) it's reported revenue, including sales to external customers and intersegment sales or transfers is 10 percent or more of the combined revenue, internal and external, of all operating segments b) the absolute amount of its reported profit or loss is 10 percent or more of the greater, in absolute amount of 1) the combined reported profit of all operating segments that did not report a loss or 2) the combined reported loss of all operating segments that did report a loss c) its assets are 10 percent or more of the combined assets of all operating segments.

+ References

Reference 1: http://www.xbrl.org/2003/role/disclosureRef
-Topic 280
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 21
-Subparagraph (b)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482810/280-10-50-21

Reference 2: http://www.xbrl.org/2003/role/disclosureRef
-Topic 280
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 21
-Subparagraph (a)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482810/280-10-50-21

Reference 3: http://www.xbrl.org/2003/role/disclosureRef
-Topic 280
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 32
-Subparagraph (e)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482810/280-10-50-32

Reference 4: http://www.xbrl.org/2003/role/disclosureRef
-Topic 280
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 31
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482810/280-10-50-31

Reference 5: http://www.xbrl.org/2003/role/disclosureRef
-Topic 280
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 15
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482810/280-10-50-15

Reference 6: http://www.xbrl.org/2003/role/disclosureRef
-Topic 280
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 42
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482810/280-10-50-42

Reference 7: http://www.xbrl.org/2003/role/exampleRef
-Topic 280
-SubTopic 10
-Name Accounting Standards Codification
-Section 55
-Paragraph 48
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482785/280-10-55-48

Reference 8: http://www.xbrl.org/2003/role/disclosureRef
-Topic 280
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 32
-Subparagraph (f)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482810/280-10-50-32

Reference 9: http://www.xbrl.org/2003/role/disclosureRef
-Topic 270
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 1
-Subparagraph (i)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482964/270-10-50-1

Reference 10: http://www.xbrl.org/2003/role/disclosureRef
-Topic 280
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 32
-Subparagraph (ee)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482810/280-10-50-32

Reference 11: http://fasb.org/us-gaap/role/ref/otherTransitionRef
-Topic 280
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 32
-Subparagraph (d)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482810/280-10-50-32

Reference 12: http://www.xbrl.org/2003/role/exampleRef
-Topic 280
-SubTopic 10
-Name Accounting Standards Codification
-Section 55
-Paragraph 54
-Subparagraph (d)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482785/280-10-55-54

Reference 13: http://www.xbrl.org/2003/role/exampleRef
-Topic 280
-SubTopic 10
-Name Accounting Standards Codification
-Section 55
-Paragraph 47
-Subparagraph (c)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482785/280-10-55-47

Reference 14: http://www.xbrl.org/2003/role/exampleRef
-Topic 280
-SubTopic 10
-Name Accounting Standards Codification
-Section 55
-Paragraph 54
-Subparagraph (a)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482785/280-10-55-54

Reference 15: http://www.xbrl.org/2003/role/exampleRef
-Topic 280
-SubTopic 10
-Name Accounting Standards Codification
-Section 55
-Paragraph 47
-Subparagraph (a)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482785/280-10-55-47

Reference 16: http://www.xbrl.org/2003/role/exampleRef
-Topic 280
-SubTopic 10
-Name Accounting Standards Codification
-Section 55
-Paragraph 54
-Subparagraph (e)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482785/280-10-55-54

Reference 17: http://www.xbrl.org/2003/role/exampleRef
-Topic 280
-SubTopic 10
-Name Accounting Standards Codification
-Section 55
-Paragraph 47
-Subparagraph (d)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482785/280-10-55-47

Reference 18: http://www.xbrl.org/2003/role/disclosureRef
-Topic 280
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 22
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482810/280-10-50-22

Reference 19: http://www.xbrl.org/2003/role/disclosureRef
-Topic 280
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 34
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482810/280-10-50-34

Reference 20: http://www.xbrl.org/2003/role/disclosureRef
-Topic 280
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 26C
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482810/280-10-50-26C

Reference 21: http://www.xbrl.org/2003/role/disclosureRef
-Topic 280
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 26B
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482810/280-10-50-26B

Reference 22: http://www.xbrl.org/2003/role/disclosureRef
-Topic 280
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 40
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482810/280-10-50-40

Reference 23: http://www.xbrl.org/2003/role/disclosureRef
-Topic 280
-Name Accounting Standards Codification
-Publisher FASB
-URI https://asc.fasb.org/280/tableOfContent

Reference 24: http://www.xbrl.org/2003/role/disclosureRef
-Topic 280
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 26
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482810/280-10-50-26

Reference 25: http://www.xbrl.org/2003/role/disclosureRef
-Topic 280
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 41
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482810/280-10-50-41

+ Details

SEGMENTED INFORMATION - Asset by Segment (Details) - CAD ($) $ in Millions	Dec. 31, 2025	Dec. 31, 2024
Segment Reporting Information [Line Items]
Assets	$ 118,751	$ 118,243
Continuing Operations
Segment Reporting Information [Line Items]
Assets	118,554	117,872
Discontinued Operations
Segment Reporting Information [Line Items]
Assets	197	371
Operating segments \| Canadian Natural Gas Pipelines
Segment Reporting Information [Line Items]
Assets	31,371	31,167
Operating segments \| U.S. Natural Gas Pipelines
Segment Reporting Information [Line Items]
Assets	56,617	56,304
Operating segments \| Mexico Natural Gas Pipelines
Segment Reporting Information [Line Items]
Assets	16,342	15,995
Operating segments \| Power and Energy Solutions
Segment Reporting Information [Line Items]
Assets	10,764	10,217
Corporate
Segment Reporting Information [Line Items]
Assets	$ 3,460	$ 4,189

PLANT, PROPERTY AND EQUIPMENT

12 Months Ended

Dec. 31, 2025

Property, Plant and Equipment [Abstract]

PLANT, PROPERTY AND EQUIPMENT


at December 31	2025			2024
	Cost	Accumulated Depreciation	Net Book Value	Cost	Accumulated Depreciation	Net Book Value
(millions of Canadian $)

Canadian Natural Gas Pipelines
NGTL System
Pipeline	20,806	8,037	12,769	20,497	7,413	13,084
Compression	7,277	2,732	4,545	7,146	2,497	4,649
Metering and other	1,685	903	782	1,668	883	785
	29,768	11,672	18,096	29,311	10,793	18,518
Under construction	663	—	663	503	—	503
	30,431	11,672	18,759	29,814	10,793	19,021
Canadian Mainline
Pipeline	11,126	8,355	2,771	10,907	8,165	2,742
Compression	4,661	3,500	1,161	4,540	3,448	1,092
Metering and other	797	344	453	749	331	418
	16,584	12,199	4,385	16,196	11,944	4,252
Under construction	121	—	121	163	—	163
	16,705	12,199	4,506	16,359	11,944	4,415
Other Canadian Natural Gas Pipelines1
Other	2,947	1,777	1,170	2,927	1,742	1,185
Under construction	19	—	19	31	—	31
	2,966	1,777	1,189	2,958	1,742	1,216
	50,102	25,648	24,454	49,131	24,479	24,652
U.S. Natural Gas Pipelines
Columbia Gas
Pipeline	14,996	1,610	13,386	14,826	1,472	13,354
Compression	6,169	741	5,428	6,153	677	5,476
Metering and other	4,529	502	4,027	4,570	455	4,115
	25,694	2,853	22,841	25,549	2,604	22,945
Under construction	675	—	675	891	—	891
	26,369	2,853	23,516	26,440	2,604	23,836
ANR
Pipeline	3,092	744	2,348	2,477	745	1,732
Compression	4,933	948	3,985	4,446	938	3,508
Metering and other	1,867	509	1,358	1,832	521	1,311
	9,892	2,201	7,691	8,755	2,204	6,551
Under construction	362	—	362	853	—	853
	10,254	2,201	8,053	9,608	2,204	7,404


at December 31	2025			2024
	Cost	Accumulated Depreciation	Net Book Value	Cost	Accumulated Depreciation	Net Book Value
(millions of Canadian $)	Cost	Accumulated Depreciation	Net Book Value	Cost	Accumulated Depreciation	Net Book Value

Other U.S. Natural Gas Pipelines
Columbia Gulf	4,427	274	4,153	4,127	304	3,823
GTN	3,325	1,476	1,849	3,405	1,467	1,938
Great Lakes	2,577	1,509	1,068	2,602	1,537	1,065

Other2	1,646	655	991	1,695	628	1,067
	11,975	3,914	8,061	11,829	3,936	7,893
Under construction	643	—	643	694	—	694
	12,618	3,914	8,704	12,523	3,936	8,587
	49,241	8,968	40,273	48,571	8,744	39,827
Mexico Natural Gas Pipelines3
Pipeline	2,468	545	1,923	2,590	523	2,067
Compression	449	113	336	476	107	369
Metering and other	394	107	287	398	99	299
	3,311	765	2,546	3,464	729	2,735
Under construction	1,454	—	1,454	7,807	—	7,807
	4,765	765	4,000	11,271	729	10,542


















Power and Energy Solutions

Natural Gas Power Generation	1,322	719	603	1,273	671	602

Natural Gas Storage and Other	887	308	579	873	281	592
Renewable Power Generation	737	83	654	779	54	725
	2,946	1,110	1,836	2,925	1,006	1,919
Under construction	56	—	56	56	—	56
	3,002	1,110	1,892	2,981	1,006	1,975
Corporate	895	460	435	944	439	505
	108,005	36,951	71,054	112,898	35,397	77,501

1Includes Foothills, Ventures LP and Great Lakes Canada.

2Includes North Baja, Tuscarora, Louisiana Intrastate, Crossroads, U.S. Energy Marketing and mineral rights business.

3During the year ended December 31, 2025, the Company derecognized $6,595 million (2024 – nil) of Plant, property and equipment and recorded a corresponding asset to net investment in leases for the in-service TGNH pipelines. Refer to Note 9, Leases, for additional information.

ACCOUNTING POLICIES	12 Months Ended
ACCOUNTING POLICIES	Dec. 31, 2025
Accounting Policies [Abstract]
ACCOUNTING POLICIES	ACCOUNTING POLICIES The Company's consolidated financial statements have been prepared by management in accordance with U.S. generally accepted accounting principles. Amounts are stated in Canadian dollars unless otherwise indicated. Basis of Presentation These consolidated financial statements include the accounts of TC Energy and its subsidiaries. The Company consolidates variable interest entities (VIEs) for which it is considered to be the primary beneficiary as well as voting interest entities in which it has a controlling financial interest. Interests in consolidated entities owned by other parties are presented as non-controlling interests. TC Energy uses the equity method of accounting for joint ventures in which the Company is able to exercise joint control and for investments in which the Company is able to exercise significant influence. The Spinoff Transaction represented a strategic shift that had a major effect on the Company's operations and consolidated financial results. Accordingly, the historical results of the Liquids Pipelines business are presented as discontinued operations and have been excluded from continuing operations and segment disclosures for all periods presented. The Notes to the consolidated financial statements reflect continuing operations only, unless otherwise indicated. Prior to the spinoff, the operations of the Liquids Pipelines business were materially reported as the Company's Liquids Pipelines segment. Refer to Note 4, Discontinued operations, and Note 5, Segmented information, for additional information. Certain prior year amounts have been reclassified to conform to current year presentation. Out-of-Period Adjustments During second quarter 2025, the Company recorded out-of-period adjustments to reclassify a pro rata portion of its net investment hedge losses recorded in Accumulated other comprehensive income (loss)(AOCI). The adjustments included (i) a reclassification of net investment hedge losses of $348 million from AOCI to Non-controlling interests (NCI) related to the sale of 40 per cent of Columbia Gas and Columbia Gulf on October 4, 2023, which was presented as Impact of non-controlling interest and Disposition of equity interests, respectively, in the Consolidated statement of equity; and (ii) a reclassification of net investment hedge losses of $542 million related to the spinoff of the Company's Liquids Pipelines business that occurred on October 1, 2024 from AOCI to Retained earnings (Accumulated deficit). The Company determined that the impact of these out-of-period adjustments was not material, individually or in the aggregate, to any previously reported quarterly or annual financial statements and is not material to the Company's consolidated financial statements. Use of Estimates and Judgments In preparing these consolidated financial statements, TC Energy is required to make estimates and assumptions that affect both the amount and timing of recording assets, liabilities, revenues and expenses since the determination of these items may be dependent on future events. The Company uses the most current information available and exercises careful judgment in making these estimates and assumptions. Certain estimates and judgments have a material impact on the consolidated financial statements where the assumptions underlying these accounting estimates relate to matters that are highly uncertain at the time they are made or are subjective. These estimates and judgments include, but are not limited to: •fair value of the Southeast Gateway pipeline used to record a net investment upon lease commencement (Note 9) •fair value of reporting units that contain goodwill (Note 13). Some of the estimates and judgments the Company has to make have a material impact on the consolidated financial statements, but do not involve significant subjectivity or uncertainty. These estimates and judgments include, but are not limited to: •recoverability and depreciation rates of plant, property and equipment (Note 8) •allocation of consideration to lease and non-lease components in a contract that contains a lease (Note 9) •assumptions used to measure the carrying amount of and expected credit losses on net investment in leases and certain contract assets (Notes 9 and 27) •fair value of equity investments (Note 10) •carrying value of regulatory assets and liabilities (Note 12) •recognition of asset retirement obligations (Note 17) •provisions for income taxes, including valuation allowances and releases as well as tax positions that may be reviewed as part of an audit by tax authorities (Note 18) •assumptions used to measure retirement and other post-retirement benefit obligations (Note 26) •fair value of financial instruments (Notes 26 and 27) •commitments and provisions for contingencies and guarantees (Note 30). TC Energy continues to assess climate-related impacts on the consolidated financial statements. There are ongoing developments in the sustainability frameworks and regulatory initiatives that could further impact accounting estimates and judgments including, but not limited to, assessment of asset useful lives, goodwill valuation, impairment of plant, property and equipment, accrued environmental costs and asset retirement obligations. The impact of these changes is continuously assessed to ensure any changes in assumptions that would impact estimates listed above are adjusted on a timely basis. Actual results could differ from these estimates. Regulation Certain Canadian, U.S. and Mexico natural gas pipeline and storage assets are regulated with respect to construction, operations and the determination of tolls. In Canada, regulated natural gas pipelines are subject to the authority of the Canada Energy Regulator (CER), the Alberta Energy Regulator or the BC Energy Regulator. In the U.S., regulated interstate natural gas pipelines and regulated natural gas storage assets are subject to the authority of the Federal Energy Regulatory Commission (FERC). In Mexico, regulated natural gas pipelines are subject to the authority of the National Energy Commission (CNE). Rate-regulated accounting (RRA) standards may impact the timing of the recognition of certain revenues and expenses in TC Energy's rate-regulated businesses which may differ from that otherwise recognized in non-rate-regulated businesses to reflect the economic impact of the regulators' decisions regarding revenues and tolls. Regulatory assets represent costs that are expected to be recovered in customer rates in future periods and regulatory liabilities represent amounts that are expected to be returned to customers through future rate-setting processes. An operation qualifies for the use of RRA when it meets three criteria: •a regulator must establish or approve the rates for the regulated services or activities •the regulated rates must be designed to recover the cost of providing the services or products •it is reasonable to assume that rates set at levels to recover the cost can be charged to and collected from customers because of the demand for services or products and the level of direct or indirect competition. TC Energy's businesses that apply RRA currently include natural gas pipelines in Canada, U.S. and Mexico and regulated U.S. natural gas storage. Revenue Recognition The total consideration for services and products to which the Company expects to be entitled can include fixed and variable amounts. The Company has variable revenue that is subject to factors outside the Company's influence, such as market prices, actions of third parties and weather conditions. The Company considers some of this variable revenue to be constrained as it cannot be reliably estimated and, therefore, variable revenue is recognized only to the extent it is probable a significant reversal in cumulative revenue will not occur. The Company's contracts with customers include natural gas pipelines capacity arrangements and transportation contracts, power generation contracts, natural gas storage and other contracts. Revenues from contracts with customers are recognized net of any commodity taxes collected from customers which are subsequently remitted to governmental authorities. Revenues from non-lease components associated with a lease arrangement are recognized systematically over the term of the contract. The majority of income earned from marketing activities, as it relates to the purchase and sale of natural gas and electricity, is recorded on a net basis in the month of delivery. Canadian Natural Gas Pipelines Capacity Arrangements and Transportation Revenues from the Company's Canadian natural gas pipelines are generated from contractual arrangements for committed capacity and from the transportation of natural gas. Revenues earned from firm contracted capacity arrangements are recognized ratably over the term of the contract regardless of the amount of natural gas that is transported. Transportation revenues for interruptible or volumetric-based services are recognized when the service is performed. Revenues from the Company's Canadian natural gas pipelines under federal jurisdiction are subject to regulatory decisions by the CER. The tolls charged on these pipelines are based on revenue requirements designed to recover the costs of providing natural gas capacity for transportation services, which includes a return of and on capital, as approved by the CER. The Company's Canadian natural gas pipelines are generally not subject to earnings volatility related to variances in revenues and costs. These variances, except as related to incentive arrangements, are generally subject to deferral treatment and are recovered or refunded in future tolls. Revenues recognized prior to a CER decision on rates for that period reflect the CER's last approved return on equity (ROE) assumptions. Adjustments to revenues are recorded when the CER decision is received. Canadian natural gas pipelines' revenues are invoiced and received on a monthly basis. The Company does not take ownership of the natural gas that it transports for customers. U.S. Natural Gas Pipelines Capacity Arrangements and Transportation Revenues from the Company's U.S. natural gas pipelines are generated from contractual arrangements for committed capacity and from the transportation of natural gas. Revenues earned from firm contracted capacity arrangements are generally recognized ratably over the term of the contract regardless of the amount of natural gas that is transported. Transportation revenues for interruptible or volumetric-based services are recognized when the service is performed. The Company's U.S. interstate natural gas pipelines are subject to FERC regulations and, as a result, a portion of revenues collected may be subject to refund if invoiced during an interim period when a rate proceeding is ongoing. Allowances for these potential refunds are recognized using management's best estimate based on the facts and circumstances of the proceeding. Any allowances that are recognized during the proceeding process are refunded or retained at the time a regulatory decision becomes final. U.S. natural gas pipelines' revenues are invoiced and received on a monthly basis. The Company does not take ownership of the natural gas that it transports for customers. Natural Gas Storage and Other Revenues from the Company's regulated U.S. natural gas storage services are generated mainly from firm committed capacity storage contracts. The performance obligation in these contracts is the reservation of a specified amount of capacity for storage including specifications with regard to the amount of natural gas that can be injected or withdrawn on a daily basis. Revenues are recognized ratably over the contract period for firm committed capacity regardless of the amount of natural gas that is stored, and when gas is injected or withdrawn for interruptible or volumetric-based services. Natural gas storage services revenues are invoiced and received on a monthly basis. The Company does not take ownership of the natural gas that it stores for customers. The Company owns mineral rights associated with certain natural gas storage facilities. These mineral rights can be leased or contributed to producers of natural gas in return for a royalty interest which is recognized when natural gas and associated liquids are produced. Mexico Natural Gas Pipelines Capacity Arrangements and Transportation Revenues from certain of the Company's Mexico natural gas pipelines are primarily collected based on negotiated firm capacity contracts and are generally recognized ratably over the term of the contract. Transportation revenues related to interruptible or volumetric-based services are recognized when the service is performed. Mexico natural gas pipelines' revenues are invoiced and received on a monthly basis. The Company does not take ownership of the natural gas that it transports for customers. Other The Company generates revenues from operating and maintenance services provided on leased pipelines. Revenues earned from these services are recognized ratably over the term of the contract. Power and Energy Solutions Power Revenues from the Company's Power and Energy Solutions business are primarily derived from long-term contractual commitments to provide power capacity to meet the demands of the market and from the sale of electricity to both centralized markets and to customers. Power generation revenues also include revenues from the sale of steam to customers. Revenues and capacity payments are recognized as the services are provided and as electricity and steam is delivered. Power generation revenues are invoiced and received on a monthly basis. Natural Gas Storage and Other Non-regulated natural gas storage contracts include park, loan and term storage arrangements. Revenues are recognized as the services are provided. Term storage revenues are invoiced and received on a monthly basis. Revenues from ancillary services are recognized as the service is provided. Cash and Cash Equivalents The Company's Cash and cash equivalents consist of cash and highly liquid short-term investments with original maturities of three months or less and are recorded at cost, which approximates fair value. Inventories Inventories primarily consist of materials and supplies including spare parts and fuel, proprietary natural gas inventory in storage and emissions allowances and credits not held for compliance. The Company purchases certain emissions allowances and credits as part of bundled arrangements that also include the purchase of electricity for a fixed price. The cost allocated to emissions allowances and credits under such arrangements is based on observable market prices. Inventories are carried at the lower of cost and net realizable value. Assets Held for Sale The Company classifies assets as held for sale when management approves and commits to a formal plan to actively market a disposal group and expects the sale to close within the next 12 months. Upon classifying an asset as held for sale, the asset is recorded at the lower of its carrying amount or its estimated fair value, net of selling costs and any losses are recognized in net income. Gains related to the expected sale of these assets are not recognized until the transaction closes. Once an asset is classified as held for sale, depreciation expense is no longer recorded. Plant, Property and Equipment Natural Gas Pipelines Plant, property and equipment for natural gas pipelines is carried at cost. Depreciation is calculated on a straight-line basis once the assets are ready for their intended use. Pipeline and compression equipment are depreciated at annual rates ranging from 0.625 per cent to 6.67 per cent and metering and other plant equipment are depreciated at various rates reflecting their estimated useful lives. The cost of major overhauls of equipment is capitalized and depreciated over the estimated service lives of the overhauls. The cost of regulated natural gas pipelines includes an allowance for funds used during construction (AFUDC) consisting of a debt component and an equity component based on the rate of return on rate base approved by regulators. AFUDC is reflected as an increase in the cost of the assets in Plant, property and equipment with a corresponding increase in Allowance for funds used during construction in the Consolidated statement of income. The equity component of AFUDC is a non-cash expenditure. Interest is capitalized during construction of non-regulated natural gas pipelines. Natural gas pipelines' linepack and natural gas storage base gas are valued at cost and are maintained to ensure adequate pressure exists to transport natural gas through pipelines and deliver natural gas held in storage. Linepack and base gas are not depreciated. When rate-regulated natural gas pipelines retire plant, property and equipment from service, the original book cost is removed from the gross plant amount and recorded as a reduction to accumulated depreciation with no amount recorded to net income. Costs incurred to remove plant, property and equipment from service, net of any salvage proceeds, are also recorded in accumulated depreciation. Other The Company participates as a working interest partner in the development of certain Marcellus and Utica acreage. The working interest allows the Company to invest in drilling activities in addition to receiving a royalty interest in well production. The Company uses the successful efforts method of accounting for natural gas and crude oil resulting from its portion of drilling activities. Capitalized well costs are depleted based on the units of production method. Power and Energy Solutions Plant, property and equipment for Power and Energy Solutions assets are recorded at cost and, once the assets are ready for their intended use, depreciated by major component on a straight-line basis over their estimated service lives at average annual rates ranging from two per cent to 20 per cent. Other equipment is depreciated at various rates reflecting their estimated useful lives. The cost of major overhauls of equipment is capitalized and depreciated over the estimated service lives of the overhauls. Interest is capitalized on facilities under construction. When these assets are retired from plant, property and equipment, the original book cost and related accumulated depreciation are derecognized and any gain or loss is recorded in net income. Natural gas storage base gas, which is valued at original cost, represents gas volumes that are maintained to ensure adequate reservoir pressure exists to deliver gas held in storage. Base gas is not depreciated. Corporate Corporate plant, property and equipment is recorded at cost and depreciated on a straight-line basis over its estimated useful life at average annual rates ranging from four per cent to 20 per cent. Capital Projects in Development The Company capitalizes project costs once advancement of the project to construction stage is probable or costs are otherwise likely to be recoverable. The Company capitalizes interest costs for non-regulated projects in development and AFUDC for regulated projects in development. Capital projects in development are included in Other long-term assets on the Consolidated balance sheet. These represent larger projects that generally require regulatory or other approvals before physical construction can begin. Once approvals are received, projects are moved to plant, property and equipment under construction. Leases The Company determines if a contract contains a lease at inception, or upon modification, of a contract by using judgment in assessing the following aspects: 1) the contract specifies an identified asset which is physically distinct or, if not physically distinct, represents substantially all of the capacity of the asset; 2) the contract provides the customer with the right to obtain substantially all of the economic benefits from the use of the asset; and 3) the customer has the right to direct how and for what purpose the identified asset is used throughout the period of the contract. If the contract is determined to contain a lease, further judgment is required to identify separate lease components of the arrangement by assessing whether the lessee can benefit from the right of use either on its own or together with other resources that are readily available to the lessee, as well as if the right of use is neither highly dependent on, nor highly interrelated, with the other rights to use underlying assets in the contract. The Company considers non-lease components as distinct elements of a contract that are not related to the use of the leased asset. A good or service that is provided to a customer is distinct if: 1) the customer can benefit from the good or service either on its own or together with other resources that are readily available to the customer; and 2) the entity’s promise to transfer the good or service to the customer is separately identifiable from other promises in the contract. The Company applies the practical expedient to not separate lease and non-lease components for all lessee contracts and facilities for which the Company is the lessor in an operating lease. Lessee Accounting Policy Operating leases are recognized as right-of-use (ROU) assets and included in Plant, property and equipment while corresponding liabilities are included in Accounts payable and other and Other long-term liabilities on the Consolidated balance sheet. Operating lease ROU assets and operating lease liabilities are recognized based on the present value of the future minimum lease payments over the lease term at the commencement date of the lease agreement. Lease terms may include options to extend or terminate the lease when it is reasonably certain that the Company will exercise that option. As the Company's lease contracts do not provide an implicit interest rate, the Company uses its incremental borrowing rate based on the information available at commencement date, or upon modification of a lease, in determining the present value of future payments. Operating lease expense is recognized on a straight-line basis over the lease term and included in Plant operating costs and other in the Consolidated statement of income. The Company applies the practical expedient to not recognize ROU assets or lease liabilities for leases that qualify for the short-term lease recognition exemption. Lessor Accounting Policy The Company provides transportation and other services on certain assets to customers according to long-term service agreements through sales-type and operating leases. In a sales-type lease, the Company measures the total consideration within the contract at lease commencement, or upon modification of a lease. When a lease arrangement contains more than one lease and/or non-lease component, a portion of the contract consideration is allocated to each component based on the stand-alone selling price for each distinct service. The Company applies judgment to determine reasonable estimates of the expected future cost of satisfying the performance obligations of each service. The payments associated with lease components are apportioned between a reduction in the net investment in lease and sales-type lease income. At lease commencement, the Company recognizes a net investment in lease equal to the present value of both the future lease payments and the estimated residual value of the leased asset discounted at the rate implicit in the lease. The plant, property and equipment of the leased asset is derecognized, with related gains/losses, if any, recognized in the Consolidated statement of income. Sales-type lease income is determined using the rate implicit in the lease and is recorded in Revenues. The Company is the lessor within certain other contracts, including PPAs, that are accounted for as operating leases. In an operating lease, the leased asset remains capitalized in Plant, property and equipment on the Consolidated balance sheet and is depreciated over its useful life, while lease payments are recognized as revenue over the term of the lease on a straight-line basis. Variable lease payments are recognized as income in the period in which they occur. Impairment of Long-Lived Assets The Company reviews long-lived assets such as plant, property and equipment and capital projects in development for impairment whenever events or changes in circumstances indicate the carrying value may not be recoverable. If the total of the estimated undiscounted future cash flows for an asset within plant, property and equipment, or the estimated selling price of any long-lived asset is less than the carrying value of an asset, an impairment loss is recognized for the excess of the carrying value over the estimated fair value of the asset. Impairment of Equity Method Investments The Company reviews equity method investments for impairment when an event or change in circumstances has a significant adverse effect on the investment's fair value. Where the Company concludes an investment's fair value is below its carrying value, the Company then determines whether the impairment is other-than-temporary, and if so, an impairment loss is recognized for the excess of the carrying value over the estimated fair value of the investment, not exceeding the carrying value of the investment. Acquisitions and Goodwill The Company accounts for business combinations using the acquisition method of accounting and, accordingly, the assets and liabilities of the acquired entities are primarily measured at their estimated fair values at the date of acquisition. The excess of the fair value of the consideration transferred over the estimated fair value of the net assets acquired is classified as goodwill. Goodwill is not amortized and is tested for impairment on an annual basis, or more frequently if events or changes in circumstances indicate that it might be impaired. The annual review for goodwill impairment is performed at the reporting unit level which is one level below the Company's operating segments. The Company can initially assess qualitative factors to determine whether events or changes in circumstances indicate that goodwill might be impaired. The factors the Company considers include, but are not limited to, macroeconomic conditions, industry and market considerations, current valuation multiples and discount rates, cost factors, historical and forecasted financial results and events specific to that reporting unit. If the Company concludes that it is not more likely than not that the fair value of the reporting unit is greater than its carrying value, the Company will then perform a quantitative goodwill impairment test. The Company can elect to proceed directly to the quantitative goodwill impairment test for any of its reporting units. If the quantitative goodwill impairment test is performed, the Company compares the fair value of the reporting unit to its carrying value, including its goodwill. If the carrying value of a reporting unit exceeds its fair value, goodwill impairment is measured at the amount by which the reporting unit’s carrying value exceeds its fair value. The fair value of a reporting unit is determined by using a discounted cash flow model which requires the use of assumptions that may include, but are not limited to, revenue and capital expenditure projections, valuation multiples and discount rates. The Company has elected to allocate goodwill impairment charges first to goodwill that is non-deductible for income tax purposes, with any remaining charge allocated to tax-deductible goodwill. When a portion of a reporting unit that constitutes a business is disposed, goodwill associated with that business is included in the carrying amount of the business in determining the gain or loss on disposal. The amount of goodwill disposed is determined based on the relative fair values of the business to be disposed and the portion of the reporting unit that will be retained. A goodwill impairment test will be completed for the goodwill that will be retained. Non-Controlling Interests Non-controlling interests (NCI) represent third-party ownership interests in certain consolidated subsidiaries of the Company. Partial dispositions which result in a change in the Company's ownership interest, but do not result in a change in control, of a subsidiary that constitutes a business are accounted for as equity transactions. No gain or loss is recognized in earnings. At the time of partial disposition, NCI is recorded as the third party's ownership interest in the Company's carrying value of the net assets of the subsidiary. Any difference between the amount by which the NCI is adjusted and the fair value of the consideration paid or received is recognized in Additional paid-in capital and/or Retained earnings (Accumulated deficit). Loans and Receivables Loans receivable from affiliates and accounts receivable are measured at amortized cost. Impairment of Financial Assets The Company reviews financial assets, inclusive of net investment in leases and certain contract assets, carried at amortized cost for impairment using the lifetime expected loss of the financial asset at initial recognition and throughout the life of the financial asset. An expected credit loss (ECL) is calculated using a model and methodology based on assumptions and judgment considering historical data, current counterparty information as well as reasonable and supportable forecasts of future economic conditions. The ECL is recognized in Plant operating costs and other in the Consolidated statement of income, and is presented on the Consolidated balance sheet as a reduction to the carrying value of the related financial asset. Restricted Investments The Company has certain investments that are restricted as to their withdrawal and use. These restricted investments are recorded at fair value on the Consolidated balance sheet. As a result of the CER’s Land Matters Consultation Initiative (LMCI), TC Energy is required to collect funds to cover estimated future pipeline abandonment costs for larger CER-regulated Canadian pipelines. Funds collected are placed in trusts that hold and invest the funds and are accounted for as restricted investments (LMCI restricted investments). LMCI restricted investments may only be used to fund the abandonment of the CER-regulated pipeline facilities, therefore, a corresponding regulatory liability is recorded on the Consolidated balance sheet. The Company also has other restricted investments that have been set aside to fund insurance claim losses to be paid by the Company's wholly-owned captive insurance subsidiary. Income Taxes The Company uses the asset and liability method of accounting for income taxes. This method requires the recognition of deferred income tax assets and liabilities for future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred income tax assets and liabilities are measured using enacted tax rates at the balance sheet date that are anticipated to apply to taxable income in the years in which temporary differences are expected to be reversed or settled. Changes to these balances are recognized in net income in the period in which they occur, except for changes in balances related to regulated natural gas pipelines which are deferred until they are refunded or recovered in tolls, as permitted by the regulator. Deferred income tax assets and liabilities are classified as non-current on the Consolidated balance sheet. The Company’s exposure to uncertain tax positions is evaluated and a provision is made where it is more likely than not that this exposure will materialize. Canadian income taxes are not provided for on the unremitted earnings of foreign investments that the Company does not intend to repatriate in the foreseeable future. Any interest and/or penalty incurred related to income tax is reflected in Income tax expense. Asset Retirement Obligations The Company recognizes the fair value of a liability for asset retirement obligations (ARO) in the period in which it is incurred, when a legal obligation exists and a reasonable estimate of fair value can be made. The fair value is added to the carrying amount of the associated asset and the liability is accreted through charges to Plant operating costs and other in the Consolidated statement of income. In determining the fair value of ARO, the following assumptions are used: •the expected retirement date •the scope and cost of abandonment and reclamation activities that are required •appropriate inflation and discount rates. The Company's AROs are substantially related to its power generation facilities. The scope and timing of asset retirements related to the Company's natural gas pipelines and storage facilities are indeterminable because the Company intends to operate them as long as there is supply and demand. As a result, the Company has not recorded an amount for ARO related to these assets. Environmental Liabilities and Emission Allowances and Credits The Company records liabilities on an undiscounted basis for environmental remediation efforts that are likely to occur and where the cost can be reasonably estimated. These estimates, including associated legal costs, are based on available information using existing technology and enacted laws and regulations and are subject to revision in future periods based on actual costs incurred or new circumstances. TC Energy evaluates recoveries from insurers and other third parties separately from the liability and, when recovery is probable, an asset is recorded separately from the associated liability. These recoveries are presented, along with environmental remediation costs, on a net basis in Plant operating costs and other in the Consolidated statement of income. Variations in one or more of the categories described above could result in additional costs such as fines, penalties and/or expenditures associated with litigation and settlement of claims with respect to environmental liabilities. Emission allowances or credits purchased for compliance are recorded on the Consolidated balance sheet at historical cost and derecognized when they are utilized or cancelled/retired by government agencies. Compliance costs are expensed when incurred. Allowances granted to or internally generated by TC Energy are not attributed a value for accounting purposes. When required, TC Energy accrues emission liabilities on the Consolidated balance sheet using the best estimate of the amount required to settle the compliance obligation. Allowances and credits not used for compliance are sold and any gain or loss is recorded in Revenues within the Power and Energy Solutions segment in the Consolidated statement of income. The Company records allowances and credits held for compliance in Other current assets and Other long-term assets on the Consolidated balance sheet. Allowances and credits not held for compliance are classified as Inventories on the Consolidated balance sheet. Stock Options and Other Compensation Programs The Company no longer issues stock options to employees or officers. Stock options granted before 2024 were recorded using the fair value method. Under this method, compensation expense is measured at the grant date based on the fair value as calculated using a binomial model and is recognized on a straight-line basis over the vesting period with an offset to Additional paid-in capital. Forfeitures are accounted for when they occur. Upon exercise of stock options, amounts originally recorded against Additional paid-in capital are reclassified to Common shares on the Consolidated balance sheet. The Company has medium-term incentive plans under which payments are made to eligible employees. The expense related to these incentive plans is accounted for on an accrual basis. Under these plans, benefits vest when certain conditions are met, including the employees' continued employment during a specified period and achievement of specified corporate performance targets. Employee Post-Retirement Benefits The Company sponsors defined benefit pension plans (DB Plans), defined contribution plans (DC Plans), savings plans and other post-retirement benefit plans (OPEB Plans). Contributions made by the Company to the DC Plans and savings plans are expensed in the period in which contributions are made. The cost of the DB Plans and OPEB Plans received by employees is actuarially determined using the projected benefit method pro-rated based on service and management's best estimate of expected plan investment performance, salary escalation, retirement age of employees and expected health care costs. The DB Plans' assets are measured at fair value at December 31 of each year. The expected return on the DB Plans' assets is determined using market-related values based on a five-year moving average value for all of the DB Plans' assets. Past service costs are amortized over the expected average remaining service life (EARSL) of the employees. Adjustments arising from plan amendments are amortized on a straight-line basis over the EARSL of employees active at the date of amendment. The Company recognizes the overfunded or underfunded status of its DB Plans as an asset or liability, respectively, on its Consolidated balance sheet and recognizes changes in that funded status through Other comprehensive income (loss)(OCI) in the year in which the change occurs. The excess of net actuarial gains or losses over 10 per cent of the greater of the benefit obligation and the market-related value of the DB Plans' assets, if any, is amortized out of AOCI and into net income over the EARSL of the active employees. When the restructuring of a benefit plan gives rise to both a curtailment and a settlement, the curtailment is accounted for prior to the settlement. For certain regulated operations, post-retirement benefit amounts are recoverable through tolls as benefits are funded. The Company records any unrecognized gains or losses or changes in actuarial assumptions related to these post-retirement benefit plans as either regulatory assets or liabilities. The regulatory assets or liabilities are amortized on a straight-line basis over the EARSL of active employees. Foreign Currency Transactions and Translation Foreign currency transactions are those transactions whose terms are denominated in a currency other than the currency of the primary economic environment in which the Company or reporting subsidiary operates. This is referred to as the functional currency. Transactions denominated in foreign currencies are translated into the functional currency using the exchange rate prevailing at the date of the transaction. Monetary assets and liabilities denominated in foreign currencies are translated to the functional currency using the rate of exchange in effect at the balance sheet date whereas non-monetary assets and liabilities are translated at the historical rate of exchange in effect on the date of the transaction. Exchange gains and losses resulting from translation of monetary assets and liabilities are recorded in net income except for exchange gains and losses on any foreign currency debt related to Canadian regulated natural gas pipelines, which are deferred until they are refunded or recovered in tolls, as permitted by the CER. Gains and losses arising from translation of foreign operations' functional currencies to the Company's Canadian dollar reporting currency are reflected in OCI until the operations are sold, at which time the gains and losses are reclassified to net income. For partial dispositions of foreign operations that do not result in a change of control, or dispositions of foreign operations other than by sale, gains and losses are reclassified within equity. Asset and liability accounts are translated at the rate of exchange in effect at the balance sheet date while revenues, expenses, gains and losses are translated at the exchange rate prevailing at the date of the transaction. The Company's U.S. dollar-denominated debt and certain derivative hedging instruments have been designated as a hedge of the net investment in foreign subsidiaries and, as a result, the unrealized foreign exchange gains and losses on the U.S. dollar-denominated debt and derivatives are also reflected in OCI. Derivative Instruments and Hedging Activities All derivative instruments are recorded on the Consolidated balance sheet at fair value, unless they qualify for and are designated under a normal purchase and normal sales exemption, or are considered to meet other permitted exemptions. The Company applies hedge accounting to arrangements that qualify for and are designated for hedge accounting treatment. This includes fair value and cash flow hedges as well as hedges of foreign currency exposures of net investments in foreign operations. Hedge accounting is discontinued prospectively if the hedging relationship ceases to be effective or the hedging or hedged items cease to exist as a result of maturity, expiry, sale, termination, cancellation or exercise. In a fair value hedging relationship, the carrying value of the hedged item is adjusted for changes in fair value attributable to the hedged risk and these changes are recognized in net income. Changes in the fair value of the hedged item, to the extent that the hedging relationship is effective, are offset by changes in the fair value of the hedging item, which are also recorded in net income. Changes in the fair value of foreign exchange and interest rate fair value hedges are recorded in Interest income and other and Interest expense, respectively. If hedge accounting is discontinued, the carrying value of the hedged item is no longer adjusted and the cumulative fair value adjustments to the carrying value of the hedged item are amortized to net income over the remaining term of the original hedging relationship. In a cash flow hedging relationship, the change in the fair value of the hedging derivative is recognized in OCI. When hedge accounting is discontinued, the amounts recognized previously in AOCI are reclassified to Revenues, Interest expense and Interest income and other, as appropriate, during the periods when the variability in cash flows of the hedged item affects net income or as the original hedged item settles. Gains and losses on derivatives are reclassified immediately to net income from AOCI when the hedged item is sold or terminated early, or when it becomes probable that the anticipated transaction will not occur. Termination payments on interest rate derivatives are classified as a financing activity in the Consolidated statement of cash flows. In hedging the foreign currency exposure of a net investment in a foreign operation, the foreign exchange gains and losses on the hedging instruments are recognized in OCI. The amounts recognized previously in AOCI are reclassified consistent with gains and losses arising from the translation of foreign operations, when the foreign operation is either entirely or partially disposed of. In some cases, derivatives do not meet the specific criteria for hedge accounting treatment. In these instances, the changes in fair value are recorded in net income in the period of change. Gains and losses arising from changes in the fair value of derivatives accounted for as part of RRA, including those that qualify for hedge accounting treatment, are refunded or recovered through the tolls charged by the Company. As a result, these gains and losses are deferred as regulatory liabilities or regulatory assets and are refunded to or collected from rate payers in subsequent periods when the derivative settles. Derivatives embedded in other financial instruments or contracts (host instrument) are recorded as separate derivatives. Embedded derivatives are measured at fair value if their economic characteristics are not clearly and closely related to those of the host instrument, their terms are the same as those of a stand-alone derivative and the total contract is not held for trading or accounted for at fair value. When changes in the fair value of embedded derivatives are measured separately, they are included in net income. Long-Term Debt Transaction Costs and Issuance Costs The Company records long-term debt transaction costs and issuance costs as a deduction from the carrying amount of the related debt liability and amortizes these costs using the effective interest method except those related to the Canadian natural gas regulated pipelines, which continue to be amortized on a straight-line basis in accordance with the provisions of regulatory tolling mechanisms. Guarantees Upon issuance, the Company records the fair value of certain guarantees entered into by the Company on behalf of a partially-owned entity or by partially-owned entities for which contingent payments may be made. The fair value of these guarantees is estimated by discounting the cash flows that would be incurred by the Company if letters of credit were used in place of the guarantees as appropriate in the circumstances. Guarantees are recorded as an increase to Equity investments or Plant, property and equipment and a corresponding liability is recorded in Other long-term liabilities. The release from the obligation is recognized either over the term of the guarantee or upon expiration or settlement of the guarantee. Variable Interest Entities A VIE is a legal entity that does not have sufficient equity at risk to finance its activities without additional subordinated financial support or is structured such that equity investors lack the ability to make significant decisions relating to the entity’s operations through voting rights or do not substantively participate in the gains and losses of the entity. The assessment of whether an entity is a VIE and, if so, whether the Company is the primary beneficiary, is completed at the inception of the entity or at a reconsideration event. Consolidated VIEs The Company's consolidated VIEs consist of legal entities where the Company has a variable interest and for which it is considered the primary beneficiary. As the primary beneficiary, the Company has the power, through voting or similar rights, to direct the activities of the VIE that most significantly impact economic performance including: purchasing or selling significant assets; maintenance and operations of assets; incurring additional indebtedness; or determining the strategic operating direction of the entity. In addition, the Company has the obligation to absorb losses or the right to receive benefits from the consolidated VIE that could potentially be significant to the VIE. Non-Consolidated VIEs The Company’s non-consolidated VIEs consist of legal entities where the Company has a variable interest but is not the primary beneficiary as it does not have the power (either explicit or implicit), through voting or similar rights, to direct the activities that most significantly impact the economic performance of these VIEs or where this power is shared with third parties. The Company contributes capital to these VIEs and receives ownership interests that provide it with residual claims on assets after liabilities are paid. Non-consolidated VIEs are accounted for as equity investments. The Company’s maximum exposure to loss is the maximum loss that could potentially be recorded through net income in future periods as a result of the Company’s variable interest in a VIE.

NOTES PAYABLE

12 Months Ended

Dec. 31, 2025

Short-Term Debt [Abstract]

NOTES PAYABLE


at December 31	2025			2024
(millions of Canadian $, unless otherwise noted)	Outstanding	Weighted Average Interest Rate per Annum		Outstanding	Weighted Average Interest Rate per Annum

Canada1	584	3.9	%	308	4.7	%
U.S. (2025 – US$449; 2024 – US$55)	616	4.1	%	79	4.7	%

	1,200			387

1At December 31, 2025, Notes payable consisted of Canadian dollar-denominated notes of $68 million (2024 – nil) and U.S. dollar-denominated notes of US$348 million (2024 – US$214 million).

At December 31, 2025, Notes payable reflects short-term borrowings in Canada by TCPL and in the U.S. by TransCanada PipeLine USA Ltd. (TCPL USA) and Columbia Pipelines Holdings Company LLC (CPHC). At December 31, 2024, there were no amounts outstanding at CPHC.

At December 31, 2025, total committed revolving and demand credit facilities were $11.9 billion (2024 – $12.2 billion). When drawn, interest on these lines of credit is charged at negotiated floating rates of Canadian and U.S. banks, and at other negotiated financial bases. These unsecured credit facilities included the following:

at December 31

(billions of Canadian $, unless otherwise noted)

2025

2024

Borrowers

Description

Matures

Total Facilities

Unused Capacity1

Total Facilities

Committed, syndicated, revolving, extendible, senior unsecured credit facilities2:

TCPL

Supports commercial paper program and for general corporate purposes

December 2030

3.0

2.9

3.0

TCPL / TCPL USA

Supports commercial paper programs and for general corporate purposes of the borrowers, guaranteed by TCPL

December 2026

US 1.0

US 0.8

US 1.0

TCPL / TCPL USA

Supports commercial paper programs and for general corporate purposes of the borrowers, guaranteed by TCPL

December 2028

US 2.5

US 2.3

US 2.5

Columbia Pipelines Holding Company LLC3

Supports commercial paper program and general corporate purposes of the borrower

December 2028

US 1.5

US 1.1

US 1.5

Demand senior unsecured revolving credit facilities2:

TCPL / TCPL USA

Supports the issuance of letters of credit and provides additional liquidity; TCPL USA facility guaranteed by TCPL

Demand

2.0

1.3

2.0

1Unused capacity is net of commercial paper outstanding and facility draws.

2Provisions of various trust indentures and credit arrangements with the Company's subsidiaries can restrict their ability to declare and pay dividends or make distributions under certain circumstances. If such restrictions apply, they may, in turn, have an impact on the Company's ability to declare and pay dividends on common and preferred shares. These trust indentures and credit arrangements also require the Company to comply with various affirmative and negative covenants and maintain certain financial ratios. At December 31, 2025, the Company was in compliance with all financial covenants.

3Columbia Pipelines Holding Company LLC is a partially-owned subsidiary of TC Energy with 40 per cent non-controlling interest.

4Or the U.S. dollar equivalent.

For the year ended December 31, 2025, the cost to maintain the above facilities was $15 million (2024 – $18 million; 2023 – $16 million).

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - Notional and Maturity Summary (Details) $ in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2025 USD ($) GWh MWh Bcf	Dec. 31, 2024 USD ($) GWh Bcf	Dec. 31, 2025 MXN ($)	Dec. 31, 2024 MXN ($)
Foreign exchange
Derivative [Line Items]
Notional amount	$ 6,342	$ 5,648	$ 15,750	$ 16,750
Interest rate
Derivative [Line Items]
Notional amount \| $	$ 2,950	$ 2,800
Power
Derivative [Line Items]
Notional amount, energy (gwh) \| MWh	50
Power \| Commodities \| Sales
Derivative [Line Items]
Notional amount, energy (gwh) \| GWh	10,221	10,192
Natural Gas \| Commodities \| Sales
Derivative [Line Items]
Notional amount, volume (bcf and mmbbls) \| Bcf	26	53

LEASES - Sale Type Leases Narrative (Details) $ in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2025 CAD ($)	Dec. 31, 2025 USD ($)	Dec. 31, 2024 CAD ($)	Dec. 31, 2023 CAD ($)	Dec. 31, 2025 USD ($)
Lessee, Lease, Description [Line Items]
Payment for receivables	$ 351				$ 251
Expected credit loss provision (Note 27)	83		$ (22)	$ (83)
Southeast Gateway Pipeline
Lessee, Lease, Description [Line Items]
Net investment in lease	6,600	$ 4,800
Expected credit loss provision	113
TGNH
Lessee, Lease, Description [Line Items]
Payment for receivables	(141)		(59)
Expected credit loss provision (Note 27)	$ 84		$ (23)	$ (73)

- Definition

Amount of allowance for credit loss on financing receivable. Excludes allowance for financing receivable covered under loss sharing agreement.

+ References + Details

EMPLOYEE POST-RETIREMENT BENEFITS - Measured at Fair Value (Details) - CAD ($) $ in Millions	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Employee post-retirement benefits
Plan assets at fair value	$ 4,431	$ 4,397
Percentage of Plan Assets	100.00%	100.00%
Pension Benefit Plans
Employee post-retirement benefits
Plan assets at fair value	$ 4,081	$ 3,948	$ 3,697
Percentage of Plan Assets	100.00%	100.00%
Quoted Prices in Active Markets (Level I)
Employee post-retirement benefits
Plan assets at fair value	$ 1,873	$ 2,324
Significant Other Observable Inputs (Level II)
Employee post-retirement benefits
Plan assets at fair value	1,896	1,483
Significant Unobservable Inputs (Level III)
Employee post-retirement benefits
Plan assets at fair value	662	590	$ 562
Cash and Cash Equivalents
Employee post-retirement benefits
Plan assets at fair value	$ 130	$ 138
Percentage of Plan Assets	3.00%	3.00%
Cash and Cash Equivalents \| Quoted Prices in Active Markets (Level I)
Employee post-retirement benefits
Plan assets at fair value	$ 130	$ 138
Cash and Cash Equivalents \| Significant Other Observable Inputs (Level II)
Employee post-retirement benefits
Plan assets at fair value	0	0
Cash and Cash Equivalents \| Significant Unobservable Inputs (Level III)
Employee post-retirement benefits
Plan assets at fair value	0	0
Equity Securities, Canadian
Employee post-retirement benefits
Plan assets at fair value	$ 129	$ 128
Percentage of Plan Assets	3.00%	3.00%
Equity Securities, Canadian \| Quoted Prices in Active Markets (Level I)
Employee post-retirement benefits
Plan assets at fair value	$ 129	$ 128
Equity Securities, Canadian \| Significant Other Observable Inputs (Level II)
Employee post-retirement benefits
Plan assets at fair value	0	0
Equity Securities, Canadian \| Significant Unobservable Inputs (Level III)
Employee post-retirement benefits
Plan assets at fair value	0	0
Equity Securities, U.S.
Employee post-retirement benefits
Plan assets at fair value	$ 969	$ 1,234
Percentage of Plan Assets	22.00%	28.00%
Equity Securities, U.S. \| Quoted Prices in Active Markets (Level I)
Employee post-retirement benefits
Plan assets at fair value	$ 969	$ 1,234
Equity Securities, U.S. \| Significant Other Observable Inputs (Level II)
Employee post-retirement benefits
Plan assets at fair value	0	0
Equity Securities, U.S. \| Significant Unobservable Inputs (Level III)
Employee post-retirement benefits
Plan assets at fair value	0	0
Equity Securities, International
Employee post-retirement benefits
Plan assets at fair value	$ 327	$ 391
Percentage of Plan Assets	7.00%	9.00%
Equity Securities, International \| Quoted Prices in Active Markets (Level I)
Employee post-retirement benefits
Plan assets at fair value	$ 107	$ 182
Equity Securities, International \| Significant Other Observable Inputs (Level II)
Employee post-retirement benefits
Plan assets at fair value	220	209
Equity Securities, International \| Significant Unobservable Inputs (Level III)
Employee post-retirement benefits
Plan assets at fair value	0	0
Equity Securities, Global
Employee post-retirement benefits
Plan assets at fair value	$ 104	$ 100
Percentage of Plan Assets	2.00%	2.00%
Equity Securities, Global \| Quoted Prices in Active Markets (Level I)
Employee post-retirement benefits
Plan assets at fair value	$ 0	$ 0
Equity Securities, Global \| Significant Other Observable Inputs (Level II)
Employee post-retirement benefits
Plan assets at fair value	104	100
Equity Securities, Global \| Significant Unobservable Inputs (Level III)
Employee post-retirement benefits
Plan assets at fair value	0	0
Equity Securities, Emerging
Employee post-retirement benefits
Plan assets at fair value	$ 165	$ 216
Percentage of Plan Assets	4.00%	5.00%
Equity Securities, Emerging \| Quoted Prices in Active Markets (Level I)
Employee post-retirement benefits
Plan assets at fair value	$ 33	$ 66
Equity Securities, Emerging \| Significant Other Observable Inputs (Level II)
Employee post-retirement benefits
Plan assets at fair value	132	150
Equity Securities, Emerging \| Significant Unobservable Inputs (Level III)
Employee post-retirement benefits
Plan assets at fair value	0	0
Fixed Income Securities, Canadian Bonds, Federal
Employee post-retirement benefits
Plan assets at fair value	$ 16	$ 55
Percentage of Plan Assets	0.00%	1.00%
Fixed Income Securities, Canadian Bonds, Federal \| Quoted Prices in Active Markets (Level I)
Employee post-retirement benefits
Plan assets at fair value	$ 0	$ 0
Fixed Income Securities, Canadian Bonds, Federal \| Significant Other Observable Inputs (Level II)
Employee post-retirement benefits
Plan assets at fair value	16	55
Fixed Income Securities, Canadian Bonds, Federal \| Significant Unobservable Inputs (Level III)
Employee post-retirement benefits
Plan assets at fair value	0	0
Fixed Income Securities, Canadian Bonds, Provincial
Employee post-retirement benefits
Plan assets at fair value	$ 514	$ 312
Percentage of Plan Assets	12.00%	7.00%
Fixed Income Securities, Canadian Bonds, Provincial \| Quoted Prices in Active Markets (Level I)
Employee post-retirement benefits
Plan assets at fair value	$ 0	$ 0
Fixed Income Securities, Canadian Bonds, Provincial \| Significant Other Observable Inputs (Level II)
Employee post-retirement benefits
Plan assets at fair value	514	312
Fixed Income Securities, Canadian Bonds, Provincial \| Significant Unobservable Inputs (Level III)
Employee post-retirement benefits
Plan assets at fair value	0	0
Fixed Income Securities, Canadian Bonds, Municipal
Employee post-retirement benefits
Plan assets at fair value	$ 19	$ 14
Percentage of Plan Assets	0.00%	0.00%
Fixed Income Securities, Canadian Bonds, Municipal \| Quoted Prices in Active Markets (Level I)
Employee post-retirement benefits
Plan assets at fair value	$ 0	$ 0
Fixed Income Securities, Canadian Bonds, Municipal \| Significant Other Observable Inputs (Level II)
Employee post-retirement benefits
Plan assets at fair value	19	14
Fixed Income Securities, Canadian Bonds, Municipal \| Significant Unobservable Inputs (Level III)
Employee post-retirement benefits
Plan assets at fair value	0	0
Fixed Income Securities, Canadian Bonds, Corporate
Employee post-retirement benefits
Plan assets at fair value	$ 483	$ 323
Percentage of Plan Assets	11.00%	7.00%
Fixed Income Securities, Canadian Bonds, Corporate \| Quoted Prices in Active Markets (Level I)
Employee post-retirement benefits
Plan assets at fair value	$ 0	$ 0
Fixed Income Securities, Canadian Bonds, Corporate \| Significant Other Observable Inputs (Level II)
Employee post-retirement benefits
Plan assets at fair value	483	323
Fixed Income Securities, Canadian Bonds, Corporate \| Significant Unobservable Inputs (Level III)
Employee post-retirement benefits
Plan assets at fair value	0	0
Fixed Income Securities, U.S. Bonds, Federal
Employee post-retirement benefits
Plan assets at fair value	$ 407	$ 406
Percentage of Plan Assets	9.00%	9.00%
Fixed Income Securities, U.S. Bonds, Federal \| Quoted Prices in Active Markets (Level I)
Employee post-retirement benefits
Plan assets at fair value	$ 147	$ 151
Fixed Income Securities, U.S. Bonds, Federal \| Significant Other Observable Inputs (Level II)
Employee post-retirement benefits
Plan assets at fair value	260	255
Fixed Income Securities, U.S. Bonds, Federal \| Significant Unobservable Inputs (Level III)
Employee post-retirement benefits
Plan assets at fair value	0	0
Fixed Income Securities, U.S. Bonds, Municipal
Employee post-retirement benefits
Plan assets at fair value	$ 1	$ 1
Percentage of Plan Assets	0.00%	0.00%
Fixed Income Securities, U.S. Bonds, Municipal \| Quoted Prices in Active Markets (Level I)
Employee post-retirement benefits
Plan assets at fair value	$ 0	$ 0
Fixed Income Securities, U.S. Bonds, Municipal \| Significant Other Observable Inputs (Level II)
Employee post-retirement benefits
Plan assets at fair value	1	1
Fixed Income Securities, U.S. Bonds, Municipal \| Significant Unobservable Inputs (Level III)
Employee post-retirement benefits
Plan assets at fair value	0	0
Fixed Income Securities, U.S. Bonds, Corporate
Employee post-retirement benefits
Plan assets at fair value	$ 378	$ 404
Percentage of Plan Assets	9.00%	9.00%
Fixed Income Securities, U.S. Bonds, Corporate \| Quoted Prices in Active Markets (Level I)
Employee post-retirement benefits
Plan assets at fair value	$ 185	$ 246
Fixed Income Securities, U.S. Bonds, Corporate \| Significant Other Observable Inputs (Level II)
Employee post-retirement benefits
Plan assets at fair value	193	158
Fixed Income Securities, U.S. Bonds, Corporate \| Significant Unobservable Inputs (Level III)
Employee post-retirement benefits
Plan assets at fair value	0	0
Fixed Income Securities, International, Government
Employee post-retirement benefits
Plan assets at fair value	$ 22	$ 21
Percentage of Plan Assets	1.00%	1.00%
Fixed Income Securities, International, Government \| Quoted Prices in Active Markets (Level I)
Employee post-retirement benefits
Plan assets at fair value	$ 3	$ 4
Fixed Income Securities, International, Government \| Significant Other Observable Inputs (Level II)
Employee post-retirement benefits
Plan assets at fair value	19	17
Fixed Income Securities, International, Government \| Significant Unobservable Inputs (Level III)
Employee post-retirement benefits
Plan assets at fair value	0	0
Fixed Income Securities, International, Corporate
Employee post-retirement benefits
Plan assets at fair value	$ 96	$ 66
Percentage of Plan Assets	2.00%	2.00%
Fixed Income Securities, International, Corporate \| Quoted Prices in Active Markets (Level I)
Employee post-retirement benefits
Plan assets at fair value	$ 0	$ 0
Fixed Income Securities, International, Corporate \| Significant Other Observable Inputs (Level II)
Employee post-retirement benefits
Plan assets at fair value	96	66
Fixed Income Securities, International, Corporate \| Significant Unobservable Inputs (Level III)
Employee post-retirement benefits
Plan assets at fair value	0	0
Fixed Income Securities, International, Mortgage-backed
Employee post-retirement benefits
Plan assets at fair value	$ 60	$ 60
Percentage of Plan Assets	1.00%	1.00%
Fixed Income Securities, International, Mortgage-backed \| Quoted Prices in Active Markets (Level I)
Employee post-retirement benefits
Plan assets at fair value	$ 40	$ 37
Fixed Income Securities, International, Mortgage-backed \| Significant Other Observable Inputs (Level II)
Employee post-retirement benefits
Plan assets at fair value	20	23
Fixed Income Securities, International, Mortgage-backed \| Significant Unobservable Inputs (Level III)
Employee post-retirement benefits
Plan assets at fair value	0	0
Fixed Income Securities, International, Net forward contract
Employee post-retirement benefits
Plan assets at fair value	$ (184)	$ (201)
Percentage of Plan Assets	4.00%	4.00%
Fixed Income Securities, International, Net forward contract \| Quoted Prices in Active Markets (Level I)
Employee post-retirement benefits
Plan assets at fair value	$ 0	$ 0
Fixed Income Securities, International, Net forward contract \| Significant Other Observable Inputs (Level II)
Employee post-retirement benefits
Plan assets at fair value	(184)	(201)
Fixed Income Securities, International, Net forward contract \| Significant Unobservable Inputs (Level III)
Employee post-retirement benefits
Plan assets at fair value	0	0
Real estate
Employee post-retirement benefits
Plan assets at fair value	$ 292	$ 276
Percentage of Plan Assets	7.00%	6.00%
Real estate \| Quoted Prices in Active Markets (Level I)
Employee post-retirement benefits
Plan assets at fair value	$ 0	$ 0
Real estate \| Significant Other Observable Inputs (Level II)
Employee post-retirement benefits
Plan assets at fair value	0	0
Real estate \| Significant Unobservable Inputs (Level III)
Employee post-retirement benefits
Plan assets at fair value	292	276
Infrastructure
Employee post-retirement benefits
Plan assets at fair value	$ 315	$ 282
Percentage of Plan Assets	7.00%	7.00%
Infrastructure \| Quoted Prices in Active Markets (Level I)
Employee post-retirement benefits
Plan assets at fair value	$ 0	$ 0
Infrastructure \| Significant Other Observable Inputs (Level II)
Employee post-retirement benefits
Plan assets at fair value	0	0
Infrastructure \| Significant Unobservable Inputs (Level III)
Employee post-retirement benefits
Plan assets at fair value	315	282
Private equity funds
Employee post-retirement benefits
Plan assets at fair value	$ 55	$ 32
Percentage of Plan Assets	1.00%	1.00%
Private equity funds \| Quoted Prices in Active Markets (Level I)
Employee post-retirement benefits
Plan assets at fair value	$ 0	$ 0
Private equity funds \| Significant Other Observable Inputs (Level II)
Employee post-retirement benefits
Plan assets at fair value	0	0
Private equity funds \| Significant Unobservable Inputs (Level III)
Employee post-retirement benefits
Plan assets at fair value	55	32
Funds held on deposit
Employee post-retirement benefits
Plan assets at fair value	$ 130	$ 138
Percentage of Plan Assets	3.00%	3.00%
Funds held on deposit \| Quoted Prices in Active Markets (Level I)
Employee post-retirement benefits
Plan assets at fair value	$ 130	$ 138
Funds held on deposit \| Significant Other Observable Inputs (Level II)
Employee post-retirement benefits
Plan assets at fair value	0	0
Funds held on deposit \| Significant Unobservable Inputs (Level III)
Employee post-retirement benefits
Plan assets at fair value	0	0
Derivatives
Employee post-retirement benefits
Plan assets at fair value	$ 3	$ 1
Percentage of Plan Assets	0.00%	0.00%
Derivatives \| Quoted Prices in Active Markets (Level I)
Employee post-retirement benefits
Plan assets at fair value	$ 0	$ 0
Derivatives \| Significant Other Observable Inputs (Level II)
Employee post-retirement benefits
Plan assets at fair value	3	1
Derivatives \| Significant Unobservable Inputs (Level III)
Employee post-retirement benefits
Plan assets at fair value	$ 0	$ 0

LONG-TERM DEBT - Amounts Outstanding (Details) $ in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2025 CAD ($)	Dec. 31, 2024 CAD ($)	Dec. 31, 2025 USD ($)	Dec. 31, 2024 USD ($)
Debt Instrument [Line Items]
Outstanding	$ 46,928	$ 48,172
Current portion of long-term debt	(1,545)	(2,955)
Unamortized debt discount and issue costs	(251)	(252)
Fair value adjustments	115	11
Noncurrent portion of long-term debt	45,247	44,976
Fair value adjustments of interest rate hedge	17	139
Fair value hedging adjustments, discontinued hedges	39	41
Columbia
Debt Instrument [Line Items]
Fair value adjustments of interest rate hedge	93	109
TRANSCANADA PIPELINES LIMITED
Debt Instrument [Line Items]
Outstanding	29,123	30,126
NOVA GAS TRANSMISSION LTD.
Debt Instrument [Line Items]
Outstanding	462	551
GREAT LAKES GAS TRANSMISSION LIMITED PARTNERSHIP
Debt Instrument [Line Items]
Outstanding	395	150
Medium Term Notes \| TRANSCANADA PIPELINES LIMITED
Debt Instrument [Line Items]
Outstanding	$ 14,241	$ 13,141
Interest rate	4.80%	4.70%	4.80%	4.70%
Senior Unsecured Notes \| TRANSCANADA PIPELINES LIMITED
Debt Instrument [Line Items]
Outstanding	$ 14,882	$ 16,985	$ 10,850	$ 11,792
Interest rate	5.50%	5.50%	5.50%	5.50%
Senior Unsecured Notes \| COLUMBIA PIPELINES OPERATING COMPANY LLC
Debt Instrument [Line Items]
Outstanding	$ 8,915	$ 9,362	$ 6,500
Interest rate	6.20%	6.00%	6.20%	6.00%
Senior Unsecured Notes \| COLUMBIA PIPELINES HOLDING COMPANY LLC
Debt Instrument [Line Items]
Outstanding	$ 3,634	$ 2,737	$ 2,650	$ 1,900
Interest rate	5.70%	5.90%	5.70%	5.90%
Senior Unsecured Notes \| ANR PIPELINE COMPANY
Debt Instrument [Line Items]
Outstanding	$ 2,249	$ 1,509	$ 1,640	$ 1,047
Interest rate	4.30%	3.70%	4.30%	3.70%
Senior Unsecured Notes \| TC PIPELINES, LP
Debt Instrument [Line Items]
Outstanding	$ 686	$ 1,224	$ 500	$ 850
Interest rate	4.00%	4.20%	4.00%	4.20%
Senior Unsecured Notes \| GAS TRANSMISSION NORTHWEST LLC
Debt Instrument [Line Items]
Outstanding	$ 514	$ 540	$ 375	$ 375
Interest rate	4.40%	4.40%	4.40%	4.40%
Senior Unsecured Notes \| GREAT LAKES GAS TRANSMISSION LIMITED PARTNERSHIP
Debt Instrument [Line Items]
Outstanding	$ 114	$ 150	$ 83	$ 104
Interest rate	7.60%	7.60%	7.60%	7.60%
Medium-Term Notes, Maturity between 2026 and 2030 \| NOVA GAS TRANSMISSION LTD.
Debt Instrument [Line Items]
Outstanding	$ 417	$ 504
Interest rate	7.10%	7.40%	7.10%	7.40%
Medium-Term Notes, Maturity Date of 2026 \| NOVA GAS TRANSMISSION LTD.
Debt Instrument [Line Items]
Outstanding	$ 45	$ 47	$ 33	$ 33
Interest rate	7.50%	7.50%	7.50%	7.50%
Senior Unsecured Term Loan \| GREAT LAKES GAS TRANSMISSION LIMITED PARTNERSHIP
Debt Instrument [Line Items]
Outstanding	$ 281	$ 0	$ 205
Interest rate	5.00%	0.00%	5.00%	0.00%
Senior Unsecured Term Loan \| TC ENERGÍA MEXICANA, S. DE R.L. DE C.V.
Debt Instrument [Line Items]
Outstanding	$ 950	$ 1,973	$ 693	$ 1,370
Interest rate	6.30%	7.20%	6.30%	7.20%

LONG-TERM DEBT - Interest Expense (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Interest Expense, Operating and Nonoperating [Abstract]
Capitalized interest	$ (10)	$ (191)	$ (187)
Amortization and other financial charges	107	158	106
Gain on debt extinguishment	0	(228)	0
Interest expense after interest allocated to discontinuing operations	3,407	3,237	3,263
Interest allocated to discontinued operations	0	(218)	(297)
Interest expense (Note 19)	3,407	3,019	2,966
Short-term debt
Interest Expense, Operating and Nonoperating [Abstract]
Interest on debt	95	60	165
Long-term debt (excluding junior subordinated notes)
Interest Expense, Operating and Nonoperating [Abstract]
Interest on debt	2,537	2,800	2,562
Junior subordinated notes
Interest Expense, Operating and Nonoperating [Abstract]
Interest on debt	$ 678	$ 638	$ 617

INCOME TAXES - Narrative (Details) - CAD ($)	12 Months Ended
INCOME TAXES - Narrative (Details) - CAD ($)	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Income Tax Disclosure [Abstract]
Deferred income tax liabilities on the unremitted earnings of foreign investments	$ 2,198,000,000	$ 1,728,000,000
Interest (recovery) expense reflected within net tax expense	7,000,000	(1,000,000)	$ 3,000,000
Accrued interest expense	26,000,000	19,000,000	20,000,000
Income tax penalties expense	0	0	0
Income tax penalties accrued	$ 0	$ 0	$ 0

LONG-TERM DEBT (Tables)

12 Months Ended

Dec. 31, 2025

Debt Disclosure [Abstract]

Schedule of Long-Term Debt


at December 31		2025			2024
	Maturity Dates	Outstanding	Interest Rate1		Outstanding	Interest Rate1
(millions of Canadian $, unless otherwise noted)

TRANSCANADA PIPELINES LIMITED



Medium Term Notes
Canadian	2026 to 2055	14,241	4.8	%	13,141	4.7	%
Senior Unsecured Notes
U.S. (2025 – US$10,850 and 2024 – US$11,792)	2028 to 2049	14,882	5.5	%	16,985	5.5	%
		29,123			30,126
NOVA GAS TRANSMISSION LTD.



Medium Term Notes
Canadian	2026 to 2030	417	7.1	%	504	7.4	%
U.S. (2025 and 2024 – US$33)	2026	45	7.5	%	47	7.5	%
		462			551






COLUMBIA PIPELINES OPERATING COMPANY LLC
Senior Unsecured Notes
U.S. (2025 and 2024 – US$6,500)	2030 to 2063	8,915	6.2	%	9,362	6.0	%
COLUMBIA PIPELINES HOLDING COMPANY LLC
Senior Unsecured Notes
U.S. (2025 – US$2,650; 2024 – US$1,900)	2026 to 2034	3,634	5.7	%	2,737	5.9	%
ANR PIPELINE COMPANY
Senior Unsecured Notes
U.S. (2025 – US$1,640; 2024 – US$1,047)	2026 to 2037	2,249	4.3	%	1,509	3.7	%
TC PIPELINES, LP
Senior Unsecured Notes
U.S. (2025 – US$500 and 2024 – US$850)	2027	686	4.0	%	1,224	4.2	%
GAS TRANSMISSION NORTHWEST LLC


Senior Unsecured Notes
U.S. (2025 and 2024 – US$375)	2030 to 2035	514	4.4	%	540	4.4	%
GREAT LAKES GAS TRANSMISSION LIMITED PARTNERSHIP
Unsecured Term Loan
U.S. (2025 – US$205; 2024 – nil)	2028	281	5.0	%	—	—
Senior Unsecured Notes
U.S. (2025 – US$83; 2024 – US$104)	2028 to 2030	114	7.6	%	150	7.6	%
		395			150
TC ENERGÍA MEXICANA, S. DE R.L. DE C.V.
Senior Unsecured Term Loan
U.S. (2025 – US$693; 2024 – US$1,370)	2028	950	6.3	%	1,973	7.2	%


		46,928			48,172
Current portion of long-term debt		(1,545)			(2,955)
Unamortized debt discount and issue costs		(251)			(252)
Fair value adjustments2		115			11
		45,247			44,976

1 Interest rates are the effective interest rates except for those pertaining to long-term debt issued for the Company's Canadian regulated natural gas operations, in which case the weighted average interest rate is presented as approved by the regulators. The effective interest rate is calculated by discounting the expected future interest payments, adjusted for loan fees, premiums and discounts. Weighted average and effective interest rates are stated as at the respective outstanding dates.

2 The fair value adjustments include $93 million (2024 – $109 million) related to the acquisition of Columbia Pipeline Group, Inc. These adjustments also include a decrease of $17 million (2024 – decrease of $139 million) related to hedged interest rate risk and an increase of $39 million (2024 - increase of $41 million) related to discontinued hedge interest rate risk. Refer to Note 27, Risk management and financial instruments, for additional information.

The Company issued long-term debt over the three years ended December 31, 2025 as follows:

(millions of Canadian $, unless otherwise noted)

Company

Issue Date

Type

Maturity Date

Amount

Interest Rate

TRANSCANADA PIPELINES LIMITED

November 2025

Medium Term Notes

November 2055

850

5.13

February 2025

Medium Term Notes

February 2035

1,000

4.58

August 2024

Term Loan1

August 2024

US 1,242

Floating

May 2023

Senior Unsecured Term Loan2

May 2026

US 1,024

Floating

March 2023

Senior Unsecured Notes3

March 2026

US 850

6.20

March 2023

Senior Unsecured Notes3

March 2026

US 400

Floating

March 2023

Medium Term Notes

July 2030

1,250

5.28

March 2023

Medium Term Notes3

March 2026

600

5.42

March 2023

Medium Term Notes3

March 2026

400

Floating

COLUMBIA PIPELINES HOLDING COMPANY LLC

November 2025

Senior Unsecured Notes

November 2032

US 750

5.00

September 2024

Senior Unsecured Notes

October 2031

US 400

5.10

January 2024

Senior Unsecured Notes

January 2034

US 500

5.68

August 2023

Senior Unsecured Notes

August 2028

US 700

6.04

August 2023

Senior Unsecured Notes

August 2026

US 300

6.06

GREAT LAKES GAS TRANSMISSION LIMITED PARTNERSHIP

October 2025

Unsecured Term Loan

October 2028

US 205

Floating

ANR PIPELINE COMPANY

September 2025

Senior Unsecured Notes

September 2031

US 250

5.23

September 2025

Senior Unsecured Notes

September 2035

US 350

5.69

COLUMBIA PIPELINES OPERATING COMPANY LLC

March 2025

Senior Unsecured Notes

February 2035

US 550

5.44

March 2025

Senior Unsecured Notes

February 2055

US 450

5.96

September 2024

Senior Unsecured Notes

October 2054

US 400

5.70

August 2023

Senior Unsecured Notes

November 2033

US 1,500

6.04

August 2023

Senior Unsecured Notes

November 2053

US 1,250

6.54

August 2023

Senior Unsecured Notes

August 2030

US 750

5.93

August 2023

Senior Unsecured Notes

August 2043

US 600

6.50

August 2023

Senior Unsecured Notes

August 2063

US 500

6.71

GAS TRANSMISSION NORTHWEST LLC

June 2023

Senior Unsecured Notes

June 2030

US 50

4.92

TC ENERGÍA MEXICANA, S. DE R.L. DE C.V.

January 2023

Senior Unsecured Term Loan

January 2028

US 1,800

Floating

January 2023

Senior Unsecured Revolving Credit Facility

January 2028

US 500

Floating

1In August 2024, TCPL entered into a term loan to facilitate the Spinoff Transaction and, in August 2024, the term loan was fully repaid and retired upon delivery of senior unsecured notes issued by 6297782 LLC. Refer to Note 4, Discontinued operations, for additional information.

2Fully repaid and retired in September 2023.

3In October 2024, callable notes were repaid and retired at par.

Schedule of Retired Long-Term Debt

The Company retired/repaid long-term debt over the three years ended December 31, 2025 as follows:

(millions of Canadian $, unless otherwise noted)

Company

Retirement/Repayment Date

Type

Amount

Interest Rate

TRANSCANADA PIPELINES LIMITED

November 2025

Senior Unsecured Notes

US 850

4.88

October 2025

Senior Unsecured Notes

US 92

7.06

July 2025

Medium Term Notes

750

3.30

October 2024

Senior Unsecured Notes

US 1,250

1.00

October 2024

Senior Unsecured Notes1

US 850

6.20

October 2024

Senior Unsecured Notes2

US 739

2.50

October 2024

Senior Unsecured Notes2

US 441

4.88

October 2024

Senior Unsecured Notes1

US 400

Floating

October 2024

Senior Unsecured Notes2

US 313

4.75

October 2024

Senior Unsecured Notes2

US 201

5.00

October 2024

Senior Unsecured Notes2

US 180

5.10

October 2024

Medium Term Notes1

600

5.42

October 2024

Medium Term Notes2

575

4.18

October 2024

Medium Term Notes1

400

Floating

August 2024

Term Loan3

US 1,242

Floating

June 2024

Medium Term Notes

750

Floating

October 2023

Senior Unsecured Notes

US 625

3.75

September 2023

Senior Unsecured Term Loan

US 1,024

Floating

July 2023

Medium Term Notes

750

3.69

ANR PIPELINE COMPANY

June 2025

Senior Unsecured Notes

US 7

7.00

February 2024

Senior Unsecured Notes

US 125

7.38

NOVA GAS TRANSMISSION LTD.

May 2025

Medium Term Notes

8.90

March 2024

Debentures

100

9.90

April 2023

Debentures

US 200

7.88

COLUMBIA PIPELINES OPERATING COMPANY LLC

March 2025

Senior Unsecured Notes

US 1,000

4.50

TC PIPELINES, LP

March 2025

Senior Unsecured Notes

US 350

4.38

TC ENERGÍA MEXICANA, S. DE R.L. DE C.V.

Various 2025

Senior Unsecured Term Loan

US 677

Floating

Various 2024

Senior Unsecured Term Loan

US 430

Floating

Various 2024

Senior Unsecured Revolving Credit Facility

US 185

Floating

Various 2023

Senior Unsecured Revolving Credit Facility

US 315

Floating

TUSCARORA GAS TRANSMISSION COMPANY

November 2023

Unsecured Term Loan

US 32

Floating

1In October 2024, callable notes were repaid and retired at par.

2In October 2024, TCPL purchased and cancelled notes at a 7.73 per cent weighted average discount, as a settlement of cash tender offers.

3In August 2024, TCPL entered into a term loan to facilitate the Spinoff Transaction and, in August 2024, the term loan was fully repaid and retired upon delivery of senior unsecured notes issued by 6297782 LLC. Refer to Note 4, Discontinued operations, for additional information.

Schedule of Repayments of Long-Term Debt

At December 31, 2025, principal repayments for the next five years on the Company's long-term debt are approximately as follows:


(millions of Canadian $)	2026	2027	2028	2029	2030

Principal repayments on long-term debt	1,545	3,122	5,196	1,309	4,573

Schedule of Interest Expense

Interest Expense


year ended December 31	2025	2024	2023
(millions of Canadian $)

Interest on long-term debt	2,537	2,800	2,562
Interest on junior subordinated notes	678	638	617
Interest on short-term debt	95	60	165
Capitalized interest	(10)	(191)	(187)
Amortization and other financial charges1	107	158	106
Gain on debt extinguishment	—	(228)	—
	3,407	3,237	3,263
Interest allocated to discontinued operations (Note 4)	—	(218)	(297)
	3,407	3,019	2,966

1Amortization and other financial charges include amortization of transaction costs and debt discounts calculated using the effective interest method and gains and losses on derivatives used to manage the Company's exposure to changes in interest rates.

- Definition

Tabular disclosure of long-debt instruments or arrangements, including identification, terms, features, collateral requirements and other information necessary to a fair presentation. These are debt arrangements that originally required repayment more than twelve months after issuance or greater than the normal operating cycle of the entity, if longer.

+ References

Reference 1: http://fasb.org/us-gaap/role/ref/legacyRef
-Name Accounting Standards Codification
-Section S99
-Paragraph 1
-Subparagraph (SX 210.5-02(22))
-SubTopic 10
-Topic 210
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480566/210-10-S99-1

Reference 2: http://www.xbrl.org/2009/role/commonPracticeRef
-Topic 942
-SubTopic 235
-Name Accounting Standards Codification
-Section S99
-Paragraph 2
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147477314/942-235-S99-2

Reference 3: http://www.xbrl.org/2009/role/commonPracticeRef
-Topic 235
-SubTopic 10
-Name Accounting Standards Codification
-Section S50
-Paragraph 4
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480738/235-10-S50-4

Reference 4: http://www.xbrl.org/2009/role/commonPracticeRef
-Topic 235
-SubTopic 10
-Name Accounting Standards Codification
-Section S99
-Paragraph 3
-Subparagraph (SX 210.12-04(a))
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480678/235-10-S99-3

Reference 5: http://www.xbrl.org/2003/role/exampleRef
-Topic 470
-SubTopic 20
-Name Accounting Standards Codification
-Section 55
-Paragraph 69B
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147481568/470-20-55-69B

Reference 6: http://www.xbrl.org/2003/role/exampleRef
-Topic 470
-SubTopic 20
-Name Accounting Standards Codification
-Section 55
-Paragraph 69E
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147481568/470-20-55-69E

Reference 7: http://www.xbrl.org/2009/role/commonPracticeRef
-Topic 835
-SubTopic 30
-Name Accounting Standards Codification
-Section 45
-Paragraph 2
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482925/835-30-45-2

Reference 8: http://fasb.org/us-gaap/role/ref/legacyRef
-Name Accounting Standards Codification
-Topic 505
-SubTopic 10
-Section 50
-Paragraph 3
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147481112/505-10-50-3

Reference 9: http://fasb.org/us-gaap/role/ref/legacyRef
-Name Accounting Standards Codification
-Topic 942
-SubTopic 470
-Section 50
-Paragraph 3
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147477734/942-470-50-3

Reference 10: http://fasb.org/us-gaap/role/ref/legacyRef
-Name Accounting Standards Codification
-Topic 505
-SubTopic 10
-Section 50
-Paragraph 8
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147481112/505-10-50-8

Reference 11: http://fasb.org/us-gaap/role/ref/legacyRef
-Topic 505
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 6
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147481112/505-10-50-6

Reference 12: http://fasb.org/us-gaap/role/ref/legacyRef
-Topic 505
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 7
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147481112/505-10-50-7

+ Details

VARIABLE INTEREST ENTITIES

12 Months Ended

Dec. 31, 2025

Organization, Consolidation and Presentation of Financial Statements [Abstract]

VARIABLE INTEREST ENTITIES

Consolidated VIEs

A significant portion of the Company’s assets are held through VIEs in which the Company holds a 100 per cent voting interest, the VIE meets the definition of a business and the VIE’s assets can be used for general corporate purposes. The consolidated VIEs whose assets cannot be used for purposes other than for the settlement of the VIE’s obligations, or are not considered a business, were as follows:


at December 31
(millions of Canadian $)	2025	2024

ASSETS
Current Assets
Cash and cash equivalents	167	311
Accounts receivable	989	839
Inventories	211	205
Other current assets	65	121
	1,432	1,476
Plant, Property and Equipment	49,445	49,904
Equity Investments	979	865
Restricted Investments	1,150	950
Regulatory Assets	109	53
Goodwill	456	479
Other Long-Term Assets	93	59
	53,664	53,786
LIABILITIES
Current Liabilities
Notes payable	535	—
Accounts payable and other	1,703	1,866

Accrued interest	216	202
Current portion of long-term debt	575	2,062
	3,029	4,130
Regulatory Liabilities	1,458	1,232
Other Long-Term Liabilities	51	70
Deferred Income Tax Liabilities	7	7
Long-Term Debt	13,904	12,387
	18,449	17,826

Non-Consolidated VIEs

The carrying value of these VIEs and the maximum exposure to loss as a result of the Company's involvement with these VIEs were as follows:


at December 31
(millions of Canadian $)	2025	2024

Balance Sheet Exposure

Equity Investments
Bruce Power	7,780	7,043

Coastal GasLink	896	1,006
Other equity investments	158	160

Off-Balance Sheet Exposure1
Bruce Power	1,955	1,877
Coastal GasLink2	200	265
Other equity investments	—	2
Maximum exposure to loss	10,989	10,353

1Includes maximum potential exposure to guarantees and future funding commitments.

CHANGES IN OPERATING WORKING CAPITAL (Tables)

12 Months Ended

Dec. 31, 2025

CHANGES IN OPERATING WORKING CAPITAL

Schedule of changes in operating working capital


year ended December 31	2025¹	2024¹	2023¹
(millions of Canadian $)

(Increase) decrease in Accounts receivable	(332)	(13)	(394)
(Increase) decrease in Inventories	(55)	(16)	(56)

(Increase) decrease in Other current assets	(159)	(97)	618
Increase (decrease) in Accounts payable and other	13	365	(206)
Increase (decrease) in Accrued interest	30	(40)	245

(Increase) Decrease in Operating Working Capital	(503)	199	207

1 Includes continuing and discontinued operations.

COMMON SHARES - Options (Details) shares in Thousands	12 Months Ended
COMMON SHARES - Options (Details) shares in Thousands	Dec. 31, 2025 $ / shares shares
Number of Options
Outstanding at the beginning of the period (in shares) \| shares	4,474
Exercised (in shares) \| shares	(1,740)
Options forfeited/expired (in shares) \| shares	(373)
Outstanding at the end of the period (in shares) \| shares	2,361
Options Exercisable (in shares) \| shares	1,898
Weighted Average Exercise Prices
Outstanding at the beginning of the period (in Canadian dollars per share) \| $ / shares	$ 60.69
Exercised (in Canadian dollars per share) \| $ / shares	59.34
Options forfeited/expired (in Canadian dollars per share) \| $ / shares	62.77
Outstanding at the end of the period (in Canadian dollars per share) \| $ / shares	61.37
Options Exercisable at December 31, 2020 (in Canadian dollars per share) \| $ / shares	$ 63.22
Weighted Average Remaining Contractual Life
Options Outstanding at December 31, 2025	2 years 9 months 18 days
Options Exercisable at December 31, 2025	2 years 4 months 24 days

EMPLOYEE POST-RETIREMENT BENEFITS - Net Change in Level III Fair Value (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024
Net change in the Level III fair value category
Plan assets at fair value – beginning of year	$ 4,397
Plan assets at fair value – end of year	4,431	$ 4,397
Significant Unobservable Inputs (Level III)
Net change in the Level III fair value category
Plan assets at fair value – beginning of year	590	562
Purchases and sales	59	(15)
Realized and unrealized gains (losses)	13	43
Plan assets at fair value – end of year	$ 662	$ 590

- Definition

Amount of asset segregated and restricted to provide benefit under defined benefit plan. Asset includes, but is not limited to, stock, bond, other investment, earning from investment, and contribution by employer and employee.

+ References

Reference 1: http://www.xbrl.org/2003/role/exampleRef
-Topic 715
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 5
-Subparagraph (c)(ii)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480506/715-20-50-5

Reference 2: http://www.xbrl.org/2003/role/disclosureRef
-Topic 715
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 5
-Subparagraph (a)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480506/715-20-50-5

Reference 3: http://www.xbrl.org/2003/role/exampleRef
-Topic 715
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 5
-Subparagraph (c)(iv)(01)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480506/715-20-50-5

Reference 4: http://www.xbrl.org/2003/role/disclosureRef
-Topic 715
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 5
-Subparagraph (c)(iv)(01)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480506/715-20-50-5

Reference 5: http://www.xbrl.org/2003/role/disclosureRef
-Topic 715
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 5
-Subparagraph (c)(ii)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480506/715-20-50-5

Reference 6: http://www.xbrl.org/2003/role/exampleRef
-Topic 715
-SubTopic 20
-Name Accounting Standards Codification
-Section 55
-Paragraph 17
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480482/715-20-55-17

Reference 7: http://www.xbrl.org/2003/role/disclosureRef
-Topic 715
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 1
-Subparagraph (d)(iv)(02)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480506/715-20-50-1

Reference 8: http://www.xbrl.org/2003/role/disclosureRef
-Topic 715
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 1
-Subparagraph (d)(ii)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480506/715-20-50-1

Reference 9: http://www.xbrl.org/2003/role/disclosureRef
-Topic 715
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 1
-Subparagraph (d)(iv)(01)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480506/715-20-50-1

Reference 10: http://www.xbrl.org/2003/role/disclosureRef
-Topic 715
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 1
-Subparagraph (b)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480506/715-20-50-1

Reference 11: http://www.xbrl.org/2003/role/exampleRef
-Topic 715
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 1
-Subparagraph (d)(ii)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480506/715-20-50-1

Reference 12: http://www.xbrl.org/2003/role/exampleRef
-Topic 715
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 1
-Subparagraph (d)(iv)(01)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480506/715-20-50-1

+ Details

Consolidated statement of cash flows - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Cash Generated from Operations
Net income (loss)	$ 4,094	$ 5,379	$ 3,068
Depreciation and amortization	2,769	2,788	2,778
Deferred income taxes (Note 18)	766	493	11
(Income) loss from equity investments (Notes 5 and 10)	(1,274)	(1,608)	(1,377)
Impairment of equity investment (Note 10)	0	0	2,100
Distributions received from operating activities of equity investments (Note 10)	1,616	1,675	1,254
Employee post-retirement benefits funding, net of expense (Note 26)	3	11	(17)
Equity allowance for funds used during construction	(320)	(512)	(367)
Unrealized (gains) losses on financial instruments (Note 27)	(235)	340	(342)
Expected credit loss provision (Note 27)	83	(22)	(83)
Foreign exchange (gains) losses, net – intercompany loan	149	(216)	44
Net (gain) loss on sale of assets (Note 29)	0	(620)	0
Asset impairment charge and other (Note 4)	29	21	(4)
Other	169	(232)	(4)
(Increase) decrease in operating working capital (Note 28)	(503)	199	207
Net cash provided by operations	7,346	7,696	7,268
Investing Activities
Capital expenditures (Note 5)	(5,270)	(6,308)	(8,007)
Capital projects in development (Note 5)	(16)	(50)	(142)
Contributions to equity investments (Notes 5 and 10)	(1,051)	(4,683)	(4,149)
Other distributions from equity investments (Note 10)	5	3,686	23
Proceeds from sales of assets, net of transaction costs (Note 29)	0	791	33
Acquisitions, net of cash acquired (Note 29)	0	0	(307)
Loans to affiliate (issued) repaid, net	0	0	250
Deferred amounts and other	(126)	(345)	12
Net cash (used in) provided by investing activities	(6,458)	(6,909)	(12,287)
Financing Activities
Notes payable issued (repaid), net	876	341	(6,299)
Long-term debt issued, net of issue costs	5,413	8,089	15,884
Long-term debt repaid (Notes 19 and 20)	(6,116)	(9,273)	(3,772)
Junior subordinated notes issued, net of issue costs	2,545	1,465	0
Dividends on common shares	(3,507)	(3,953)	(2,787)
Dividends on preferred shares	(114)	(99)	(92)
Common shares issued, net of issue costs	104	88	4
Preferred shares redeemed (Note 24)	(250)	0	0
Distributions to non-controlling interests and other	(929)	(755)	(173)
Contributions from redeemable non-controlling interest	0	21	0
Cash received from factoring arrangement (Note 9)	351	0	0
Loan from affiliate (Note 11)	111	0	0
Disposition of equity interest, net of transaction costs (Note 29)	0	419	5,328
Cash transferred to South Bow, net of debt settlements	0	(244)	0
Gains (losses) on settlement of financial instruments	0	27	0
Net cash (used in) provided by financing activities	(1,516)	(3,874)	8,093
Effect of Foreign Exchange Rate Changes on Cash and Cash Equivalents	(5)	210	(16)
Increase (Decrease) in Cash and Cash Equivalents	(633)	(2,877)	3,058
Cash and Cash Equivalents, Beginning of year	801	3,678	620
Cash and Cash Equivalents, End of year	$ 168	$ 801	$ 3,678

RATE-REGULATED BUSINESSES - Narrative (Details) - CAD ($) $ in Billions	1 Months Ended		12 Months Ended	24 Months Ended
	Sep. 30, 2024	Apr. 30, 2020	Dec. 31, 2025	Dec. 31, 2024
NGTL System
Public Utilities, General Disclosures [Line Items]
Maximum cost recovery and return on investment	$ 3.3
Approved ROE on deemed common equity			10.10%	10.10%
Deemed common equity, percent			40.00%	40.00%
Canadian Mainline
Public Utilities, General Disclosures [Line Items]
Approved ROE on deemed common equity			10.10%
Deemed common equity, percent			40.00%
Unanimous negotiated settlement period		6 years

VARIABLE INTEREST ENTITIES - Narrative (Details)	12 Months Ended
VARIABLE INTEREST ENTITIES - Narrative (Details)	Dec. 31, 2025
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Variable interest entity ownership percentage	100.00%

LONG-TERM DEBT - Retired/Repaid (Details) $ in Millions, $ in Millions			1 Months Ended																	12 Months Ended
	Feb. 05, 2026 CAD ($)	Oct. 31, 2024 CAD ($)	Nov. 30, 2025 USD ($)	Oct. 31, 2025 USD ($)	Jul. 31, 2025 CAD ($)	Jun. 30, 2025 USD ($)	May 31, 2025 CAD ($)	Mar. 31, 2025 USD ($)	Oct. 31, 2024 CAD ($)	Oct. 31, 2024 USD ($)	Aug. 31, 2024 USD ($)	Jun. 30, 2024 CAD ($)	Mar. 31, 2024 CAD ($)	Feb. 29, 2024 USD ($)	Nov. 30, 2023 USD ($)	Oct. 31, 2023 USD ($)	Sep. 30, 2023 USD ($)	Jul. 31, 2023 CAD ($)	Apr. 30, 2023 USD ($)	Dec. 31, 2025 USD ($)	Dec. 31, 2024 USD ($)	Dec. 31, 2023 USD ($)	Mar. 31, 2023
TRANSCANADA PIPELINES LIMITED \| Senior Unsecured Notes Due November 2025
Debt Instrument [Line Items]
Amount			$ 850
Interest Rate			4.88%
TRANSCANADA PIPELINES LIMITED \| Senior Unsecured Notes Due October 2025
Debt Instrument [Line Items]
Amount				$ 92
Interest Rate				7.06%
TRANSCANADA PIPELINES LIMITED \| Medium Term Notes Due July 2025
Debt Instrument [Line Items]
Amount					$ 750
Interest Rate					3.30%
TRANSCANADA PIPELINES LIMITED \| Senior Unsecured Notes Due October 2024
Debt Instrument [Line Items]
Amount										$ 1,250
Interest Rate		1.00%							1.00%	1.00%
TRANSCANADA PIPELINES LIMITED \| Senior Unsecured Notes Due October 2024
Debt Instrument [Line Items]
Amount										$ 850
Interest Rate		6.20%							6.20%	6.20%
TRANSCANADA PIPELINES LIMITED \| Senior Unsecured Notes Due October 2024
Debt Instrument [Line Items]
Amount										$ 739
Interest Rate		2.50%							2.50%	2.50%
TRANSCANADA PIPELINES LIMITED \| Senior Unsecured Notes Due October 2024
Debt Instrument [Line Items]
Amount										$ 441
Interest Rate		4.88%							4.88%	4.88%
TRANSCANADA PIPELINES LIMITED \| Senior Unsecured Notes Due October 2024
Debt Instrument [Line Items]
Amount										$ 400
TRANSCANADA PIPELINES LIMITED \| Senior Unsecured Notes Due October 2024
Debt Instrument [Line Items]
Amount										$ 313
Interest Rate		4.75%							4.75%	4.75%
TRANSCANADA PIPELINES LIMITED \| Senior Unsecured Notes Due October 2024
Debt Instrument [Line Items]
Amount										$ 201
Interest Rate		5.00%							5.00%	5.00%
TRANSCANADA PIPELINES LIMITED \| Senior Unsecured Notes Due October 2024
Debt Instrument [Line Items]
Amount										$ 180
Interest Rate		5.10%							5.10%	5.10%
TRANSCANADA PIPELINES LIMITED \| Medium Term Notes Due October 2024
Debt Instrument [Line Items]
Amount									$ 600
Interest Rate		5.42%							5.42%	5.42%
TRANSCANADA PIPELINES LIMITED \| Medium Term Notes Due October 2024
Debt Instrument [Line Items]
Amount									$ 575
Interest Rate		4.18%							4.18%	4.18%
TRANSCANADA PIPELINES LIMITED \| Medium Term Notes Due October 2024
Debt Instrument [Line Items]
Amount									$ 400
TRANSCANADA PIPELINES LIMITED \| Term Loan Due August 2024
Debt Instrument [Line Items]
Amount											$ 1,242
TRANSCANADA PIPELINES LIMITED \| Medium Term Notes due June 2024
Debt Instrument [Line Items]
Amount												$ 750
TRANSCANADA PIPELINES LIMITED \| Senior Unsecured Notes due October 2023
Debt Instrument [Line Items]
Amount																$ 625
Interest Rate																3.75%
TRANSCANADA PIPELINES LIMITED \| Senior Unsecured Notes Due September 2030
Debt Instrument [Line Items]
Amount																	$ 1,024
TRANSCANADA PIPELINES LIMITED \| Medium Term Note Due July 2023
Debt Instrument [Line Items]
Amount																		$ 750
Interest Rate																		3.69%
TRANSCANADA PIPELINES LIMITED \| Senior Unsecured Notes Due March 2026
Debt Instrument [Line Items]
Interest Rate																							6.20%
Long-term debt, weighted average discount, percent									7.73%	7.73%
Pre-tax gain on the debt extinguishment		$ 228
TRANSCANADA PIPELINES LIMITED \| Medium Term Notes Due February 2026 \| Subsequent event
Debt Instrument [Line Items]
Amount	$ 241
Interest Rate	8.29%
ANR PIPELINE COMPANY \| Senior Unsecured Notes Due June 2025
Debt Instrument [Line Items]
Amount						$ 7
Interest Rate						7.00%
ANR PIPELINE COMPANY \| Senior Unsecured Notes due November 2021
Debt Instrument [Line Items]
Amount														$ 125
Interest Rate														7.38%
NOVA GAS TRANSMISSION LTD. \| Medium Term Notes Due May 2025
Debt Instrument [Line Items]
Amount							$ 87
Interest Rate							8.90%
NOVA GAS TRANSMISSION LTD. \| Debentures Due March 2024
Debt Instrument [Line Items]
Amount													$ 100
Interest Rate													9.90%
NOVA GAS TRANSMISSION LTD. \| Debentures Due April 2023
Debt Instrument [Line Items]
Amount																			$ 200
Interest Rate																			7.88%
COLUMBIA PIPELINES OPERATING COMPANY LLC \| Senior Unsecured Notes Due March 2025
Debt Instrument [Line Items]
Amount								$ 1,000
Interest Rate								4.50%
TC PIPELINES, LP \| Senior Unsecured Notes Due March 2025
Debt Instrument [Line Items]
Amount								$ 350
Interest Rate								4.38%
TC ENERGÍA MEXICANA, S. DE R.L. DE C.V. \| Senior Unsecured Term Loan Various 2025
Debt Instrument [Line Items]
Amount																				$ 677
TC ENERGÍA MEXICANA, S. DE R.L. DE C.V. \| Senior Unsecured Term Loan Various 2024
Debt Instrument [Line Items]
Amount																					$ 430
TC ENERGÍA MEXICANA, S. DE R.L. DE C.V. \| Senior Unsecured Revolving Credit Facility Various 2024
Debt Instrument [Line Items]
Amount																					$ 185
TC ENERGÍA MEXICANA, S. DE R.L. DE C.V. \| Senior Unsecured Revolving Credit Facility Various 2023
Debt Instrument [Line Items]
Amount																						$ 315
TUSCARORA GAS TRANSMISSION COMPANY \| Unsecured Term Loan Due November 2023
Debt Instrument [Line Items]
Amount															$ 32

OTHER LONG-TERM LIABILITIES (Details) - CAD ($) $ in Millions	Dec. 31, 2025	Dec. 31, 2024
Deferred Costs, Noncurrent [Abstract]
Operating lease liabilities (Note 9)	$ 370	$ 451
Fair value of derivative instruments (Note 27)	149	209
Asset retirement obligations	119	108
Loan from affiliate (Note 11)	111	0
Employee post-retirement benefits (Note 26)	69	94
Other	216	189
Other long-term liabilities	$ 1,034	$ 1,051

EMPLOYEE POST-RETIREMENT BENEFITS - Obligations, Fair Value and Weighted Average Assets (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Benefit obligation and fair value of plan assets for plans that are not fully funded
Plan assets at fair value	$ 4,431	$ 4,397
Funded status based on accumulated benefit obligation
Fair value of plan assets	$ 4,431	$ 4,397
Pension plans' weighted average asset allocations and target allocations by asset category
Percentage of Plan Assets	100.00%	100.00%
Pension Benefit Plans
Benefit obligation and fair value of plan assets for plans that are not fully funded
Projected benefit obligation	$ (3,273)	$ (3,342)	$ (3,356)
Plan assets at fair value	4,081	3,948	3,697
Funded Status – Plan Surplus	808	606
Funded status based on accumulated benefit obligation
Accumulated benefit obligation	(3,086)	(3,097)
Fair value of plan assets	4,098	4,058
Fair value of plan assets	4,081	3,948	3,697
Funded Status – Plan Surplus	$ 1,012	$ 961
Pension plans' weighted average asset allocations and target allocations by asset category
Percentage of Plan Assets	100.00%	100.00%
Pension Benefit Plans \| Fixed income securities
Pension plans' weighted average asset allocations and target allocations by asset category
Percentage of Plan Assets	45.00%	37.00%
Company debt or common shares included in plan assets, amount	$ 26	$ 44
Company debt or common shares included in plan assets, percentage	0.60%	1.10%
Pension Benefit Plans \| Fixed income securities \| Minimum
Pension plans' weighted average asset allocations and target allocations by asset category
Target Allocations	30.00%
Pension Benefit Plans \| Fixed income securities \| Maximum
Pension plans' weighted average asset allocations and target allocations by asset category
Target Allocations	55.00%
Pension Benefit Plans \| Equity securities
Pension plans' weighted average asset allocations and target allocations by asset category
Percentage of Plan Assets	40.00%	49.00%
Company debt or common shares included in plan assets, amount	$ 2	$ 3
Company debt or common shares included in plan assets, percentage	0.10%	0.10%
Pension Benefit Plans \| Equity securities \| Minimum
Pension plans' weighted average asset allocations and target allocations by asset category
Target Allocations	20.00%
Pension Benefit Plans \| Equity securities \| Maximum
Pension plans' weighted average asset allocations and target allocations by asset category
Target Allocations	55.00%
Pension Benefit Plans \| Other investments
Pension plans' weighted average asset allocations and target allocations by asset category
Percentage of Plan Assets	15.00%	14.00%
Pension Benefit Plans \| Other investments \| Minimum
Pension plans' weighted average asset allocations and target allocations by asset category
Target Allocations	10.00%
Pension Benefit Plans \| Other investments \| Maximum
Pension plans' weighted average asset allocations and target allocations by asset category
Target Allocations	35.00%
Pension Benefit Plans \| South Bow
Benefit obligation and fair value of plan assets for plans that are not fully funded
Plan assets at fair value	$ 17	$ 110
Funded status based on accumulated benefit obligation
Fair value of plan assets	17	110
Pension Benefit Plans \| Not fully funded
Benefit obligation and fair value of plan assets for plans that are not fully funded
Projected benefit obligation	0	0
Plan assets at fair value	0	0
Funded Status – Plan Surplus	0	0
Funded status based on accumulated benefit obligation
Fair value of plan assets	0	0
Other Post-Retirement Benefit Plans
Benefit obligation and fair value of plan assets for plans that are not fully funded
Projected benefit obligation	(249)	(288)	(285)
Plan assets at fair value	333	339	358
Funded Status – Plan Surplus	84	51
Funded status based on accumulated benefit obligation
Fair value of plan assets	333	339	$ 358
Other Post-Retirement Benefit Plans \| Not fully funded
Benefit obligation and fair value of plan assets for plans that are not fully funded
Projected benefit obligation	(76)	(101)
Plan assets at fair value	0	0
Funded Status – Plan Surplus	(76)	(101)
Funded status based on accumulated benefit obligation
Fair value of plan assets	$ 0	$ 0

PREFERRED SHARES

12 Months Ended

Dec. 31, 2025

Preferred Stock, Number of Shares, Par Value and Other Disclosure [Abstract]

PREFERRED SHARES


at December 31, 2025	Number of Shares Outstanding	Current Yield			Annual Dividend Per Share1,2	Redemption Price Per Share	Redemption and Conversion Option Date		Right to Convert Into	Carrying Value December 313
										2025	2024	2023
	(thousands)									(millions of Canadian $)

Cumulative First Preferred Shares
Series 1	18,424	4.94	%	4	$1.23475	$25.00	December 31, 2029		Series 2	456	456	360
Series 2	3,576	Floating		5	Floating	$25.00	December 31, 2029		Series 1	83	83	179
Series 3	11,715	4.10	%	4	$1.0255	$25.00	June 30, 2030	6	Series 4	289	246	246
Series 4	2,285	Floating		5	Floating	$25.00	June 30, 2030	6	Series 3	54	97	97
Series 5	12,071	1.95	%		$0.48725	$25.00	January 30, 2026		Series 6	294	294	294
Series 6	1,929	Floating		5	Floating	$25.00	January 30, 2026		Series 5	48	48	48
Series 7	24,000	5.99	%	4	$1.49625	$25.00	April 30, 2029		Series 8	589	589	589
Series 9	16,703	5.08	%	4	$1.27	$25.00	October 30, 2029		Series 10	410	410	442
Series 10	1,297	Floating		5	Floating	$25.00	October 30, 2029		Series 9	32	32	—
Series 11	—	—			—	—	—		—	—	244	244

										2,255	2,499	2,499

3Net of underwriting commissions and deferred income taxes.

6Adjusted to July 2, 2030 to account for applicable business days.

The holders of preferred shares are entitled to receive a fixed or floating cumulative quarterly preferential dividend as and when declared by the Board. The holders will have the right, subject to certain conditions, to convert their first preferred shares of a specified series into first preferred shares of another specified series on the conversion option date and every fifth anniversary thereafter as indicated in the table above.

TC Energy may, at its option, redeem all or a portion of the outstanding preferred shares for the redemption price per share, plus all accrued and unpaid dividends on the applicable redemption option date and on every fifth anniversary thereafter. In addition, Series 2, Series 4, Series 6 and Series 10 preferred shares are redeemable by TC Energy at any time other than on a designated date for $25.50 per share plus all accrued and unpaid dividends on such redemption date.

On November 28, 2025, TC Energy redeemed all 10 million issued and outstanding Series 11 preferred shares at a redemption price of $25.00 per share and paid the final quarterly dividend of $0.2094375 per Series 11 preferred share for the period up to but excluding November 28, 2025. The Company used the proceeds from the October 2025 issuance of US$370 million of Junior Subordinated Notes to finance this preferred share redemption. Prior to the redemption of the Series 11 preferred shares, Series 12 preferred shares were issuable upon conversion of the Series 11 preferred shares, subject to certain conditions, on previously set conversion dates. At the time of the redemption and cancellation of the Series 11 preferred shares, there were no Series 12 preferred shares outstanding.

On June 30, 2025, 104,778 Series 3 preferred shares were converted, on a one-for-one basis, into Series 4 preferred shares and 1,822,829 Series 4 preferred shares were converted, on a one-for-one basis, into Series 3 preferred shares.

On December 31, 2024, 42,200 Series 1 preferred shares were converted, on a one-for-one basis, into Series 2 preferred shares and 3,889,020 Series 2 preferred shares were converted, on a one-for-one basis, into Series 1 preferred shares.

On October 30, 2024, 1,297,203 Series 9 preferred shares were converted, on a one-for-one basis, into Series 10 preferred shares.

EMPLOYEE POST-RETIREMENT BENEFITS - Cash Payments, Changes and Balance Sheet Presentation (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Employee post-retirement benefits
Expected average remaining life expectancy of former employees over which past service costs are amortized	11 years	12 years	12 years
Expense for savings plan and DC Plans	$ 72	$ 71	$ 64
Current assets of discontinued operations	197	235
Defined Benefits, Contribution And Other Postretirement Plan Contributions [Abstract]
Savings and DC Plans	72	71	64
Total cash contributions	80	79	$ 101
Change in Plan Assets
Plan assets at fair value – beginning of year	4,397
Plan assets at fair value – end of year	4,431	4,397
Amounts recognized in the Balance Sheet
Other long-term assets (Note 14)	967	758
Other long-term liabilities (Note 17)	(69)	$ (94)
Disposed of by sale \| South Bow Canadian Infrastructure Holdings Ltd
Employee post-retirement benefits
Sale consideration	105
Current assets of discontinued operations	$ 17
Pension Benefit Plans
Employee post-retirement benefits
Expected average remaining service life of employees over which past service costs are amortized	8 years	9 years	9 years
Defined Benefits, Contribution And Other Postretirement Plan Contributions [Abstract]
DB Plans and Other post-retirement benefit plans	$ 0	$ 0	$ 28
Total amount outstanding under letters of credit	111	133
Change in Benefit Obligation
Benefit obligation – beginning of year	3,342	3,356
Service cost	101	108	93
Interest cost	162	160	158
Employee contributions	11	11
Benefits paid	(228)	(194)
Actuarial (gain) loss	(80)	(39)
South Bow - transition of benefit obligation	0	(118)
Foreign exchange rate changes	(35)	58
Benefit obligation – end of year	3,273	3,342	3,356
Change in Plan Assets
Plan assets at fair value – beginning of year	3,948	3,697
Actual return on plan assets	390	485
Employer contributions	0	0
Employee contributions	11	11
Benefits paid	(228)	(194)
South Bow - transition of plan assets	0	(119)
Foreign exchange rate changes	(40)	68
Plan assets at fair value – end of year	4,081	3,948	3,697
Funded Status – Plan Surplus	$ 808	$ 606
Discount rate	5.10%	4.90%
Amounts recognized in the Balance Sheet
Other long-term assets (Note 14)	$ 808	$ 606
Accounts payable and other	0	0
Other long-term liabilities (Note 17)	0	0
Net	808	606
Pension Benefit Plans \| South Bow
Change in Plan Assets
Plan assets at fair value – beginning of year	110
Plan assets at fair value – end of year	17	110
Pension Benefit Plans \| TC Energy and South Bow
Change in Plan Assets
Plan assets at fair value – beginning of year	4,058
Plan assets at fair value – end of year	4,098	4,058
Pension Benefit Plans \| Canadian
Defined Benefits, Contribution And Other Postretirement Plan Contributions [Abstract]
Total amount outstanding under letters of credit	$ 0	111	244
Pension Benefit Plans \| Minimum
Employee post-retirement benefits
Consecutive period of employment for highest average earnings	3 years
Pension Benefit Plans \| Maximum
Employee post-retirement benefits
Consecutive period of employment for highest average earnings	5 years
Other Post-Retirement Benefit Plans
Defined Benefits, Contribution And Other Postretirement Plan Contributions [Abstract]
DB Plans and Other post-retirement benefit plans	$ 8	8	9
Change in Benefit Obligation
Benefit obligation – beginning of year	288	285
Service cost	1	1	3
Interest cost	15	14	16
Employee contributions	2	2
Benefits paid	(22)	(24)
Actuarial (gain) loss	(26)	(5)
South Bow - transition of benefit obligation	0	(1)
Foreign exchange rate changes	(9)	16
Benefit obligation – end of year	249	288	285
Change in Plan Assets
Plan assets at fair value – beginning of year	339	358
Actual return on plan assets	22	17
Employer contributions	8	(41)
Employee contributions	2	2
Benefits paid	(22)	(25)
South Bow - transition of plan assets	0	0
Foreign exchange rate changes	(16)	28
Plan assets at fair value – end of year	333	339	$ 358
Funded Status – Plan Surplus	$ 84	$ 51
Discount rate	5.45%	5.45%
OPEB surplus transferred to pay future active employee medical expenses	$ 0	$ 49
Amounts recognized in the Balance Sheet
Other long-term assets (Note 14)	159	152
Accounts payable and other	(6)	(7)
Other long-term liabilities (Note 17)	(69)	(94)
Net	$ 84	$ 51

OTHER LONG-TERM ASSETS - Summary (Details) - CAD ($) $ in Millions	Dec. 31, 2025	Dec. 31, 2024
Goodwill and Intangible Assets Disclosure [Abstract]
Employee post-retirement benefits (Note 26)	$ 967	$ 758
Contract assets (Note 6)	627	608
Deferred income tax assets (Note 18)	356	428
Fair value of derivative instruments (Note 27)	161	122
Capital projects in development	81	164
Other	290	330
Total other assets	$ 2,482	$ 2,410

- Definition

Amount of asset, recognized in statement of financial position, for overfunded defined benefit pension and other postretirement plans.

+ References + Details

ACCOUNTING POLICIES (Policies)	12 Months Ended
ACCOUNTING POLICIES (Policies)	Dec. 31, 2025
Accounting Policies [Abstract]
Basis of Presentation	Basis of Presentation These consolidated financial statements include the accounts of TC Energy and its subsidiaries. The Company consolidates variable interest entities (VIEs) for which it is considered to be the primary beneficiary as well as voting interest entities in which it has a controlling financial interest. Interests in consolidated entities owned by other parties are presented as non-controlling interests. TC Energy uses the equity method of accounting for joint ventures in which the Company is able to exercise joint control and for investments in which the Company is able to exercise significant influence. The Spinoff Transaction represented a strategic shift that had a major effect on the Company's operations and consolidated financial results. Accordingly, the historical results of the Liquids Pipelines business are presented as discontinued operations and have been excluded from continuing operations and segment disclosures for all periods presented. The Notes to the consolidated financial statements reflect continuing operations only, unless otherwise indicated. Prior to the spinoff, the operations of the Liquids Pipelines business were materially reported as the Company's Liquids Pipelines segment. Refer to Note 4, Discontinued operations, and Note 5, Segmented information, for additional information. Certain prior year amounts have been reclassified to conform to current year presentation.
Use of Estimates and Judgments	Use of Estimates and Judgments In preparing these consolidated financial statements, TC Energy is required to make estimates and assumptions that affect both the amount and timing of recording assets, liabilities, revenues and expenses since the determination of these items may be dependent on future events. The Company uses the most current information available and exercises careful judgment in making these estimates and assumptions. Certain estimates and judgments have a material impact on the consolidated financial statements where the assumptions underlying these accounting estimates relate to matters that are highly uncertain at the time they are made or are subjective. These estimates and judgments include, but are not limited to: •fair value of the Southeast Gateway pipeline used to record a net investment upon lease commencement (Note 9) •fair value of reporting units that contain goodwill (Note 13). Some of the estimates and judgments the Company has to make have a material impact on the consolidated financial statements, but do not involve significant subjectivity or uncertainty. These estimates and judgments include, but are not limited to: •recoverability and depreciation rates of plant, property and equipment (Note 8) •allocation of consideration to lease and non-lease components in a contract that contains a lease (Note 9) •assumptions used to measure the carrying amount of and expected credit losses on net investment in leases and certain contract assets (Notes 9 and 27) •fair value of equity investments (Note 10) •carrying value of regulatory assets and liabilities (Note 12) •recognition of asset retirement obligations (Note 17) •provisions for income taxes, including valuation allowances and releases as well as tax positions that may be reviewed as part of an audit by tax authorities (Note 18) •assumptions used to measure retirement and other post-retirement benefit obligations (Note 26) •fair value of financial instruments (Notes 26 and 27) •commitments and provisions for contingencies and guarantees (Note 30). TC Energy continues to assess climate-related impacts on the consolidated financial statements. There are ongoing developments in the sustainability frameworks and regulatory initiatives that could further impact accounting estimates and judgments including, but not limited to, assessment of asset useful lives, goodwill valuation, impairment of plant, property and equipment, accrued environmental costs and asset retirement obligations. The impact of these changes is continuously assessed to ensure any changes in assumptions that would impact estimates listed above are adjusted on a timely basis. Actual results could differ from these estimates.
Regulation	Regulation Certain Canadian, U.S. and Mexico natural gas pipeline and storage assets are regulated with respect to construction, operations and the determination of tolls. In Canada, regulated natural gas pipelines are subject to the authority of the Canada Energy Regulator (CER), the Alberta Energy Regulator or the BC Energy Regulator. In the U.S., regulated interstate natural gas pipelines and regulated natural gas storage assets are subject to the authority of the Federal Energy Regulatory Commission (FERC). In Mexico, regulated natural gas pipelines are subject to the authority of the National Energy Commission (CNE). Rate-regulated accounting (RRA) standards may impact the timing of the recognition of certain revenues and expenses in TC Energy's rate-regulated businesses which may differ from that otherwise recognized in non-rate-regulated businesses to reflect the economic impact of the regulators' decisions regarding revenues and tolls. Regulatory assets represent costs that are expected to be recovered in customer rates in future periods and regulatory liabilities represent amounts that are expected to be returned to customers through future rate-setting processes. An operation qualifies for the use of RRA when it meets three criteria: •a regulator must establish or approve the rates for the regulated services or activities •the regulated rates must be designed to recover the cost of providing the services or products •it is reasonable to assume that rates set at levels to recover the cost can be charged to and collected from customers because of the demand for services or products and the level of direct or indirect competition. TC Energy's businesses that apply RRA currently include natural gas pipelines in Canada, U.S. and Mexico and regulated U.S. natural gas storage.
Revenue Recognition	Revenue Recognition The total consideration for services and products to which the Company expects to be entitled can include fixed and variable amounts. The Company has variable revenue that is subject to factors outside the Company's influence, such as market prices, actions of third parties and weather conditions. The Company considers some of this variable revenue to be constrained as it cannot be reliably estimated and, therefore, variable revenue is recognized only to the extent it is probable a significant reversal in cumulative revenue will not occur. The Company's contracts with customers include natural gas pipelines capacity arrangements and transportation contracts, power generation contracts, natural gas storage and other contracts. Revenues from contracts with customers are recognized net of any commodity taxes collected from customers which are subsequently remitted to governmental authorities. Revenues from non-lease components associated with a lease arrangement are recognized systematically over the term of the contract. The majority of income earned from marketing activities, as it relates to the purchase and sale of natural gas and electricity, is recorded on a net basis in the month of delivery. Canadian Natural Gas Pipelines Capacity Arrangements and Transportation Revenues from the Company's Canadian natural gas pipelines are generated from contractual arrangements for committed capacity and from the transportation of natural gas. Revenues earned from firm contracted capacity arrangements are recognized ratably over the term of the contract regardless of the amount of natural gas that is transported. Transportation revenues for interruptible or volumetric-based services are recognized when the service is performed. Revenues from the Company's Canadian natural gas pipelines under federal jurisdiction are subject to regulatory decisions by the CER. The tolls charged on these pipelines are based on revenue requirements designed to recover the costs of providing natural gas capacity for transportation services, which includes a return of and on capital, as approved by the CER. The Company's Canadian natural gas pipelines are generally not subject to earnings volatility related to variances in revenues and costs. These variances, except as related to incentive arrangements, are generally subject to deferral treatment and are recovered or refunded in future tolls. Revenues recognized prior to a CER decision on rates for that period reflect the CER's last approved return on equity (ROE) assumptions. Adjustments to revenues are recorded when the CER decision is received. Canadian natural gas pipelines' revenues are invoiced and received on a monthly basis. The Company does not take ownership of the natural gas that it transports for customers. U.S. Natural Gas Pipelines Capacity Arrangements and Transportation Revenues from the Company's U.S. natural gas pipelines are generated from contractual arrangements for committed capacity and from the transportation of natural gas. Revenues earned from firm contracted capacity arrangements are generally recognized ratably over the term of the contract regardless of the amount of natural gas that is transported. Transportation revenues for interruptible or volumetric-based services are recognized when the service is performed. The Company's U.S. interstate natural gas pipelines are subject to FERC regulations and, as a result, a portion of revenues collected may be subject to refund if invoiced during an interim period when a rate proceeding is ongoing. Allowances for these potential refunds are recognized using management's best estimate based on the facts and circumstances of the proceeding. Any allowances that are recognized during the proceeding process are refunded or retained at the time a regulatory decision becomes final. U.S. natural gas pipelines' revenues are invoiced and received on a monthly basis. The Company does not take ownership of the natural gas that it transports for customers. Natural Gas Storage and Other Revenues from the Company's regulated U.S. natural gas storage services are generated mainly from firm committed capacity storage contracts. The performance obligation in these contracts is the reservation of a specified amount of capacity for storage including specifications with regard to the amount of natural gas that can be injected or withdrawn on a daily basis. Revenues are recognized ratably over the contract period for firm committed capacity regardless of the amount of natural gas that is stored, and when gas is injected or withdrawn for interruptible or volumetric-based services. Natural gas storage services revenues are invoiced and received on a monthly basis. The Company does not take ownership of the natural gas that it stores for customers. The Company owns mineral rights associated with certain natural gas storage facilities. These mineral rights can be leased or contributed to producers of natural gas in return for a royalty interest which is recognized when natural gas and associated liquids are produced. Mexico Natural Gas Pipelines Capacity Arrangements and Transportation Revenues from certain of the Company's Mexico natural gas pipelines are primarily collected based on negotiated firm capacity contracts and are generally recognized ratably over the term of the contract. Transportation revenues related to interruptible or volumetric-based services are recognized when the service is performed. Mexico natural gas pipelines' revenues are invoiced and received on a monthly basis. The Company does not take ownership of the natural gas that it transports for customers. Other The Company generates revenues from operating and maintenance services provided on leased pipelines. Revenues earned from these services are recognized ratably over the term of the contract. Power and Energy Solutions Power Revenues from the Company's Power and Energy Solutions business are primarily derived from long-term contractual commitments to provide power capacity to meet the demands of the market and from the sale of electricity to both centralized markets and to customers. Power generation revenues also include revenues from the sale of steam to customers. Revenues and capacity payments are recognized as the services are provided and as electricity and steam is delivered. Power generation revenues are invoiced and received on a monthly basis. Natural Gas Storage and Other Non-regulated natural gas storage contracts include park, loan and term storage arrangements. Revenues are recognized as the services are provided. Term storage revenues are invoiced and received on a monthly basis. Revenues from ancillary services are recognized as the service is provided.
Cash and Cash Equivalents	Cash and Cash Equivalents The Company's Cash and cash equivalents consist of cash and highly liquid short-term investments with original maturities of three months or less and are recorded at cost, which approximates fair value.
Inventories	Inventories Inventories primarily consist of materials and supplies including spare parts and fuel, proprietary natural gas inventory in storage and emissions allowances and credits not held for compliance. The Company purchases certain emissions allowances and credits as part of bundled arrangements that also include the purchase of electricity for a fixed price. The cost allocated to emissions allowances and credits under such arrangements is based on observable market prices. Inventories are carried at the lower of cost and net realizable value.
Assets Held For Sale	Assets Held for Sale The Company classifies assets as held for sale when management approves and commits to a formal plan to actively market a disposal group and expects the sale to close within the next 12 months. Upon classifying an asset as held for sale, the asset is recorded at the lower of its carrying amount or its estimated fair value, net of selling costs and any losses are recognized in net income. Gains related to the expected sale of these assets are not recognized until the transaction closes. Once an asset is classified as held for sale, depreciation expense is no longer recorded.
Plant, Property and Equipment	Plant, Property and Equipment Natural Gas Pipelines Plant, property and equipment for natural gas pipelines is carried at cost. Depreciation is calculated on a straight-line basis once the assets are ready for their intended use. Pipeline and compression equipment are depreciated at annual rates ranging from 0.625 per cent to 6.67 per cent and metering and other plant equipment are depreciated at various rates reflecting their estimated useful lives. The cost of major overhauls of equipment is capitalized and depreciated over the estimated service lives of the overhauls. The cost of regulated natural gas pipelines includes an allowance for funds used during construction (AFUDC) consisting of a debt component and an equity component based on the rate of return on rate base approved by regulators. AFUDC is reflected as an increase in the cost of the assets in Plant, property and equipment with a corresponding increase in Allowance for funds used during construction in the Consolidated statement of income. The equity component of AFUDC is a non-cash expenditure. Interest is capitalized during construction of non-regulated natural gas pipelines. Natural gas pipelines' linepack and natural gas storage base gas are valued at cost and are maintained to ensure adequate pressure exists to transport natural gas through pipelines and deliver natural gas held in storage. Linepack and base gas are not depreciated. When rate-regulated natural gas pipelines retire plant, property and equipment from service, the original book cost is removed from the gross plant amount and recorded as a reduction to accumulated depreciation with no amount recorded to net income. Costs incurred to remove plant, property and equipment from service, net of any salvage proceeds, are also recorded in accumulated depreciation. Other The Company participates as a working interest partner in the development of certain Marcellus and Utica acreage. The working interest allows the Company to invest in drilling activities in addition to receiving a royalty interest in well production. The Company uses the successful efforts method of accounting for natural gas and crude oil resulting from its portion of drilling activities. Capitalized well costs are depleted based on the units of production method. Power and Energy Solutions Plant, property and equipment for Power and Energy Solutions assets are recorded at cost and, once the assets are ready for their intended use, depreciated by major component on a straight-line basis over their estimated service lives at average annual rates ranging from two per cent to 20 per cent. Other equipment is depreciated at various rates reflecting their estimated useful lives. The cost of major overhauls of equipment is capitalized and depreciated over the estimated service lives of the overhauls. Interest is capitalized on facilities under construction. When these assets are retired from plant, property and equipment, the original book cost and related accumulated depreciation are derecognized and any gain or loss is recorded in net income. Natural gas storage base gas, which is valued at original cost, represents gas volumes that are maintained to ensure adequate reservoir pressure exists to deliver gas held in storage. Base gas is not depreciated. Corporate Corporate plant, property and equipment is recorded at cost and depreciated on a straight-line basis over its estimated useful life at average annual rates ranging from four per cent to 20 per cent. Capital Projects in Development The Company capitalizes project costs once advancement of the project to construction stage is probable or costs are otherwise likely to be recoverable. The Company capitalizes interest costs for non-regulated projects in development and AFUDC for regulated projects in development. Capital projects in development are included in Other long-term assets on the Consolidated balance sheet. These represent larger projects that generally require regulatory or other approvals before physical construction can begin. Once approvals are received, projects are moved to plant, property and equipment under construction.
Lessee Accounting Policy	Leases The Company determines if a contract contains a lease at inception, or upon modification, of a contract by using judgment in assessing the following aspects: 1) the contract specifies an identified asset which is physically distinct or, if not physically distinct, represents substantially all of the capacity of the asset; 2) the contract provides the customer with the right to obtain substantially all of the economic benefits from the use of the asset; and 3) the customer has the right to direct how and for what purpose the identified asset is used throughout the period of the contract. If the contract is determined to contain a lease, further judgment is required to identify separate lease components of the arrangement by assessing whether the lessee can benefit from the right of use either on its own or together with other resources that are readily available to the lessee, as well as if the right of use is neither highly dependent on, nor highly interrelated, with the other rights to use underlying assets in the contract. The Company considers non-lease components as distinct elements of a contract that are not related to the use of the leased asset. A good or service that is provided to a customer is distinct if: 1) the customer can benefit from the good or service either on its own or together with other resources that are readily available to the customer; and 2) the entity’s promise to transfer the good or service to the customer is separately identifiable from other promises in the contract. The Company applies the practical expedient to not separate lease and non-lease components for all lessee contracts and facilities for which the Company is the lessor in an operating lease. Lessee Accounting Policy Operating leases are recognized as right-of-use (ROU) assets and included in Plant, property and equipment while corresponding liabilities are included in Accounts payable and other and Other long-term liabilities on the Consolidated balance sheet. Operating lease ROU assets and operating lease liabilities are recognized based on the present value of the future minimum lease payments over the lease term at the commencement date of the lease agreement. Lease terms may include options to extend or terminate the lease when it is reasonably certain that the Company will exercise that option. As the Company's lease contracts do not provide an implicit interest rate, the Company uses its incremental borrowing rate based on the information available at commencement date, or upon modification of a lease, in determining the present value of future payments. Operating lease expense is recognized on a straight-line basis over the lease term and included in Plant operating costs and other in the Consolidated statement of income. The Company applies the practical expedient to not recognize ROU assets or lease liabilities for leases that qualify for the short-term lease recognition exemption.
Lessor Accounting Policy	Lessor Accounting Policy The Company provides transportation and other services on certain assets to customers according to long-term service agreements through sales-type and operating leases. In a sales-type lease, the Company measures the total consideration within the contract at lease commencement, or upon modification of a lease. When a lease arrangement contains more than one lease and/or non-lease component, a portion of the contract consideration is allocated to each component based on the stand-alone selling price for each distinct service. The Company applies judgment to determine reasonable estimates of the expected future cost of satisfying the performance obligations of each service. The payments associated with lease components are apportioned between a reduction in the net investment in lease and sales-type lease income. At lease commencement, the Company recognizes a net investment in lease equal to the present value of both the future lease payments and the estimated residual value of the leased asset discounted at the rate implicit in the lease. The plant, property and equipment of the leased asset is derecognized, with related gains/losses, if any, recognized in the Consolidated statement of income. Sales-type lease income is determined using the rate implicit in the lease and is recorded in Revenues. The Company is the lessor within certain other contracts, including PPAs, that are accounted for as operating leases. In an operating lease, the leased asset remains capitalized in Plant, property and equipment on the Consolidated balance sheet and is depreciated over its useful life, while lease payments are recognized as revenue over the term of the lease on a straight-line basis. Variable lease payments are recognized as income in the period in which they occur.
Impairment of Long-Lived Assets and Impairment of Financial Assets	Impairment of Long-Lived Assets The Company reviews long-lived assets such as plant, property and equipment and capital projects in development for impairment whenever events or changes in circumstances indicate the carrying value may not be recoverable. If the total of the estimated undiscounted future cash flows for an asset within plant, property and equipment, or the estimated selling price of any long-lived asset is less than the carrying value of an asset, an impairment loss is recognized for the excess of the carrying value over the estimated fair value of the asset. Impairment of Financial Assets The Company reviews financial assets, inclusive of net investment in leases and certain contract assets, carried at amortized cost for impairment using the lifetime expected loss of the financial asset at initial recognition and throughout the life of the financial asset. An expected credit loss (ECL) is calculated using a model and methodology based on assumptions and judgment considering historical data, current counterparty information as well as reasonable and supportable forecasts of future economic conditions. The ECL is recognized in Plant operating costs and other in the Consolidated statement of income, and is presented on the Consolidated balance sheet as a reduction to the carrying value of the related financial asset.
Impairment of Equity Method Investments	Impairment of Equity Method Investments The Company reviews equity method investments for impairment when an event or change in circumstances has a significant adverse effect on the investment's fair value. Where the Company concludes an investment's fair value is below its carrying value, the Company then determines whether the impairment is other-than-temporary, and if so, an impairment loss is recognized for the excess of the carrying value over the estimated fair value of the investment, not exceeding the carrying value of the investment.
Acquisitions and Goodwill	Acquisitions and Goodwill The Company accounts for business combinations using the acquisition method of accounting and, accordingly, the assets and liabilities of the acquired entities are primarily measured at their estimated fair values at the date of acquisition. The excess of the fair value of the consideration transferred over the estimated fair value of the net assets acquired is classified as goodwill. Goodwill is not amortized and is tested for impairment on an annual basis, or more frequently if events or changes in circumstances indicate that it might be impaired. The annual review for goodwill impairment is performed at the reporting unit level which is one level below the Company's operating segments. The Company can initially assess qualitative factors to determine whether events or changes in circumstances indicate that goodwill might be impaired. The factors the Company considers include, but are not limited to, macroeconomic conditions, industry and market considerations, current valuation multiples and discount rates, cost factors, historical and forecasted financial results and events specific to that reporting unit. If the Company concludes that it is not more likely than not that the fair value of the reporting unit is greater than its carrying value, the Company will then perform a quantitative goodwill impairment test. The Company can elect to proceed directly to the quantitative goodwill impairment test for any of its reporting units. If the quantitative goodwill impairment test is performed, the Company compares the fair value of the reporting unit to its carrying value, including its goodwill. If the carrying value of a reporting unit exceeds its fair value, goodwill impairment is measured at the amount by which the reporting unit’s carrying value exceeds its fair value. The fair value of a reporting unit is determined by using a discounted cash flow model which requires the use of assumptions that may include, but are not limited to, revenue and capital expenditure projections, valuation multiples and discount rates. The Company has elected to allocate goodwill impairment charges first to goodwill that is non-deductible for income tax purposes, with any remaining charge allocated to tax-deductible goodwill. When a portion of a reporting unit that constitutes a business is disposed, goodwill associated with that business is included in the carrying amount of the business in determining the gain or loss on disposal. The amount of goodwill disposed is determined based on the relative fair values of the business to be disposed and the portion of the reporting unit that will be retained. A goodwill impairment test will be completed for the goodwill that will be retained.
Non-Controlling Interests	Non-Controlling Interests Non-controlling interests (NCI) represent third-party ownership interests in certain consolidated subsidiaries of the Company. Partial dispositions which result in a change in the Company's ownership interest, but do not result in a change in control, of a subsidiary that constitutes a business are accounted for as equity transactions. No gain or loss is recognized in earnings. At the time of partial disposition, NCI is recorded as the third party's ownership interest in the Company's carrying value of the net assets of the subsidiary. Any difference between the amount by which the NCI is adjusted and the fair value of the consideration paid or received is recognized in Additional paid-in capital and/or Retained earnings (Accumulated deficit).
Loans and Receivables	Loans and Receivables Loans receivable from affiliates and accounts receivable are measured at amortized cost.
Restricted Investments	Restricted Investments The Company has certain investments that are restricted as to their withdrawal and use. These restricted investments are recorded at fair value on the Consolidated balance sheet. As a result of the CER’s Land Matters Consultation Initiative (LMCI), TC Energy is required to collect funds to cover estimated future pipeline abandonment costs for larger CER-regulated Canadian pipelines. Funds collected are placed in trusts that hold and invest the funds and are accounted for as restricted investments (LMCI restricted investments). LMCI restricted investments may only be used to fund the abandonment of the CER-regulated pipeline facilities, therefore, a corresponding regulatory liability is recorded on the Consolidated balance sheet. The Company also has other restricted investments that have been set aside to fund insurance claim losses to be paid by the Company's wholly-owned captive insurance subsidiary.
Income Taxes	Income Taxes The Company uses the asset and liability method of accounting for income taxes. This method requires the recognition of deferred income tax assets and liabilities for future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred income tax assets and liabilities are measured using enacted tax rates at the balance sheet date that are anticipated to apply to taxable income in the years in which temporary differences are expected to be reversed or settled. Changes to these balances are recognized in net income in the period in which they occur, except for changes in balances related to regulated natural gas pipelines which are deferred until they are refunded or recovered in tolls, as permitted by the regulator. Deferred income tax assets and liabilities are classified as non-current on the Consolidated balance sheet. The Company’s exposure to uncertain tax positions is evaluated and a provision is made where it is more likely than not that this exposure will materialize. Canadian income taxes are not provided for on the unremitted earnings of foreign investments that the Company does not intend to repatriate in the foreseeable future. Any interest and/or penalty incurred related to income tax is reflected in Income tax expense.
Asset Retirement Obligations	Asset Retirement Obligations The Company recognizes the fair value of a liability for asset retirement obligations (ARO) in the period in which it is incurred, when a legal obligation exists and a reasonable estimate of fair value can be made. The fair value is added to the carrying amount of the associated asset and the liability is accreted through charges to Plant operating costs and other in the Consolidated statement of income. In determining the fair value of ARO, the following assumptions are used: •the expected retirement date •the scope and cost of abandonment and reclamation activities that are required •appropriate inflation and discount rates. The Company's AROs are substantially related to its power generation facilities. The scope and timing of asset retirements related to the Company's natural gas pipelines and storage facilities are indeterminable because the Company intends to operate them as long as there is supply and demand. As a result, the Company has not recorded an amount for ARO related to these assets.
Environmental Liabilities and Emission Allowances and Credits	Environmental Liabilities and Emission Allowances and Credits The Company records liabilities on an undiscounted basis for environmental remediation efforts that are likely to occur and where the cost can be reasonably estimated. These estimates, including associated legal costs, are based on available information using existing technology and enacted laws and regulations and are subject to revision in future periods based on actual costs incurred or new circumstances. TC Energy evaluates recoveries from insurers and other third parties separately from the liability and, when recovery is probable, an asset is recorded separately from the associated liability. These recoveries are presented, along with environmental remediation costs, on a net basis in Plant operating costs and other in the Consolidated statement of income. Variations in one or more of the categories described above could result in additional costs such as fines, penalties and/or expenditures associated with litigation and settlement of claims with respect to environmental liabilities. Emission allowances or credits purchased for compliance are recorded on the Consolidated balance sheet at historical cost and derecognized when they are utilized or cancelled/retired by government agencies. Compliance costs are expensed when incurred. Allowances granted to or internally generated by TC Energy are not attributed a value for accounting purposes. When required, TC Energy accrues emission liabilities on the Consolidated balance sheet using the best estimate of the amount required to settle the compliance obligation. Allowances and credits not used for compliance are sold and any gain or loss is recorded in Revenues within the Power and Energy Solutions segment in the Consolidated statement of income. The Company records allowances and credits held for compliance in Other current assets and Other long-term assets on the Consolidated balance sheet. Allowances and credits not held for compliance are classified as Inventories on the Consolidated balance sheet.
Stock Options and Other Compensation Programs	Stock Options and Other Compensation Programs The Company no longer issues stock options to employees or officers. Stock options granted before 2024 were recorded using the fair value method. Under this method, compensation expense is measured at the grant date based on the fair value as calculated using a binomial model and is recognized on a straight-line basis over the vesting period with an offset to Additional paid-in capital. Forfeitures are accounted for when they occur. Upon exercise of stock options, amounts originally recorded against Additional paid-in capital are reclassified to Common shares on the Consolidated balance sheet. The Company has medium-term incentive plans under which payments are made to eligible employees. The expense related to these incentive plans is accounted for on an accrual basis. Under these plans, benefits vest when certain conditions are met, including the employees' continued employment during a specified period and achievement of specified corporate performance targets.
Employee Post-Retirement Benefits	Employee Post-Retirement Benefits The Company sponsors defined benefit pension plans (DB Plans), defined contribution plans (DC Plans), savings plans and other post-retirement benefit plans (OPEB Plans). Contributions made by the Company to the DC Plans and savings plans are expensed in the period in which contributions are made. The cost of the DB Plans and OPEB Plans received by employees is actuarially determined using the projected benefit method pro-rated based on service and management's best estimate of expected plan investment performance, salary escalation, retirement age of employees and expected health care costs. The DB Plans' assets are measured at fair value at December 31 of each year. The expected return on the DB Plans' assets is determined using market-related values based on a five-year moving average value for all of the DB Plans' assets. Past service costs are amortized over the expected average remaining service life (EARSL) of the employees. Adjustments arising from plan amendments are amortized on a straight-line basis over the EARSL of employees active at the date of amendment. The Company recognizes the overfunded or underfunded status of its DB Plans as an asset or liability, respectively, on its Consolidated balance sheet and recognizes changes in that funded status through Other comprehensive income (loss)(OCI) in the year in which the change occurs. The excess of net actuarial gains or losses over 10 per cent of the greater of the benefit obligation and the market-related value of the DB Plans' assets, if any, is amortized out of AOCI and into net income over the EARSL of the active employees. When the restructuring of a benefit plan gives rise to both a curtailment and a settlement, the curtailment is accounted for prior to the settlement. For certain regulated operations, post-retirement benefit amounts are recoverable through tolls as benefits are funded. The Company records any unrecognized gains or losses or changes in actuarial assumptions related to these post-retirement benefit plans as either regulatory assets or liabilities. The regulatory assets or liabilities are amortized on a straight-line basis over the EARSL of active employees.
Foreign Currency Transactions and Translation	Foreign Currency Transactions and Translation Foreign currency transactions are those transactions whose terms are denominated in a currency other than the currency of the primary economic environment in which the Company or reporting subsidiary operates. This is referred to as the functional currency. Transactions denominated in foreign currencies are translated into the functional currency using the exchange rate prevailing at the date of the transaction. Monetary assets and liabilities denominated in foreign currencies are translated to the functional currency using the rate of exchange in effect at the balance sheet date whereas non-monetary assets and liabilities are translated at the historical rate of exchange in effect on the date of the transaction. Exchange gains and losses resulting from translation of monetary assets and liabilities are recorded in net income except for exchange gains and losses on any foreign currency debt related to Canadian regulated natural gas pipelines, which are deferred until they are refunded or recovered in tolls, as permitted by the CER. Gains and losses arising from translation of foreign operations' functional currencies to the Company's Canadian dollar reporting currency are reflected in OCI until the operations are sold, at which time the gains and losses are reclassified to net income. For partial dispositions of foreign operations that do not result in a change of control, or dispositions of foreign operations other than by sale, gains and losses are reclassified within equity. Asset and liability accounts are translated at the rate of exchange in effect at the balance sheet date while revenues, expenses, gains and losses are translated at the exchange rate prevailing at the date of the transaction. The Company's U.S. dollar-denominated debt and certain derivative hedging instruments have been designated as a hedge of the net investment in foreign subsidiaries and, as a result, the unrealized foreign exchange gains and losses on the U.S. dollar-denominated debt and derivatives are also reflected in OCI.
Derivative Instruments and Hedging Activities	Derivative Instruments and Hedging Activities All derivative instruments are recorded on the Consolidated balance sheet at fair value, unless they qualify for and are designated under a normal purchase and normal sales exemption, or are considered to meet other permitted exemptions. The Company applies hedge accounting to arrangements that qualify for and are designated for hedge accounting treatment. This includes fair value and cash flow hedges as well as hedges of foreign currency exposures of net investments in foreign operations. Hedge accounting is discontinued prospectively if the hedging relationship ceases to be effective or the hedging or hedged items cease to exist as a result of maturity, expiry, sale, termination, cancellation or exercise. In a fair value hedging relationship, the carrying value of the hedged item is adjusted for changes in fair value attributable to the hedged risk and these changes are recognized in net income. Changes in the fair value of the hedged item, to the extent that the hedging relationship is effective, are offset by changes in the fair value of the hedging item, which are also recorded in net income. Changes in the fair value of foreign exchange and interest rate fair value hedges are recorded in Interest income and other and Interest expense, respectively. If hedge accounting is discontinued, the carrying value of the hedged item is no longer adjusted and the cumulative fair value adjustments to the carrying value of the hedged item are amortized to net income over the remaining term of the original hedging relationship. In a cash flow hedging relationship, the change in the fair value of the hedging derivative is recognized in OCI. When hedge accounting is discontinued, the amounts recognized previously in AOCI are reclassified to Revenues, Interest expense and Interest income and other, as appropriate, during the periods when the variability in cash flows of the hedged item affects net income or as the original hedged item settles. Gains and losses on derivatives are reclassified immediately to net income from AOCI when the hedged item is sold or terminated early, or when it becomes probable that the anticipated transaction will not occur. Termination payments on interest rate derivatives are classified as a financing activity in the Consolidated statement of cash flows. In hedging the foreign currency exposure of a net investment in a foreign operation, the foreign exchange gains and losses on the hedging instruments are recognized in OCI. The amounts recognized previously in AOCI are reclassified consistent with gains and losses arising from the translation of foreign operations, when the foreign operation is either entirely or partially disposed of. In some cases, derivatives do not meet the specific criteria for hedge accounting treatment. In these instances, the changes in fair value are recorded in net income in the period of change. Gains and losses arising from changes in the fair value of derivatives accounted for as part of RRA, including those that qualify for hedge accounting treatment, are refunded or recovered through the tolls charged by the Company. As a result, these gains and losses are deferred as regulatory liabilities or regulatory assets and are refunded to or collected from rate payers in subsequent periods when the derivative settles. Derivatives embedded in other financial instruments or contracts (host instrument) are recorded as separate derivatives. Embedded derivatives are measured at fair value if their economic characteristics are not clearly and closely related to those of the host instrument, their terms are the same as those of a stand-alone derivative and the total contract is not held for trading or accounted for at fair value. When changes in the fair value of embedded derivatives are measured separately, they are included in net income.
Long-Term Debt Transaction Costs and Issuance Costs	Long-Term Debt Transaction Costs and Issuance Costs The Company records long-term debt transaction costs and issuance costs as a deduction from the carrying amount of the related debt liability and amortizes these costs using the effective interest method except those related to the Canadian natural gas regulated pipelines, which continue to be amortized on a straight-line basis in accordance with the provisions of regulatory tolling mechanisms.
Guarantees	Guarantees Upon issuance, the Company records the fair value of certain guarantees entered into by the Company on behalf of a partially-owned entity or by partially-owned entities for which contingent payments may be made. The fair value of these guarantees is estimated by discounting the cash flows that would be incurred by the Company if letters of credit were used in place of the guarantees as appropriate in the circumstances. Guarantees are recorded as an increase to Equity investments or Plant, property and equipment and a corresponding liability is recorded in Other long-term liabilities. The release from the obligation is recognized either over the term of the guarantee or upon expiration or settlement of the guarantee.
Variable Interest Entities	Variable Interest Entities A VIE is a legal entity that does not have sufficient equity at risk to finance its activities without additional subordinated financial support or is structured such that equity investors lack the ability to make significant decisions relating to the entity’s operations through voting rights or do not substantively participate in the gains and losses of the entity. The assessment of whether an entity is a VIE and, if so, whether the Company is the primary beneficiary, is completed at the inception of the entity or at a reconsideration event. Consolidated VIEs The Company's consolidated VIEs consist of legal entities where the Company has a variable interest and for which it is considered the primary beneficiary. As the primary beneficiary, the Company has the power, through voting or similar rights, to direct the activities of the VIE that most significantly impact economic performance including: purchasing or selling significant assets; maintenance and operations of assets; incurring additional indebtedness; or determining the strategic operating direction of the entity. In addition, the Company has the obligation to absorb losses or the right to receive benefits from the consolidated VIE that could potentially be significant to the VIE. Non-Consolidated VIEs The Company’s non-consolidated VIEs consist of legal entities where the Company has a variable interest but is not the primary beneficiary as it does not have the power (either explicit or implicit), through voting or similar rights, to direct the activities that most significantly impact the economic performance of these VIEs or where this power is shared with third parties. The Company contributes capital to these VIEs and receives ownership interests that provide it with residual claims on assets after liabilities are paid. Non-consolidated VIEs are accounted for as equity investments. The Company’s maximum exposure to loss is the maximum loss that could potentially be recorded through net income in future periods as a result of the Company’s variable interest in a VIE.
Accounting Changes	ACCOUNTING CHANGES Changes in Accounting Policies for 2025 Income Taxes In December 2023, the FASB issued new guidance to enhance the transparency and usefulness of income tax disclosures through improvements to the rate reconciliation and income taxes paid information. The new guidance requires entities to disclose specific categories in the rate reconciliation and sets specific disaggregation requirements for reconciling items that meet certain thresholds. Additionally, entities are required to disclose disaggregated information on income taxes paid, income from continuing operations before tax and income tax expense from continuing operations. This new guidance was effective for annual periods beginning January 1, 2025. The Company adopted the guidance on a retrospective basis. The adoption of this guidance did not have a material impact on the Company's financial position or results of operations. Refer to Note 18, Income taxes, for additional information and the effects of the new guidance. Future Accounting Changes Disaggregation of Income Statement Expenses In November 2024, the FASB issued new guidance requiring additional disclosure on the nature of expenses included in the income statement. The new standard requires disclosures about specific types of expenses included in the expense captions presented on the face of the income statement as well as disclosures about selling expenses. The new guidance is effective for annual periods beginning January 1, 2027 and interim periods beginning January 1, 2028. Early adoption is permitted. The guidance is applied prospectively with retrospective application permitted. The Company is currently assessing the impact of the standard on the Company's consolidated financial statements. Internal-Use Software In September 2025, the FASB issued updated guidance for accounting for internal-use software costs. The updated guidance removes references to project development stages and outlines revised guidance for when capitalization begins for internal-use software costs. The guidance is effective for annual and interim periods beginning January 1, 2028. Early adoption is permitted as of the beginning of an annual reporting period. The guidance can be applied prospectively, retrospectively, or with a modified transition approach. The Company is currently assessing the impact of the standard on the Company's consolidated financial statements. Hedge Accounting Improvements In November 2025, the FASB issued new guidance to further align hedge accounting with the economics of an entity's risk management activities. The amendments are intended to allow entities to achieve and maintain hedge accounting for highly effective hedges of forecasted transactions. The new guidance is effective for interim and annual reporting periods beginning January 1, 2027. Early adoption is permitted. The guidance is applied on a prospective basis for all hedging relationships that exist at the date of adoption. The Company is currently assessing the impact of the standard on the Company's consolidated financial statements. Government Grants In December 2025, the FASB established authoritative guidance on the recognition, measurement and presentation requirements for government grants received. The new guidance is effective for annual and interim periods beginning January 1, 2029. Early adoption is permitted. The guidance can be applied with a modified prospective, a modified retrospective, or a retrospective approach. The Company is currently assessing the impact of the standard on the Company's consolidated financial statements.

EQUITY INVESTMENTS - Narrative (Details) - CAD ($) $ in Millions	9 Months Ended	12 Months Ended
	Sep. 30, 2023	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023	Nov. 30, 2024
Equity Investments
Impairment of equity investment (Note 10)		$ 0	$ 0	$ 2,100
Equity Investments (Note 10)		11,358	10,636
Difference between the carrying value of the investment and the underlying equity in the net assets		834	769
Coastal GasLink
Equity Investments
Additional aggregate cost					$ 199
Impairment losses pre tax	$ 5,148
Impairment charges after tax	$ 4,586
Coastal GasLink \| LNG Canada
Equity Investments
Proceeds from incentive fees				$ 200
Coastal GasLink \| Canadian Natural Gas Pipelines
Equity Investments
Equity Investments (Note 10)		$ 896	$ 1,006

COMMON SHARES - Shareholder Rights Plan (Details)	Dec. 31, 2025 shares
Shareholder Rights Plan
Number of rights entitled to each common share (in shares)	1

REVENUES - Contract Balances (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024
Revenue from Contract with Customer [Abstract]
Receivables from contracts with customers	$ 1,822	$ 1,452
Contract assets (Note 7)	216	165
Long-term contract assets (Note 14)	627	608
Contract liabilities (Note 16)	46	30
Revenue recognized	$ 21	$ 41

INCOME TAXES - Reconciliation of Unrecognized Tax Benefit (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Unrecognized Tax Benefits [Roll Forward]
Unrecognized tax benefit at beginning of year	$ 72	$ 85	$ 91
Gross increase - tax positions in prior years	2	3	9
Gross decrease - tax positions in prior years	(4)	(2)	(1)
Gross increase - tax positions in current year	18	5	16
Gross decrease - tax positions in current year	0	(2)	0
Settlement	0	(13)	0
Lapse of statutes of limitations	(5)	(4)	(30)
Unrecognized Tax Benefit at End of Year	$ 83	$ 72	$ 85

RATE-REGULATED BUSINESSES (Tables)

12 Months Ended

Dec. 31, 2025

Regulated Operations [Abstract]

Schedule of Regulatory Assets and Liabilities


at December 31	Remaining Recovery/ Settlement Period (years)	2025	2024
(millions of Canadian $)

Regulatory Assets
Deferred income taxes1	n/a	2,760	2,593
Operating and debt-service regulatory assets2	1	—	56

Foreign exchange on long-term debt1,3	1-4	23	39
Other	n/a	188	117
		2,971	2,805
Less: Current portion included in Other current assets (Note 7)		58	123
		2,913	2,682
Regulatory Liabilities

Pipeline abandonment trust balances4	n/a	3,143	2,686
Deferred income taxes – U.S. Tax Reform5	n/a	1,098	1,197
Canadian Mainline short-term adjustment and toll-stabilization accounts6,7	n/a	705	553
Cost of removal8	n/a	407	376
Canadian Mainline bridging amortization account6	5	268	322
Pensions and other post-retirement benefits9	n/a	266	122
Deferred income taxes1	n/a	195	188
Operating and debt-service regulatory liabilities2	1	134	50
ANR post-employment and retirement benefits other than pension10	n/a	43	45
Canadian Mainline long-term adjustment account6,11	1	37	74

Other	n/a	77	43
		6,373	5,656
Less: Current portion included in Accounts payable and other (Note 16)		532	353
		5,841	5,303

1These regulatory assets and liabilities are underpinned by non-cash transactions or are recovered without an allowance for return as approved by the regulator. Accordingly, these regulatory assets or liabilities are not included in rate base and do not yield a return on investment during the recovery period.

2Operating and debt-service regulatory assets and liabilities represent the accumulation of cost and revenue variances to be included in determination of rates in the following year.

3Foreign exchange on long-term debt of the NGTL System represents the variance resulting from revaluing foreign currency-denominated debt instruments to the current foreign exchange rate from the historical foreign exchange rate at the time of issue. Foreign exchange gains and losses realized when foreign debt matures or is redeemed early are expected to be recovered or refunded through the determination of future tolls.

4This balance represents the amounts collected in tolls from customers and is included in the LMCI restricted investments to fund future abandonment of the Company's CER-regulated pipeline facilities.

5The U.S. corporate income tax rate was reduced from 35 per cent to 21 per cent in 2017 as a result of H.R.1, the Tax Cuts and Jobs Act (U.S. Tax Reform). This U.S. regulated operations balance, where applicable, represents established regulatory liabilities driven by 2018 FERC prescribed changes related to U.S. Tax Reform being amortized over varying terms that approximate the expected reversal of the underlying deferred tax liabilities that gave rise to the regulatory liabilities.

6These regulatory accounts are used to capture revenue and cost variances plus toll-stabilization adjustments during the 2015-2030 settlement term.

7Under the terms of the 2021-2026 Mainline Settlement, a portion of the STAA account commenced amortization in 2023 and the remainder commenced amortization in 2024, as predetermined thresholds were met, over the terms outlined per the settlement agreement.

8This balance represents anticipated costs of removal that have been, and continue to be, included in depreciation rates and collected in the service rates of certain rate-regulated operations for future costs to be incurred.

9These balances represent the regulatory offset to pension plan and other post-retirement benefit obligations to the extent the amounts are expected to be collected from or refunded to customers in future rates.

10This balance represents the amount ANR estimates it would be required to refund to its customers for post-retirement and post-employment benefit amounts collected through its FERC-approved rates that have not been used to pay benefits to its employees. Pursuant to a FERC-approved rate settlement, the $43 million (US$32 million) balance at December 31, 2025 is subject to resolution through future regulatory proceedings and, accordingly, a settlement period cannot be determined at this time.

11Under the terms of the 2021-2026 Mainline Settlement, $223 million is amortized over the six-year settlement term.

JUNIOR SUBORDINATED NOTES - Narrative (Details) $ in Millions, $ in Millions	1 Months Ended			12 Months Ended
	Oct. 31, 2025 USD ($)	Aug. 31, 2025 USD ($)	Feb. 28, 2025 USD ($)	Dec. 31, 2025 CAD ($)	Dec. 31, 2025 USD ($)	Aug. 01, 2025	May 31, 2025 USD ($)	Dec. 31, 2024 CAD ($)
Debt Instrument [Line Items]
Unamortized debt issue costs				$ 251				$ 252
Junior subordinated notes \| TCPL
Debt Instrument [Line Items]
Unamortized debt issue costs				$ 123				$ 98
Junior subordinated debt, due 2075 \| Junior subordinated notes \| TCPL
Debt Instrument [Line Items]
Amount					$ 750
Interest Rate				5.88%	5.88%		5.88%
Unamortized debt issue costs							$ 11
Junior subordinated debt due 2085 \| Junior subordinated notes
Debt Instrument [Line Items]
Amount					$ 370
Interest Rate				6.25%	6.25%
Junior subordinated debt due 2085 \| Junior subordinated notes \| TCPL
Debt Instrument [Line Items]
Amount	$ 370
Interest Rate	6.25%
Redemption price as a percentage of principal amount plus accrued and unpaid interest	100.00%
Junior subordinated debt, due 2056 \| Junior subordinated notes
Debt Instrument [Line Items]
Amount				$ 1,000
Interest Rate				5.20%	5.20%
Junior subordinated debt, due 2056 \| Junior subordinated notes \| TCPL
Debt Instrument [Line Items]
Amount		$ 1,000
Interest Rate		5.20%				2.148%
Stated interest rate, period of time		5 years		5 years
Redemption price as a percentage of principal amount plus accrued and unpaid interest		100.00%
Junior subordinated debt, due 2065 \| Junior subordinated notes
Debt Instrument [Line Items]
Amount					$ 750
Interest Rate				7.00%	7.00%
Junior subordinated debt, due 2065 \| Junior subordinated notes \| TCPL
Debt Instrument [Line Items]
Amount			$ 750
Stated interest rate, period of time				5 years
Redemption price as a percentage of principal amount plus accrued and unpaid interest			100.00%
Junior subordinated debt, due 2065 \| Junior subordinated notes \| TCPL \| Period one
Debt Instrument [Line Items]
Interest Rate			7.00%
Stated interest rate, period of time			5 years
Junior subordinated debt, due 2065 \| Junior subordinated notes \| TCPL \| Period two
Debt Instrument [Line Items]
Interest Rate			2.614%
Stated interest rate, period of time			5 years
Junior subordinated debt, due 2065 \| Junior subordinated notes \| TCPL \| Period three
Debt Instrument [Line Items]
Stated interest rate, period of time			10 years

INCOME TAXES - Provision (Details) - CAD ($) $ in Millions	12 Months Ended
INCOME TAXES - Provision (Details) - CAD ($) $ in Millions	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Current
Total	$ 367	$ 495	$ 864
Deferred
Total	771	427	(22)
Income Tax Expense	1,138	922	842
Canada
Current
Canada - federal	54	90	34
Canada - provincial	5	71	40
Deferred
Canada - federal	213	80	3
Canada - provincial	139	56	3
Other foreign jurisdictions
Current
Foreign	308	334	790
Deferred
Foreign	$ 419	$ 291	$ (28)

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - Derivative Assets and Liabilities Measured on a Recurring Basis (Details) $ in Millions	12 Months Ended
	Dec. 31, 2025 CAD ($) MWh	Dec. 31, 2024 CAD ($)
Fair Value Hierarchy
Derivative Instrument Assets	$ 599	$ 469
Derivative Instrument Liabilities	$ (529)	(716)
Power
Fair Value Hierarchy
Notional amount, energy (mwh) \| MWh	50
Power \| Minimum
Fair Value Hierarchy
Notional amount, life (in years)	15 years
Power \| Maximum
Fair Value Hierarchy
Notional amount, life (in years)	20 years
Wind Generation
Fair Value Hierarchy
Source allocation percentage	80.00%
Solar Generation
Fair Value Hierarchy
Source allocation percentage	10.00%
Market
Fair Value Hierarchy
Source allocation percentage	10.00%
Recurring basis
Fair Value Hierarchy
Assets and (liabilities), net	$ 70	(247)
Recurring basis \| Quoted Prices in Active Markets (Level I)
Fair Value Hierarchy
Assets and (liabilities), net	3	10
Recurring basis \| Significant Other Observable Inputs (Level II)
Fair Value Hierarchy
Assets and (liabilities), net	(7)	(329)
Recurring basis \| Significant Unobservable Inputs (Level III)
Fair Value Hierarchy
Assets and (liabilities), net	74	72
Recurring basis \| Commodities \| Power
Fair Value Hierarchy
Derivative Instrument Assets	508	418
Derivative Instrument Liabilities	(404)	(339)
Recurring basis \| Commodities \| Quoted Prices in Active Markets (Level I) \| Power
Fair Value Hierarchy
Derivative Instrument Assets	154	126
Derivative Instrument Liabilities	(151)	(116)
Recurring basis \| Commodities \| Significant Other Observable Inputs (Level II) \| Power
Fair Value Hierarchy
Derivative Instrument Assets	279	214
Derivative Instrument Liabilities	(252)	(217)
Recurring basis \| Commodities \| Significant Unobservable Inputs (Level III) \| Power
Fair Value Hierarchy
Derivative Instrument Assets	75	78
Derivative Instrument Liabilities	(1)	(6)
Recurring basis \| Foreign exchange
Fair Value Hierarchy
Derivative Instrument Assets	66	51
Derivative Instrument Liabilities	(83)	(238)
Recurring basis \| Foreign exchange \| Quoted Prices in Active Markets (Level I)
Fair Value Hierarchy
Derivative Instrument Assets	0	0
Derivative Instrument Liabilities	0	0
Recurring basis \| Foreign exchange \| Significant Other Observable Inputs (Level II)
Fair Value Hierarchy
Derivative Instrument Assets	66	51
Derivative Instrument Liabilities	(83)	(238)
Recurring basis \| Foreign exchange \| Significant Unobservable Inputs (Level III)
Fair Value Hierarchy
Derivative Instrument Assets	0	0
Derivative Instrument Liabilities	0	0
Recurring basis \| Interest rate
Fair Value Hierarchy
Derivative Instrument Assets	25
Derivative Instrument Liabilities	(42)	(139)
Recurring basis \| Interest rate \| Quoted Prices in Active Markets (Level I)
Fair Value Hierarchy
Derivative Instrument Assets	0
Derivative Instrument Liabilities	0	0
Recurring basis \| Interest rate \| Significant Other Observable Inputs (Level II)
Fair Value Hierarchy
Derivative Instrument Assets	25
Derivative Instrument Liabilities	(42)	(139)
Recurring basis \| Interest rate \| Significant Unobservable Inputs (Level III)
Fair Value Hierarchy
Derivative Instrument Assets	0
Derivative Instrument Liabilities	$ 0	$ 0

SEGMENTED INFORMATION - Schedule of Segment Reporting Information, by Segment (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Segmented information
Revenues	$ 15,239	$ 13,771	$ 13,267
Revenues, including intersegment revenues	15,239	13,771	13,267
Income (loss) from equity investments	1,274	1,558	1,310
Impairment of equity investment (Note 10)	0	0	(2,100)
Operating costs	(5,708)	(5,450)	(4,934)
Depreciation and amortization	(2,769)	(2,535)	(2,446)
Other segment items		620
Segmented Earnings (Losses)	8,036	7,964	5,097
Interest expense	(3,407)	(3,019)	(2,966)
Allowance for funds used during construction	453	784	575
Foreign exchange gains (losses), net	157	(147)	320
Interest income and other	205	324	272
Income (Loss) from Continuing Operations before Income Taxes	5,444	5,906	3,298
Income tax (expense) recovery from continuing operations	(1,138)	(922)	(842)
Net Income (Loss) from Continuing Operations	4,306	4,984	2,456
Net Income (Loss) from Discontinued Operations, Net of Tax	(212)	395	612
Net Income (Loss)	4,094	5,379	3,068
Net (income) loss attributable to non-controlling interests	(575)	(681)	(146)
Net Income (Loss) Attributable to Controlling Interests	3,519	4,698	2,922
Preferred share dividends	(119)	(104)	(93)
Net income (loss) attributable to common shares from continuing operations	3,400	4,594	2,829
Capital Spending
Capital expenditures	5,270	6,181	7,958
Capital projects in development	16	50	142
Contributions to equity investments, net of distributions	1,051
Contributions to equity method investments	6,337	1,546	4,149
Contributions to equity investments		7,777	12,249
Discontinued operations		127	49
Capital Spending		7,904	12,298
Coastal GasLink
Capital Spending
Contributions to equity investments, net of distributions		3,100
Intersegment eliminations
Segmented information
Revenues	(151)	(148)	(123)
Operating segments
Segmented information
Revenues	15,225	13,763
Corporate
Segmented information
Revenues	14	8	0
Revenues, including intersegment revenues	(137)	(140)	(123)
Income (loss) from equity investments	0	0	0
Impairment of equity investment (Note 10)			0
Operating costs	123	9	(15)
Depreciation and amortization	0	(5)	(6)
Other segment items		0
Segmented Earnings (Losses)	(14)	(136)	(144)
Capital Spending
Capital expenditures	31	50	33
Capital projects in development	0	0	0
Contributions to equity investments, net of distributions	0
Contributions to equity method investments	31	0	0
Contributions to equity investments		50	33
Canadian Natural Gas Pipelines
Segmented information
Revenues	5,785	5,600	5,173
Canadian Natural Gas Pipelines \| Coastal GasLink
Segmented information
Income (loss) from equity investments	95	17	203
Canadian Natural Gas Pipelines \| Intersegment eliminations
Segmented information
Revenues	0	0	0
Canadian Natural Gas Pipelines \| Operating segments
Segmented information
Revenues	5,785	5,600	5,173
Revenues, including intersegment revenues	5,785	5,600	5,173
Income (loss) from equity investments	112	34	220
Impairment of equity investment (Note 10)			(2,100)
Operating costs	(2,210)	(2,246)	(2,058)
Depreciation and amortization	(1,523)	(1,382)	(1,325)
Other segment items		10
Segmented Earnings (Losses)	2,164	2,016	(90)
Capital Spending
Capital expenditures	1,340	1,273	2,953
Capital projects in development	0	0	0
Contributions to equity investments, net of distributions	65
Contributions to equity method investments	1,405	827	3,231
Contributions to equity investments		2,100	6,184
U.S. Natural Gas Pipelines
Segmented information
Revenues	7,145	6,339	6,229
U.S. Natural Gas Pipelines \| Intersegment eliminations
Segmented information
Revenues	(99)	(99)	(101)
U.S. Natural Gas Pipelines \| Operating segments
Segmented information
Revenues	7,145	6,339	6,229
Revenues, including intersegment revenues	7,244	6,438	6,330
Income (loss) from equity investments	301	341	324
Impairment of equity investment (Note 10)			0
Operating costs	(2,581)	(2,381)	(2,189)
Depreciation and amortization	(1,037)	(955)	(934)
Other segment items		610
Segmented Earnings (Losses)	3,927	4,053	3,531
Capital Spending
Capital expenditures	3,316	2,568	2,536
Capital projects in development	0	5	0
Contributions to equity investments, net of distributions	141
Contributions to equity method investments	3,457	2	124
Contributions to equity investments		2,575	2,660
Mexico Natural Gas Pipelines
Segmented information
Revenues	1,450	870	846
Mexico Natural Gas Pipelines \| Intersegment eliminations
Segmented information
Revenues	0	0	0
Mexico Natural Gas Pipelines \| Operating segments
Segmented information
Revenues	1,450	870	846
Revenues, including intersegment revenues	1,450	870	846
Income (loss) from equity investments	94	283	78
Impairment of equity investment (Note 10)			0
Operating costs	(262)	(132)	(39)
Depreciation and amortization	(96)	(92)	(89)
Other segment items		0
Segmented Earnings (Losses)	1,186	929	796
Capital Spending
Capital expenditures	522	2,228	2,292
Capital projects in development	0	0	0
Contributions to equity investments, net of distributions	0
Contributions to equity method investments	522	0	0
Contributions to equity investments		2,228	2,292
Power and Energy Solutions
Segmented information
Revenues	845	954	1,019
Power and Energy Solutions \| Intersegment eliminations
Segmented information
Revenues	(52)	(49)	(22)
Power and Energy Solutions \| Operating segments
Segmented information
Revenues	845	954	1,019
Revenues, including intersegment revenues	897	1,003	1,041
Income (loss) from equity investments	767	900	688
Impairment of equity investment (Note 10)			0
Operating costs	(778)	(700)	(633)
Depreciation and amortization	(113)	(101)	(92)
Other segment items		0
Segmented Earnings (Losses)	773	1,102	1,004
Capital Spending
Capital expenditures	61	62	144
Capital projects in development	16	45	142
Contributions to equity investments, net of distributions	845
Contributions to equity method investments	922	717	794
Contributions to equity investments		824	$ 1,080
Corporate
Segmented information
Revenues	$ 14	$ 8

COMMON SHARES - Stock Options Assumptions Used (Details)	12 Months Ended
	Dec. 31, 2023 $ / shares
Common Stock, Number of Shares, Par Value and Other Disclosure [Abstract]
Weighted average fair value (in Canadian dollars per share)	$ 7.88
Expected life (years)	5 years 1 month 6 days
Interest rate	2.90%
Volatility	24.00%
Dividend yield	6.30%

Consolidated statement of equity - CAD ($) $ in Millions	Total	Equity Attributable to Controlling Interests	Common Shares (Note 23)	Preferred Shares (Note 24)	Additional Paid-In Capital	Retained Earnings (Accumulated Deficit)	Total	Equity Attributable to Non-Controlling Interests
Balance at beginning of year at Dec. 31, 2022			$ 28,995	$ 2,499	$ 722	$ 819	$ 955	$ 126
Shares issued:
Exercise of stock options			4
Dividend reinvestment and share purchase plan			1,003
Issuance of stock options, net of exercises					9
Disposition of equity interest, net of transaction costs (Note 29)					(3,537)			9,451
Reclassification of additional paid-in capital deficit to accumulated deficit					2,806	(2,806)
Net income (loss) attributable to controlling interests	$ 2,922					2,922
Common share dividends						(3,839)
Preferred share dividends						(93)
Other comprehensive income (loss) attributable to controlling interests	(1,272)						(379)
Impact of non-controlling interest (Note 29)							(527)
Net income (loss) attributable to non-controlling interests (Note 22)	(146)							146
Other comprehensive income (loss) attributable to non-controlling interests								(366)
Non-controlling interests on acquisition of Texas Wind Farms (Note 29)								222
Distributions declared to non-controlling interests								(124)
Balance at end of year at Dec. 31, 2023	39,008	$ 29,553	30,002	2,499	0	(2,997)	49	9,455
Shares issued:
Exercise of stock options			99
Issuance of stock options, net of exercises					(5)
Disposition of equity interest, net of transaction costs (Note 29)					(41)			461
Reclassification of additional paid-in capital deficit to accumulated deficit					46	(46)
Net income (loss) attributable to controlling interests	4,698					4,698
Common share dividends						(3,842)
Preferred share dividends						(104)
Spinoff of Liquids Pipelines business (Note 4)						(2,950)	(741)
Other comprehensive income (loss) attributable to controlling interests	1,828						946
Impact of non-controlling interest (Note 29)							(21)
Net income (loss) attributable to non-controlling interests (Note 22)	(681)							681
Other comprehensive income (loss) attributable to non-controlling interests								903
Contributions from non-controlling interests								21
Distributions declared to non-controlling interests								(753)
Balance at end of year at Dec. 31, 2024	38,360	27,592	30,101	2,499	0	(5,241)	233	10,768
Shares issued:
Exercise of stock options			117
Redemption of shares				(244)
Issuance of stock options, net of exercises					(7)
Disposition of equity interest, net of transaction costs (Note 29)								(348)
Reclassification of additional paid-in capital deficit to accumulated deficit					7	(7)
Net income (loss) attributable to controlling interests	3,519					3,519
Common share dividends						(3,537)
Preferred share dividends						(117)
Spinoff of Liquids Pipelines business (Note 4)						(542)	542
Other comprehensive income (loss) attributable to controlling interests	(887)						(376)
Impact of non-controlling interest (Note 29)							348
Net income (loss) attributable to non-controlling interests (Note 22)	(575)							575
Other comprehensive income (loss) attributable to non-controlling interests								(511)
Distributions declared to non-controlling interests								(880)
Balance at end of year at Dec. 31, 2025	$ 36,899	$ 27,295	$ 30,218	$ 2,255	$ 0	$ (5,925)	$ 747	$ 9,604

INCOME TAXES (Tables)

12 Months Ended

Dec. 31, 2025

Income Tax Disclosure [Abstract]

Schedule of Geographic Components of Income

Geographic Components of Income before Income Taxes


year ended December 31	2025	2024	2023
(millions of Canadian $)

Canada	1,959	1,469	(194)
Foreign	3,485	4,437	3,492
Income before Income Taxes	5,444	5,906	3,298

Schedule of Provision for Income Taxes


year ended December 31	2025	2024	2023
(millions of Canadian $)

Current
Canada - federal	54	90	34
Canada - provincial	5	71	40
Foreign	308	334	790
	367	495	864
Deferred
Canada - federal	213	80	3
Canada - provincial	139	56	3
Foreign	419	291	(28)
	771	427	(22)
Income Tax Expense	1,138	922	842

Schedule of Reconciliation of Income Tax Expense


year ended December 31	2025				2024				2023
(millions of Canadian $, unless otherwise noted)	Amount		Percentage		Amount		Percentage		Amount		Percentage

Income before income taxes	5,444				5,906				3,298
Canadian federal statutory income tax rate	15	%			15	%			15	%
Expected income tax expense	817				886				495
Canadian federal reconciling items
Income tax differential related to regulated operations	(24)		(0.4	%)	(68)		(1.2	%)	(108)		(3.3	%)


Non-taxable capital (gain) loss	(20)		(0.4	%)	12		0.2	%	113		3.4	%
Changes in valuation allowances	—		—		3		0.1	%	114		3.5	%
Effect of cross-border taxes	(25)		(0.5	%)	(23)		(0.4	%)	(27)		(0.8	%)
Canadian provincial taxes1	143		2.6	%	103		1.7	%	22		0.7	%
Foreign reconciling items
United States
Rate differential	177		3.3	%	168		2.8	%	136		4.1	%
State and local income taxes, net of federal effect	(28)		(0.5	%)	123		2.1	%	76		2.3	%

Income from non-controlling interests	(125)		(2.3	%)	(121)		(2.0	%)	(31)		(0.9	%)
Other	(16)		(0.3	%)	(12)		(0.2	%)	(8)		(0.2	%)
Mexico
Mexico foreign exchange exposure	213		3.9	%	(246)		(4.2	%)	163		4.9	%
Rate differential	57		1.0	%	234		4.0	%	94		2.9	%
Income from equity investments	(28)		(0.5	%)	(84)		(1.4	%)	(23)		(0.7	%)
Income tax differential related to regulated operations	(45)		(0.8	%)	(109)		(1.8	%)	(79)		(2.4	%)
Withholding tax	41		0.8	%	35		0.6	%	12		0.4	%
Other	8		0.1	%	2		—		2		0.1	%
Other foreign jurisdictions	(2)		—		3		0.1	%	(91)		(2.8	%)

Other adjustments	(5)		(0.1	%)	16		0.3	%	(18)		(0.5	%)
Income Tax Expense	1,138		20.9	%	922		15.7	%	842		25.7	%

1 Ontario provincial tax comprises the majority of Canada provincial taxes.

Schedule of Deferred Income Tax Assets and Liabilities and Amounts Classified in the Consolidated Balance Sheet


at December 31	2025	2024
(millions of Canadian $)

Deferred Income Tax Assets
Tax loss and credit carryforwards	1,728	1,987
Disallowed interest carryforward	100	115
Regulatory and other deferred amounts	644	612
Unrealized foreign exchange losses on long-term debt	290	467

Other	57	143
	2,819	3,324
Less: Valuation allowance	789	931
	2,030	2,393
Deferred Income Tax Liabilities
Difference in accounting and tax bases of plant, property and equipment	6,792	6,488
Equity investments	1,478	1,280
Taxes on future revenue requirement	654	612
Financial instruments	176	168
Other	251	301
	9,351	8,849
Net Deferred Income Tax Liabilities	7,321	6,456

The above deferred tax amounts have been classified on the Consolidated balance sheet as follows:


at December 31	2025	2024
(millions of Canadian $)

Deferred Income Tax Assets
Other long-term assets (Note 14)	356	428
Deferred Income Tax Liabilities
Deferred income tax liabilities	7,677	6,884
Net Deferred Income Tax Liabilities	7,321	6,456

The following table provides details of the tax loss and credit carryforwards and valuation allowances:


at December 31, 2025	Unused Amounts	Deferred Tax Asset	Valuation Allowance	Expiry Years
(millions of Canadian $)

Tax Loss and Credit Carryforwards
Operating losses	5,838	1,302	—	2026-2045
Foreign federal and state operating losses	1,746	173	41	2026-2037
Capital loss	618	74	74	Indefinite
Minimum tax	—	179	42	2033-Indefinite
		1,728	157
Restricted Interest and Financing Expense	424	100	—	Indefinite
Unrealized Foreign Exchange on Long-Term Debt	—	290	290
Equity Investments	—	342	342
			789

Schedule of Income Tax Payments (Refunds)

Income Tax Payments (Refunds)


at December 31	2025	2024	2023
(millions of Canadian $)
Jurisdiction
Canada - federal	73	53	61
Canada - provincial	17	6	(1)
United States	368	302	692
Mexico	84	34	26
Other - foreign	1	(8)	13
	543	387	791

Schedule of Reconciliation of Unrecognized Tax Benefit

Below is the reconciliation of the annual changes in the total unrecognized tax benefit:


at December 31	2025	2024	2023
(millions of Canadian $)

Unrecognized tax benefit at beginning of year	72	85	91
Gross increase - tax positions in prior years	2	3	9
Gross decrease - tax positions in prior years	(4)	(2)	(1)
Gross increase - tax positions in current year	18	5	16
Gross decrease - tax positions in current year	—	(2)	—
Settlement	—	(13)	—
Lapse of statutes of limitations	(5)	(4)	(30)
Unrecognized Tax Benefit at End of Year	83	72	85

COMMON SHARES - Stock Options Narrative (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Equity [Abstract]
Number of shares available for grant (in shares)	3,994,688
Options expiration term	7 years
Award vesting period	3 years
Expense for stock options	$ 7.0	$ 6.0	$ 9.0
Unrecognized compensation costs related to non-vested stock options	$ 0.8
Expense recognition period	1 month 6 days
Options, exercisable, intrinsic value	$ 23.0	20.0
Options, outstanding, intrinsic value	$ 34.0	$ 34.0

EQUITY INVESTMENTS

12 Months Ended

Dec. 31, 2025

Equity Method Investments and Joint Ventures [Abstract]

EQUITY INVESTMENTS


(millions of Canadian $)	Ownership Interest at December 31, 2025		Income (Loss) from Equity Investments			Equity Investments
			year ended December 31			at December 31
			2025	2024	2023	2025	2024

Canadian Natural Gas Pipelines
TQM1	50	%	17	17	17	158	160
Coastal GasLink1	35	%	95	17	203	896	1,006
U.S. Natural Gas Pipelines
Northern Border	50	%	145	130	101	766	647
Millennium	47.5	%	70	95	109	(22)	(21)
Iroquois	50	%	70	100	98	216	221
Other	Various		16	16	16	137	135
Mexico Natural Gas Pipelines
Sur de Texas	60	%	94	283	78	1,427	1,403





Power and Energy Solutions
Bruce Power1	48.3	%	767	900	690	7,780	7,043
Other	Various		—	—	(2)	—	42
			1,274	1,558	1,310	11,358	10,636

1Classified as a VIE. Refer to Note 31, Variable interest entities, for additional information.

Distributions and Contributions

Distributions received from equity investments and contributions made to equity investments for the years ended December 31, 2025, 2024 and 2023 were as follows:


year ended December 31	2025	2024	2023
(millions of Canadian $)

Distributions
Distributions received from operating activities of equity investments	1,616	1,607	1,158
Coastal GasLink LP subordinated loan repayment1,2	—	3,147	—
Other1	5	539	23

	1,621	5,293	1,181
Contributions1
Contributions made to other equity investments	986	719	918
Contributions to Coastal GasLink LP2	65	3,964	3,231
	1,051	4,683	4,149

1Included in Investing activities in the Consolidated statement of cash flows.

2In December 2024, TC Energy made an equity contribution of $3,137 million to Coastal GasLink LP, which used the funds to repay the balance owing to TC Energy under the subordinated loan agreement. The contribution and repayment were included in Investing activities in the Consolidated statement of cash flows. Refer to Note 11, Loans with affiliates, for additional information.

Coastal GasLink Pipeline Limited Partnership

In November 2024, Coastal GasLink Pipeline Limited Partnership (Coastal GasLink LP) executed a commercial agreement with LNG Canada (LNGC) and each of the five LNGC participants (LNGC Participants) that declared commercial in-service for the Coastal GasLink pipeline, enabling toll collection from customers retroactive to October 1, 2024. The agreement also provided for a one-time payment of $199 million from LNGC Participants to TC Energy in recognition of completed work and final cost settlement, payable upon the earlier of three months following the LNG facility's declared in-service date or December 15, 2025.

Effective July 12, 2025, the LNG facility was declared in-service by LNGC. Pursuant to the commercial agreement, TC Energy received the one-time payment of $199 million, settled through a cash distribution in October 2025. This payment, which accrues entirely to TC Energy under the contractual arrangements between the Coastal GasLink LP partners, was recognized as an in-substance distribution from Coastal GasLink LP and reflected in Accounts receivable and Equity investments on the Company's Consolidated balance sheet as at December 31, 2024.

The Coastal GasLink project reached mechanical completion in November 2023 and was ready to deliver commissioning gas to the LNGC facility by the end of 2023. These milestones entitled Coastal GasLink LP to receive a $200 million incentive payment from LNGC, which was recorded as Accounts receivable on the Consolidated balance sheet and Income (loss) from equity investments in the Consolidated statement of income as at and for the year ended December 31, 2023. The incentive payment was settled through a cash distribution in February 2024.

In February 2023, Coastal GasLink LP announced an increase in the revised capital cost of the Coastal GasLink pipeline. The increase in project costs and the expectation that additional equity contributions under the subordinated loan agreement would be predominantly funded by TC Energy was an indication of significant adverse impact on the estimated fair value of the Company’s investment in Coastal GasLink LP. The Company completed valuation assessments and concluded that the fair value of its investment in Coastal GasLink LP was below its carrying value, which resulted in a pre-tax impairment charge of $2,100 million in 2023 and cumulative impairment charges of $5,148 million, or $4,586 million after tax, between December 31, 2022 and September 30, 2023. No further indication of other-than-temporary impairments of the Company's investment in Coastal GasLink LP have since been identified and no further impairment charges have been recorded.

At December 31, 2025, the carrying value of the Company's investment in Coastal GasLink LP was $896 million (2024 – $1,006 million).

Summarized Financial Information of Equity Investments


year ended December 31	2025	2024	2023
(millions of Canadian $)

Income
Revenues	7,493	6,962	6,197
Operating and other expenses	(4,412)	(3,783)	(3,343)
Net income	2,405	3,026	2,457
Net income attributable to TC Energy	1,274	1,558	1,310


at December 31	2025	2024
(millions of Canadian $)

Balance Sheet
Current assets	3,438	3,959
Non-current assets	47,233	44,835
Current liabilities	(1,888)	(2,111)
Non-current liabilities	(22,389)	(21,729)

At December 31, 2025, the cumulative carrying value of the Company’s equity investments was $834 million (2024 – $769 million) lower than the cumulative underlying equity in the net assets primarily due to the impairment of the equity investment in Coastal GasLink LP, partially offset by fair value adjustments at the time of acquisition or partial disposition, as well as interest capitalized during construction.

Consolidated statement of comprehensive income - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Statement of Comprehensive Income [Abstract]
Net Income (Loss)	$ 4,094	$ 5,379	$ 3,068
Other Comprehensive Income (Loss), Net of Tax
Foreign currency translation gains and losses on net investment in foreign operations	(978)	1,602	(1,141)
Reclassification of foreign currency translation (gains) losses on net investment on disposal of foreign operations	0	(25)	0
Change in fair value of net investment hedges	1	(18)	17
Change in fair value of cash flow hedges	(22)	35	0
Reclassification to net income of (gains) losses on cash flow hedges	31	(16)	74
Unrealized actuarial gains (losses) on pension and other post-retirement benefit plans	79	83	(11)
Reclassification to net income of actuarial (gains) losses on pension and other post-retirement benefit plans	0	(6)	0
Other comprehensive income (loss) on equity investments	2	173	(211)
Other comprehensive income (loss) (Note 25)	(887)	1,828	(1,272)
Comprehensive Income (Loss)	3,207	7,207	1,796
Comprehensive income (loss) attributable to non-controlling interests	64	1,584	(220)
Comprehensive Income (Loss) Attributable to Controlling Interests	3,143	5,623	2,016
Preferred share dividends	119	104	93
Comprehensive Income (Loss) Attributable to Common Shares	$ 3,024	$ 5,519	$ 1,923

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS

12 Months Ended

Dec. 31, 2025

Risk Management and Financial Instruments [Abstract]

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS

Risk Management Overview

TC Energy has exposure to various financial risks and has strategies, policies and limits in place to manage the impact of these risks on its earnings, cash flows and, ultimately, shareholder value.

Risk management strategies, policies and limits are designed to ensure TC Energy's risks and related exposures are in line with the Company's business objectives and risk tolerance. TC Energy's risks are managed within limits that are established by the Company's Board, implemented by senior management and monitored by the Company's risk management, internal audit and business segment groups. The Board's Audit Committee oversees how management monitors compliance with risk management policies and procedures and oversees management's review of the adequacy of the risk management framework.

Market Risk

The Company constructs and invests in energy infrastructure projects, purchases and sells commodities, issues short- and long‑term debt, including amounts in foreign currencies and invests in foreign operations. Certain of these activities expose the Company to market risk from changes in commodity prices, foreign exchange rates and interest rates, which may affect the Company's earnings, cash flows and the value of its financial assets and liabilities. The Company assesses contracts used to manage market risk to determine whether all, or a portion, meets the definition of a derivative.

Derivative contracts the Company uses to assist in managing exposure to market risk may include the following:

•forwards and futures contracts – agreements to purchase or sell a specific financial instrument or commodity at a specified price and date in the future

•swaps – agreements between two parties to exchange streams of payments over time according to specified terms

•options – agreements that convey the right, but not the obligation of the purchaser to buy or sell a specific amount of a financial instrument or commodity at a fixed price, either at a fixed date or at any time within a specified period.

Commodity price risk

The following strategies may be used to manage the Company's exposure to market risk resulting from commodity price risk management activities in the Company's non-regulated businesses:

•in the Company's natural gas marketing business, TC Energy enters into natural gas transportation and storage contracts as well as natural gas purchase and sale agreements. The Company manages exposure on these contracts using financial instruments and hedging activities to offset market price volatility

•in the Company's power businesses, TC Energy manages the exposure to fluctuating commodity prices through long-term contracts and hedging activities including selling and purchasing electricity and natural gas in forward markets

•in the Company's non-regulated natural gas storage business, TC Energy's exposure to seasonal natural gas price spreads is managed with a portfolio of third-party storage capacity contracts and through offsetting purchases and sales of natural gas in forward markets to lock in future positive margins.

Lower natural gas and electricity prices could lead to reduced investment in the development, expansion and production of these commodities. A reduction in the demand for these commodities could negatively impact opportunities to expand the Company's asset base and/or re-contract with TC Energy's shippers and customers as contractual agreements expire.

Physical and transition risks

Climate-related physical and transition risks may influence demand for, or the operation of, TC Energy's assets, which could affect the Company’s financial performance. TC Energy evaluates the financial resilience of its asset portfolio against a range of future pricing and supply and demand outcomes as part of the Company's strategic planning process.

TC Energy manages exposure to climate-related transition risks and resulting policy changes through its business model, which is based on a long-term, low-risk strategy whereby the majority of TC Energy’s earnings are underpinned by regulated cost-of-service arrangements and/or long-term contracts. Physical and transition risks are factored into capital planning, enterprise risk management, financial risk management and operational activities. In addition, the Company is actively working to reduce methane emissions intensity from our natural gas transmission and gas storage assets.

Interest rate risk

TC Energy utilizes short- and long-term debt to finance its operations which exposes the Company to interest rate risk. TC Energy typically pays fixed rates of interest on its long-term debt and floating rates on short-term debt including its commercial paper programs and amounts drawn on its credit facilities. A small portion of TC Energy's long-term debt bears interest at floating rates. In addition, the Company is exposed to interest rate risk on financial instruments and contractual obligations containing variable interest rate components. The Company actively manages its interest rate risk using interest rate derivatives.

Foreign exchange risk

Certain of TC Energy's businesses generate all or most of their earnings in U.S. dollars and, since the Company reports its financial results in Canadian dollars, changes in the value of the U.S. dollar against the Canadian dollar can affect its net income. This exposure grows as the Company's U.S. dollar-denominated operations grow. A portion of this risk is offset by interest expense on U.S. dollar-denominated debt. The balance of the exposure is actively managed on a rolling basis up to three years in advance using foreign exchange derivatives; however, the natural exposure beyond that period remains.

A portion of the Company's Mexico Natural Gas Pipelines monetary assets and liabilities are peso-denominated, while TC Energy's Mexico operations' financial results are denominated in U.S. dollars. These peso‑denominated balances are revalued to U.S. dollars and, as a result, changes in the value of the Mexican peso against the U.S. dollar can affect the Company's net income. In addition, foreign exchange gains or losses calculated for Mexico income tax purposes on the revaluation of U.S. dollar‑denominated monetary assets and liabilities result in a peso‑denominated income tax exposure for these entities, leading to fluctuations in Income (loss) from equity investments and Income tax expense (recovery). These exposures are actively managed using foreign exchange derivatives, although some unhedged exposure remains.

Net investment in foreign operations

The Company hedges a portion of its net investment in foreign operations (on an after-tax basis) with U.S. dollar‑denominated debt and cross-currency interest rate swaps as appropriate.

The fair values and notional amounts for the derivatives designated as a net investment hedge were as follows:

at December 31

2025

2024

Fair
Value

Notional Amount

Fair
Value1,2

Notional Amount

(millions of Canadian $, unless otherwise noted)

U.S. dollar cross-currency interest rate swaps3

—

(11)

US 100

1Fair value equals carrying value.

2No amounts have been excluded from the assessment of hedge effectiveness.

3In 2025 and 2024, Net income (loss) included net realized gains of less than $1 million related to the interest component of cross-currency swap settlements which are reported within Interest expense in the Consolidated statement of income.

The notional amounts and fair values of U.S. dollar-denominated debt designated as a net investment hedge were as follows:

at December 31

2025

2024

(millions of Canadian $, unless otherwise noted)

Notional amount

25,700 (US 18,700)

26,000 (US 18,000)

Fair value

25,800 (US 18,800)

25,700 (US 17,800)

Counterparty Credit Risk

TC Energy's exposure to counterparty credit risk includes its cash and cash equivalents, accounts receivable, available-for-sale assets, the fair value of derivative assets, net investment in leases and certain contract assets in Mexico.

At times, the Company's counterparties may endure financial challenges resulting from commodity price and market volatility, economic instability and political or regulatory changes. In addition to actively monitoring these situations, there are a number of factors that reduce TC Energy's counterparty credit risk exposure in the event of default, including:

•contractual rights and remedies together with the utilization of contractually-based financial assurances

•current regulatory frameworks governing certain TC Energy operations

•the competitive position of the Company's assets and the demand for the Company's services

•potential recovery of unpaid amounts through bankruptcy and similar proceedings.

The Company reviews financial assets carried at amortized cost for impairment using the lifetime expected loss of the financial asset at initial recognition and throughout the life of the financial asset. TC Energy uses historical credit loss and recovery data, adjusted for management's judgment regarding current economic and credit conditions, along with reasonable and supportable forecasts to determine any impairment, which is recognized in Plant operating costs and other.

The Company’s net investment in leases and certain contract assets are financial assets subject to ECL. TC Energy’s methodology for assessing the ECL regarding these financial assets includes consideration of the probability of default (the probability that the customer will default on its obligation), the loss given default (the economic loss as a proportion of the financial asset balance in the event of a default) and the exposure at default (the financial asset balance at the time of a hypothetical default) with one‑year forward-looking information that includes assumptions for future macroeconomic conditions under three probability‑weighted future scenarios.

The macroeconomic factors considered most relevant to the Company's net investment in leases and contract assets include Mexico's GDP, Mexico's government debt to GDP and Mexico's inflation. The ECL amount is updated at each reporting date to reflect changes in assumptions and forecasts for future economic conditions.

For the year ended December 31, 2025, the Company recorded an $84 million ECL expense (2024 – $23 million recovery; 2023 ‑ $73 million recovery) with respect to the net investment in leases associated with the in-service TGNH pipelines and $1 million ECL recovery (2024 – $1 million expense; 2023 – $10 million recovery) for contract assets related to certain other Mexico natural gas pipelines. At December 31, 2025, the balance of the ECL provision was $141 million (2024 – $59 million) with respect to the net investment in leases associated with in-service TGNH pipelines. The ECL provision is driven primarily by a probability of default measure for the counterparty, which is calculated using information published by an external third party.

Other than the ECL provision noted above, the Company had no significant credit losses at December 31, 2025 and 2024.
At December 31, 2025 and 2024, there were no significant credit risk concentrations and no significant amounts past due
or impaired.

TC Energy has significant credit and performance exposure to financial institutions that hold cash deposits and provide committed credit lines and letters of credit that help manage the Company's exposure to counterparties and provide liquidity in commodity, foreign exchange and interest rate derivative markets. TC Energy's portfolio of financial sector exposure consists primarily of highly-rated investment grade, systemically important financial institutions.

Non-Derivative Financial Instruments

Fair value of non-derivative financial instruments

Available-for-sale assets are recorded at fair value which is calculated using quoted market prices where available in addition to the Company's LMCI equity securities which are classified in Level I of the fair value hierarchy. Certain other non-derivative financial instruments included in Cash and cash equivalents, Accounts receivable, Other current assets, Net investment in leases, Restricted investments, Other long-term assets, Notes payable, Accounts payable and other, Dividends payable, Accrued interest and Other long-term liabilities have carrying amounts that approximate their fair value due to the nature of the item or the short time to maturity.

Credit risk has been taken into consideration when calculating the fair value of non-derivative financial instruments.

Balance sheet presentation of non-derivative financial instruments

The following table details the fair value of non-derivative financial instruments, excluding those where carrying amounts approximate fair value, and would be classified in Level II of the fair value hierarchy:


at December 31	2025		2024
	Carrying Amount	Fair Value	Carrying Amount	Fair Value
(millions of Canadian $)

Long-term debt, including current portion (Note 19)1,2	(46,792)	(47,720)	(47,931)	(48,318)
Junior subordinated notes (Note 20)	(12,094)	(12,061)	(11,048)	(10,824)
	(58,886)	(59,781)	(58,979)	(59,142)

1Long-term debt is recorded at amortized cost, except for $4.0 billion (2024 – $4.0 billion) that is attributed to hedged risk and recorded at fair value.

2Net income (loss) for 2025 included unrealized losses of $122 million (2024 – unrealized gains of $128 million) for fair value adjustments attributable to the hedged interest rate risk associated with interest rate swap fair value hedging.

The following tables summarize additional information about the Company's restricted investments that were classified as available-for-sale assets and equity securities with readily determinable fair values:


at December 31	2025		2024
	LMCI Restricted Investments	Other Restricted Investments1	LMCI Restricted Investments	Other Restricted Investments1
(millions of Canadian $)

Fair value of fixed income securities2,3
Maturing within 1 year	—	94	—	33
Maturing within 1-5 years	26	251	3	256
Maturing within 5-10 years	1,846	4	1,578	—
Maturing after 10 years	—	16	—	—
Fair value of equity securities2,4	1,252	94	1,070	64
	3,124	459	2,651	353

1Other restricted investments have been set aside to fund insurance claim losses to be paid by the Company's wholly-owned captive insurance subsidiary and, in 2025, funds have also been set aside to pay for certain active employee medical benefits.

2Available-for-sale assets and equity securities with readily determinable fair values are recorded at fair value and included in Other current assets and Restricted investments on the Company's Consolidated balance sheet.

3Classified in Level II of the fair value hierarchy.

4Classified in Level I of the fair value hierarchy.


year ended December 31	2025		2024		2023
(millions of Canadian $)	LMCI Restricted Investments1	Other Restricted Investments2	LMCI Restricted Investments1	Other Restricted Investments2	LMCI Restricted Investments1	Other Restricted Investments2

Net unrealized gains (losses)	167	(1)	218	9	179	13
Net realized gains (losses)3	21	22	3	2	(28)	—

1Unrealized and realized gains (losses) arising from changes in the fair value of LMCI restricted investments impact the subsequent amounts to be collected through tolls to cover future pipeline abandonment costs. As a result, the Company records these gains and losses as regulatory liabilities or regulatory assets.

2Unrealized and realized gains (losses) on other restricted investments are included in Interest income and other in the Company's Consolidated statement
of income.

3Realized gains (losses) on the sale of LMCI restricted investments are determined using the average cost basis.

Derivative Instruments

Fair value of derivative instruments

The fair value of foreign exchange and interest rate derivatives has been calculated using the income approach which uses year‑end market rates and applies a discounted cash flow valuation model. The fair value of commodity derivatives has been calculated using quoted market prices where available. In the absence of quoted market prices, third-party broker quotes or other valuation techniques have been used. The fair value of options has been calculated using the Black-Scholes pricing model. Credit risk has been taken into consideration when calculating the fair value of derivative instruments. Unrealized gains and losses on derivative instruments are not necessarily representative of the amounts that will be realized on settlement.

In some cases, even though the derivatives are considered to be effective economic hedges, they do not meet the specific criteria for hedge accounting treatment or are not designated as a hedge and are accounted for at fair value with changes in fair value recorded in net income in the period of change. This may expose the Company to increased variability in reported earnings because the fair value of the derivative instruments can fluctuate significantly from period to period.

The recognition of gains and losses on derivatives for Canadian natural gas regulated pipeline exposures is determined through the regulatory process. Gains and losses arising from changes in the fair value of derivatives accounted for as part of RRA, including those that qualify for hedge accounting treatment, are expected to be refunded or recovered through the tolls charged by the Company. As a result, these gains and losses are deferred as regulatory liabilities or regulatory assets and are refunded to or collected from the rate payers in subsequent years when the derivative settles.

Balance sheet presentation of derivative instruments

The balance sheet classification of the fair value of derivative instruments was as follows:


at December 31, 2025	Cash Flow Hedges	Fair Value Hedges	Held for Trading	Total Fair Value of Derivative Instruments1
(millions of Canadian $)

Other current assets (Note 7)
Commodities2	13	—	371	384
Foreign exchange	9	—	42	51
Interest rate	—	3	—	3
	22	3	413	438
Other long-term assets (Note 14)
Commodities2	2	—	122	124
Foreign exchange	—	—	15	15
Interest rate	—	22	—	22
	2	22	137	161
Total Derivative Assets	24	25	550	599

Accounts payable and other (Note 16)
Commodities2	(1)	—	(341)	(342)
Foreign exchange	—	—	(30)	(30)
Interest rate	—	(8)	—	(8)
	(1)	(8)	(371)	(380)
Other long-term liabilities (Note 17)
Commodities2	(1)	—	(61)	(62)
Foreign exchange	(51)	—	(2)	(53)
Interest rate	—	(34)	—	(34)
	(52)	(34)	(63)	(149)
Total Derivative Liabilities	(53)	(42)	(434)	(529)
Total Derivatives	(29)	(17)	116	70

1Fair value equals carrying value.

2Includes purchases and sales of power and natural gas.

The balance sheet classification of the fair value of derivative instruments was as follows:


at December 31, 2024	Cash Flow Hedges	Fair Value Hedges	Net Investment Hedges	Held for Trading	Total Fair Value of Derivative Instruments1
(millions of Canadian $)

Other current assets (Note 7)
Commodities2	18	—	—	287	305
Foreign exchange	—	—	—	42	42

	18	—	—	329	347
Other long-term assets (Note 14)
Commodities2	9	—	—	104	113
Foreign exchange	—	—	—	9	9

	9	—	—	113	122
Total Derivative Assets	27	—	—	442	469

Accounts payable and other (Note 16)
Commodities2	(1)	—	—	(291)	(292)
Foreign exchange	—	—	(11)	(183)	(194)
Interest rate	—	(21)	—	—	(21)
	(1)	(21)	(11)	(474)	(507)
Other long-term liabilities (Note 17)
Commodities2	(1)	—	—	(46)	(47)
Foreign exchange	—	—	—	(44)	(44)
Interest rate	—	(118)	—	—	(118)
	(1)	(118)	—	(90)	(209)
Total Derivative Liabilities	(2)	(139)	(11)	(564)	(716)
Total Derivatives	25	(139)	(11)	(122)	(247)

1Fair value equals carrying value.

2Includes purchases and sales of power and natural gas.

The majority of derivative instruments held for trading have been entered into for risk management purposes and all are subject to the Company's risk management strategies, policies and limits. These include derivatives that have not been designated as hedges or do not qualify for hedge accounting treatment but have been entered into as economic hedges to manage the Company's exposures to market risk.

Non-derivatives in fair value hedging relationships

The following table details amounts recorded on the Consolidated balance sheet in relation to cumulative adjustments for fair value hedges included in the carrying amount of the hedged liabilities:


at December 31	Carrying Amount		Fair Value Hedging Adjustments1
(millions of Canadian $)	2025	2024	2025	2024


Long-term debt	(4,068)	(3,935)	(22)	98

1At December 31, 2025, adjustments for discontinued hedging relationships included in this balance was a liability of $39 million (2024 – $41 million).

Notional and maturity summary

The maturity and notional amount or quantity outstanding related to the Company's derivative instruments excluding hedges of the net investment in foreign operations was as follows:


at December 31, 2025	Power	Natural Gas	Foreign Exchange	Interest Rate

Net sales (purchases)1	10,221	26	—	—
Millions of U.S. dollars	—	—	6,342	2,950
Millions of Mexican pesos	—	—	15,750	—
Maturity dates	2026-2044	2026-2032	2026-2030	2030-2034

1Volumes for power and natural gas derivatives are in GWh and Bcf, respectively.


at December 31, 2024	Power	Natural Gas	Foreign Exchange	Interest Rate

Net sales (purchases)1	10,192	53	—	—
Millions of U.S. dollars	—	—	5,648	2,800
Millions of Mexican pesos	—	—	16,750	—
Maturity dates	2025-2044	2025-2031	2025-2027	2030-2034

1Volumes for power and natural gas derivatives are in GWh and Bcf, respectively.

Unrealized and Realized Gains (Losses) on Derivative Instruments

The following summary does not include hedges of the net investment in foreign operations:


year ended December 31	2025	2024	2023
(millions of Canadian $)

Derivative Instruments Held for Trading1
Unrealized gains (losses) in the year
Commodities2	25	(71)	132
Foreign exchange (Note 21)	210	(266)	246
Interest rate	—	(71)	—
Realized gains (losses) in the year
Commodities	(10)	199	192
Foreign exchange (Note 21)	142	(152)	155
Interest rate	8	29	—
Derivative Instruments in Hedging Relationships
Realized gains (losses) in the year
Commodities	24	33	(2)
Foreign exchange	10	—	—
Interest rate	(30)	(52)	(43)

1Realized and unrealized gains (losses) on held-for-trading derivative instruments used to purchase and sell commodities are included on a net basis in Revenues in the Consolidated statement of income. Realized and unrealized gains (losses) on foreign exchange and interest rate held-for-trading derivative instruments are included on a net basis in Foreign exchange (gains) losses, net and Interest expense, respectively, in the Consolidated statement of income.

2In 2025, unrealized gains of $2 million were reclassified to Net Income (loss) from AOCI related to discontinued cash flow hedges (2024 – unrealized gains of $6 million; 2023 – nil).

Derivatives in cash flow hedging relationships

The components of OCI (Note 25) related to the change in fair value of derivatives in cash flow hedging relationships before tax were as follows:


year ended December 31	2025	2024	2023
(millions of Canadian $, pre-tax)

Gains (losses) in fair value of derivative instruments recognized in OCI1
Commodities	7	46	—
Foreign exchange	(38)	—	—

	(31)	46	—

1No amounts have been excluded from the assessment of hedge effectiveness.

Effect of fair value and cash flow hedging relationships

The following table details amounts presented in the Consolidated statement of income in which the effects of fair value or cash flow hedging relationships were recorded:


year ended December 31	2025	2024	2023
(millions of Canadian $)

Fair Value Hedges
Interest rate contracts1
Hedged items	(179)	(126)	(98)
Derivatives designated as hedging instruments	(30)	(52)	(43)
Cash Flow Hedges
Reclassification of gains (losses) on derivative instruments from AOCI to Net income (loss)2,3
Commodities4	19	32	(85)
Foreign exchange5	(50)	—	—
Interest rate1	(12)	(12)	(12)

1Presented within Interest expense in the Consolidated statement of income.

2Refer to Note 25, Other comprehensive income (loss) and accumulated other comprehensive income (loss), for the components of OCI related to derivatives in cash flow hedging relationships.

3There are no amounts recognized in earnings that were excluded from effectiveness testing.

4Presented within Revenues (Power and Energy Solutions) in the Consolidated statement of income. In 2025, unrealized gains of $2 million were reclassified to Net Income (loss) from AOCI related to discontinued cash flow hedges (2024 - unrealized gains of $6 million; 2023 – nil).

5Presented within Interest expense and Foreign exchange (gains) losses, net in the Consolidated statement of income.

Offsetting of derivative instruments

The Company enters into derivative contracts with the right to offset in the normal course of business as well as in the event of default. TC Energy has no master netting agreements; however, similar contracts are entered into containing rights to offset. The Company has elected to present the fair value of derivative instruments with the right to offset on a gross basis on the Consolidated balance sheet.

The following tables show the impact on the presentation of the fair value of derivative instrument assets and liabilities had the Company elected to present these contracts on a net basis:


at December 31, 2025	Gross Derivative Instruments	Amounts Available for Offset1	Net Amounts
(millions of Canadian $)

Derivative Instrument Assets
Commodities	508	(367)	141
Foreign exchange	66	(48)	18
Interest rate	25	(5)	20
	599	(420)	179
Derivative Instrument Liabilities
Commodities	(404)	367	(37)
Foreign exchange	(83)	48	(35)
Interest rate	(42)	5	(37)
	(529)	420	(109)

1Amounts available for offset do not include cash collateral pledged or received.


at December 31, 2024	Gross Derivative Instruments	Amounts Available for Offset1	Net Amounts
(millions of Canadian $)

Derivative Instrument Assets
Commodities	418	(290)	128
Foreign exchange	51	(49)	2

	469	(339)	130
Derivative Instrument Liabilities
Commodities	(339)	290	(49)
Foreign exchange	(238)	49	(189)
Interest rate	(139)	—	(139)
	(716)	339	(377)

1Amounts available for offset do not include cash collateral pledged or received.

With respect to the derivative instruments presented above, the Company provided cash collateral of $93 million and letters of credit of $73 million at December 31, 2025 (2024 – $133 million and $59 million, respectively) to its counterparties. At December 31, 2025, the Company held less than $1 million in cash collateral and $102 million in letters of credit (2024 – less than $1 million and $75 million, respectively) from counterparties on asset exposures.

Credit-risk-related contingent features of derivative instruments

Derivative contracts entered into to manage market risk often contain financial assurance provisions that allow parties to the contracts to manage credit risk. These provisions may require collateral to be provided if a credit-risk-related contingent event occurs, such as a downgrade in the Company's credit rating to non-investment grade. The Company may also need to provide collateral if the fair value of its derivative financial instruments exceeds pre-defined exposure limits.

Based on contracts in place and market prices at December 31, 2025, the aggregate fair value of all derivative instruments with credit-risk-related contingent features that were in a net liability position was $5 million (2024 – net liability of $10 million), for which the Company has provided no collateral in the normal course of business. If the credit-risk-related contingent features in these agreements were triggered on December 31, 2025, the Company would have been required to provide collateral equal to the fair value of the related derivative instruments discussed above. Collateral may also need to be provided should the fair value of derivative instruments exceed pre-defined contractual exposure limit thresholds. The Company has sufficient liquidity in the form of cash and undrawn committed revolving credit facilities to meet these contingent obligations should they arise.

Fair Value Hierarchy

The Company's financial assets and liabilities recorded at fair value have been categorized into three categories based on a fair value hierarchy.


Levels			How Fair Value Has Been Determined

Level I			Quoted prices in active markets for identical assets and liabilities that the Company has the ability to access at the measurement date. An active market is a market in which frequency and volume of transactions provides pricing information on an ongoing basis.

Level II			This category includes interest rate and foreign exchange derivative assets and liabilities where fair value is determined using the income approach and commodity derivatives where fair value is determined using the market approach. Inputs include published exchange rates, interest rates, interest rate swap curves, yield curves and broker quotes from external data service providers.

Level III			This category includes long-dated commodity transactions in certain markets where liquidity is low. The Company uses the most observable inputs available or alternatively long-term broker quotes or negotiated commodity prices that have been contracted for under similar terms in determining an appropriate estimate of these transactions. Where appropriate, these long-dated prices are discounted to reflect the expected pricing from the applicable markets. There is uncertainty caused by using unobservable market data which may not accurately reflect possible future changes in fair value.

The fair value of the Company's derivative assets and liabilities measured on a recurring basis, including both current and non‑current portions, were categorized as follows:


at December 31, 2025	Quoted Prices in Active Markets (Level I)	Significant Other Observable Inputs (Level II)1	Significant Unobservable Inputs (Level III)1	Total
(millions of Canadian $)

Derivative Instrument Assets
Commodities	154	279	75	508
Foreign exchange	—	66	—	66
Interest rate	—	25	—	25
Derivative Instrument Liabilities
Commodities	(151)	(252)	(1)	(404)
Foreign exchange	—	(83)	—	(83)
Interest rate	—	(42)	—	(42)
	3	(7)	74	70

1There were no transfers from Level II to Level III for the year ended December 31, 2025.

The Company has entered into contracts, which commenced in 2025 and with terms ranging from 15 to 20 years, to sell 50 MW of power provided from specified renewable sources in the Province of Alberta. The fair value of these contracts is classified in Level III of the fair value hierarchy and is based on the assumption that the contract volumes will be sourced approximately 80 per cent from wind generation, 10 per cent from solar generation and 10 per cent from the market.


at December 31, 2024	Quoted Prices in Active Markets (Level I)	Significant Other Observable Inputs (Level II)1	Significant Unobservable Inputs (Level III)1	Total
(millions of Canadian $)

Derivative Instrument Assets
Commodities	126	214	78	418
Foreign exchange	—	51	—	51

Derivative Instrument Liabilities
Commodities	(116)	(217)	(6)	(339)
Foreign exchange	—	(238)	—	(238)
Interest rate	—	(139)	—	(139)
	10	(329)	72	(247)

1There were no transfers from Level II to Level III for the year ended December 31, 2024.

The following table presents the net change in fair value of derivative assets and liabilities classified in Level III of the fair
value hierarchy:


(millions of Canadian $, pre-tax)	2025	2024

Balance at beginning of year	72	(11)
Net gains (losses) included in Net income (loss)	21	54

Transfers to Level II	(4)	29
Purchases	(1)	—
Settlements	(14)	—
Balance at End of Year1	74	72

1Revenues include unrealized gains of $21 million attributed to derivatives in the Level III category that were still held at December 31, 2025 (2024 – unrealized gains of $54 million).

REVENUES

12 Months Ended

Dec. 31, 2025

Revenue from Contract with Customer [Abstract]

REVENUES

Disaggregation of Revenues


year ended December 31, 2025	Canadian Natural Gas Pipelines	U.S. Natural Gas Pipelines	Mexico Natural Gas Pipelines	Power and Energy Solutions	Total
(millions of Canadian $)

Revenues from contracts with customers
Capacity arrangements and transportation	5,785	5,698	445	—	11,928
Power generation	—	—	—	236	236
Natural gas storage and other1	—	1,141	218	440	1,799
	5,785	6,839	663	676	13,963
Sales-type lease income2	—	—	787	—	787
Other revenues3	—	306	—	169	475
	5,785	7,145	1,450	845	15,225
Corporate revenues4					14
					15,239

1The Mexico Natural Gas Pipelines segment includes $192 million of revenues generated from non-lease components for the provision of operating and maintenance services with respect to sales-type leases on the in-service Transportadora de Gas Natural de La Huasteca (TGNH) pipelines. Refer to Note 9, Leases, for additional information.

2Represents the sales-type lease income on the in-service TGNH pipelines. Refer to Note 9, Leases, for additional information.

3Includes income from the Company's marketing activities, financial instruments and operating lease income. Refer to Note 9, Leases, and Note 27, Risk management and financial instruments, for additional information.

4Revenues generated from the Transition Services Agreement with South Bow. Refer to Note 4, Discontinued operations, for additional information.


year ended December 31, 2024	Canadian Natural Gas Pipelines	U.S. Natural Gas Pipelines	Mexico Natural Gas Pipelines	Power and Energy Solutions	Total
(millions of Canadian $)

Revenues from contracts with customers
Capacity arrangements and transportation	5,586	5,382	438	—	11,406
Power generation	—	—	—	266	266
Natural gas storage and other1,2	14	869	124	383	1,390
	5,600	6,251	562	649	13,062
Sales-type lease income3	—	—	308	—	308
Other revenues4	—	88	—	305	393
	5,600	6,339	870	954	13,763
Corporate revenues5					8
					13,771

1The Canadian Natural Gas Pipelines segment includes $14 million of fee revenues from an affiliate related to the development and construction of the Coastal GasLink pipeline project, which is 35 per cent owned by TC Energy.

2The Mexico Natural Gas Pipelines segment includes $98 million of revenues generated from non-lease components for the provision of operating and maintenance services with respect to sales-type leases on the in-service TGNH pipelines. Refer to Note 9, Leases, for additional information.

3Represents the sales-type lease income on the in-service TGNH pipelines. Refer to Note 9, Leases, for additional information.

4Includes income from the Company's marketing activities, financial instruments and operating lease income. Refer to Note 9, Leases, and Note 27, Risk management and financial instruments, for additional information.

5 Includes $7 million of revenues generated from the Transition Services Agreement with South Bow. Refer to Note 4, Discontinued operations, for additional information.


year ended December 31, 2023	Canadian Natural Gas Pipelines	U.S. Natural Gas Pipelines	Mexico Natural Gas Pipelines	Power and Energy Solutions	Total
(millions of Canadian $)

Revenues from contracts with customers
Capacity arrangements and transportation	5,141	5,107	442	—	10,690
Power generation	—	—	—	427	427
Natural gas storage and other1,2	32	874	125	363	1,394
	5,173	5,981	567	790	12,511
Sales-type lease income3	—	—	279	—	279
Other revenues4	—	248	—	229	477
	5,173	6,229	846	1,019	13,267

1The Canadian Natural Gas Pipelines segment includes $31 million of fee revenues from an affiliate related to the development and construction of the Coastal GasLink pipeline project which is 35 per cent owned by TC Energy.

2The Mexico Natural Gas Pipelines segment includes $97 million of revenues generated from non-lease components for the provision of operating and maintenance services with respect to sales-type leases on the in-service TGNH pipelines. Refer to Note 9, Leases, for additional information.

3Represents the sales-type lease income on the in-service TGNH pipelines. Refer to Note 9, Leases, for additional information.

Contract Balances


at December 31	2025	2024	Affected line item on the Consolidated balance sheet
(millions of Canadian $)

Receivables from contracts with customers	1,822	1,452	Accounts receivable
Contract assets (Note 7)	216	165	Other current assets
Long-term contract assets (Note 14)	627	608	Other long-term assets
Contract liabilities1 (Note 16)	46	30	Accounts payable and other

1During the year ended December 31, 2025, $21 million (2024 – $41 million) of revenues were recognized, which were included in contract liabilities and long-term contract liabilities at the beginning of the year.

Contract assets and long-term contract assets primarily relate to the Company’s right to revenues for services completed but not invoiced at the reporting date on long-term committed capacity natural gas pipelines contracts. The change in contract assets is primarily related to the transfer to Accounts receivable when these rights become unconditional and the customer is invoiced, as well as the recognition of additional revenues that remain to be invoiced. Contract liabilities primarily represent unearned revenue for contracted services.

Future Revenues from Remaining Performance Obligations

As at December 31, 2025, future revenues from long-term pipeline capacity arrangements and transportation as well as natural gas storage and other contracts extending through 2055 are approximately $33.8 billion, of which approximately $7.0 billion is expected to be recognized in 2026.

A significant portion of the Company's revenues are not included in the future revenue disclosure above, as the Company has elected the following disclosure exemptions:

•revenues related to flow-through operating costs, or other similar variable consideration, that are recognized at the amount for which the Company has the right to invoice the customer

•variable consideration relating to interruptible transportation service revenues and power generation revenues where there is uncertainty in estimating the amount of future revenue

•revenues for periods extending beyond the current rate settlement term for the Company’s U.S. natural gas pipelines' regulated transportation and storage contracts where the maximum tariff rate is to be collected from shippers

•revenues for periods extending beyond the current rate settlement term for the Company's Canadian natural gas pipelines' regulated firm capacity contracts

•revenues related to assets under construction, which are recognized when the asset is placed in service.

- Definition

The entire disclosure of revenue from contract with customer to transfer good or service and to transfer nonfinancial asset. Includes, but is not limited to, disaggregation of revenue, credit loss recognized from contract with customer, judgment and change in judgment related to contract with customer, and asset recognized from cost incurred to obtain or fulfill contract with customer. Excludes insurance and lease contracts.

+ References

Reference 1: http://www.xbrl.org/2003/role/disclosureRef
-Topic 606
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 7
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147479806/606-10-50-7

Reference 2: http://www.xbrl.org/2003/role/disclosureRef
-Topic 606
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 9
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147479806/606-10-50-9

Reference 3: http://www.xbrl.org/2003/role/disclosureRef
-Topic 606
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 10
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147479806/606-10-50-10

Reference 4: http://www.xbrl.org/2003/role/disclosureRef
-Topic 606
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 15
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147479806/606-10-50-15

Reference 5: http://www.xbrl.org/2003/role/disclosureRef
-Topic 606
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 12
-Subparagraph (a)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147479806/606-10-50-12

Reference 6: http://www.xbrl.org/2003/role/disclosureRef
-Topic 606
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 12
-Subparagraph (b)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147479806/606-10-50-12

Reference 7: http://www.xbrl.org/2003/role/disclosureRef
-Topic 606
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 12
-Subparagraph (c)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147479806/606-10-50-12

Reference 8: http://www.xbrl.org/2003/role/disclosureRef
-Topic 606
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 12
-Subparagraph (d)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147479806/606-10-50-12

Reference 9: http://www.xbrl.org/2003/role/disclosureRef
-Topic 606
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 12
-Subparagraph (e)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147479806/606-10-50-12

Reference 10: http://www.xbrl.org/2003/role/disclosureRef
-Topic 606
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 13
-Subparagraph (b)(2)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147479806/606-10-50-13

Reference 11: http://www.xbrl.org/2003/role/disclosureRef
-Name Accounting Standards Codification
-Topic 606
-Publisher FASB
-URI https://asc.fasb.org/606/tableOfContent

+ Details

LEASES

12 Months Ended

Dec. 31, 2025

Leases [Abstract]

LEASES

As a Lessee

The Company has operating leases for corporate offices, other various premises, equipment and land. Some leases have an option to renew for periods of one to 25 years, and some may include options to terminate the lease within one year or when certain conditions are met. Payments due under lease contracts include fixed payments plus, for many of the Company's leases, variable payments such as a proportionate share of the buildings' property taxes, insurance and common area maintenance. The Company subleases some of the leased premises.

Operating lease cost was as follows:


year ended December 31
(millions of Canadian $)	2025	2024

Operating lease cost1	112	117
Sublease income	(5)	(6)
Net operating lease cost	107	111

1 Includes short-term leases and variable lease costs.

Other information related to operating leases is noted in the following tables:


year ended December 31
(millions of Canadian $)	2025	2024

Cash paid for amounts included in the measurement of operating lease liabilities	76	74
ROU assets obtained in exchange for new operating lease liabilities	18	96


at December 31	2025		2024

Weighted average remaining lease term	11 years		13 years
Weighted average discount rate	3.4	%	3.3	%

Maturities of operating lease liabilities are as follows:


at December 31
(millions of Canadian $)	2025	2024

Less than one year	73	73
One to two years	66	73
Two to three years	63	66
Three to four years	63	64
Four to five years	59	63
More than five years	185	275
Total operating lease payments	509	614
Imputed interest	(78)	(103)
Operating lease liabilities	431	511

The amounts recognized on TC Energy's Consolidated balance sheet for its operating lease liabilities were as follows:


at December 31
(millions of Canadian $)	2025	2024

Accounts payable and other (Note 16)	61	60
Other long-term liabilities (Note 17)	370	451
	431	511

As at December 31, 2025, the carrying value of the ROU assets recorded under operating leases was $402 million (2024 – $480 million) and is included in Plant, property and equipment on the Consolidated balance sheet.

As a Lessor

Operating Leases

The Grandview and Bécancour power plants in the Power and Energy Solutions segment are accounted for as operating leases. The Company has long-term PPAs for the sale of power from these assets which expire between 2026 and 2035.

Some operating leases contain variable lease payments that are based on operating hours and the reimbursement of variable costs, and options to purchase the underlying asset at fair value or based on a formula considering the remaining fixed payments. Lessees have rights under some leases to terminate under certain circumstances.

The fixed portion of the operating lease income recorded by the Company for the year ended December 31, 2025 was $109 million (2024 – $114 million; 2023 – $112 million).

Future lease payments to be received under operating leases are as follows:


at December 31
(millions of Canadian $)	2025	2024

Less than one year	80	107
One to two years	9	76
Two to three years	10	9
Three to four years	10	10
Four to five years	10	10
More than five years	45	55
	164	267

At December 31, 2025, the cost and accumulated depreciation for facilities accounted for as operating leases was $697 million and $371 million, respectively (2024 – $697 million and $351 million, respectively).

Sales-Type Leases

The Tamazunchale, Villa de Reyes, Tula and Southeast Gateway pipelines are part of a U.S. dollar-denominated take-or-pay Transportation Service Agreement (TSA) that extends through 2055 between TGNH and the Comisión Federal de Electricidad (CFE).

The consolidated TSA contains multiple lease and non-lease components. The lease components within the TSA represent the capacity available to the CFE provided by the in-service pipelines within TGNH at December 31, 2025. The non-lease components represent the Company’s services with respect to operation and maintenance of the TGNH pipelines in service. The Company allocated a portion of the contract consideration to non-lease components for the provision of operating and maintenance services based on the stand-alone selling price using an expected cost plus margin approach. The remaining consideration was allocated to the lease components using the residual approach due to uncertainty surrounding the stand-alone selling price.

Transportadora de Gas Natural de la Huasteca

In September 2025, TC Energy entered into a factoring arrangement with the CFE and a major domestic bank in Mexico to factor monthly invoices for services provided on the TGNH system in 2025. Invoices for August to October were factored to the bank without recourse to TC Energy and TC Energy continued to receive invoiced amounts within the contractual payment period.

The factoring arrangement resulted in a lease modification for accounting purposes of the existing TGNH TSA with the CFE, with no change to the lease classification upon reassessment. As such, the Company reallocated contract consideration to the lease and non-lease components of the contract using an expected cost plus margin approach based on the updated operating and maintenance services stand-alone selling price for each non-lease component as of the date of modification. The residual amount of consideration from this process was then allocated to the lease component. The change in allocation was accounted for prospectively. The rate implicit in the lease was adjusted to the rate at which the modified net investment in lease equaled the carrying value of the net investment in lease directly prior to the effective date of the modification.

Under lease accounting, TC Energy recorded factored amounts in Accounts payable and other, and the corresponding receivables were not derecognized on the Consolidated balance sheet. Cash received from the factoring arrangement were included in Financing activities in the Consolidated statement of cash flows. During 2025, TC Energy assigned and received payment for receivables having an aggregate face value of $351 million (US$251 million).

Southeast Gateway Pipeline

During second quarter 2025, the Company announced the completion of the Southeast Gateway pipeline. The Company determined that the pipeline is a sales-type lease between TGNH and the CFE that commenced when the asset was made available to the customer. At the inception of the agreement in 2022 and as revised in third quarter 2025 when the Company entered into a factoring arrangement with the CFE, the Company allocated the expected contract consideration to the non-lease component for the provisioning of operating and maintenance services based on the estimated stand-alone selling price using an expected cost plus margin approach. The residual amount of consideration from this process was then allocated to the lease component. The Company’s estimate of future operating costs influenced the allocation of contract consideration between lease and non-lease components, the timing of income recognized under the contract and the calculation of the rate implicit in the lease.

The TGNH pipelines, which includes the Southeast Gateway pipeline, are rate-regulated and the tolls are designed to recover the cost of providing service. On this basis, the Company applied judgment to determine that, at the inception of the lease arrangement, the fair value of the underlying assets approximated the carrying value and the residual value approximated the remaining carrying value at the end of the lease term. The fair value was a non-recurring measurement classified in Level III of the fair value hierarchy. The Company estimated that if the assets were purchased at their carrying value, they would yield a return to the purchaser that is in line with current market participant expectations.

During 2025, the Company recorded a net investment in lease of $6.6 billion (US$4.8 billion) associated with the Southeast Gateway pipeline lease commencement, with no selling profit or losses recorded upon derecognition of the underlying asset. The Company recorded an expected credit loss provision of $113 million in Plant operating costs and other, relating to the initial net investment in lease balance.

Future lease payments to be received under the existing sales-type leases are as follows:


at December 31
(millions of Canadian $)	2025	2024

Less than one year	1,256	333
One to two years	1,000	333
Two to three years	1,000	333
Three to four years	1,000	333
Four to five years	1,000	333
More than five years	24,508	8,499
	29,764	10,164

The following table lists the components of the aggregate net investment in leases reflected on the Company's Consolidated balance sheet:


at December 31
(millions of Canadian $)	2025	2024

Net Investment in Leases
Minimum lease payments	29,764	10,164
Unearned lease income	(20,397)	(7,323)
Lease receivable	9,367	2,841
Expected credit loss provision1	(141)	(59)
Present value of unguaranteed residual value	140	28
	9,366	2,810
Current portion included in Other current assets (Note 7)	(1,256)	(333)
	8,110	2,477

1Includes $2 million gain (2024 – $6 million loss) on foreign currency translation.

For the year ended December 31, 2025, the Company recorded $787 million (2024 – $308 million; 2023 - $279 million) of sales-type lease income.

For the year ended December 31, 2025, the Company recorded an $84 million ECL expense (2024 – $23 million recovery; 2023 – $73 million recovery) relating to net investment in leases in Plant operating costs and other. Refer to Note 27, Risk management and financial instruments, for additional information.

LEASES

As a Lessee

Operating lease cost was as follows:


year ended December 31
(millions of Canadian $)	2025	2024

Operating lease cost1	112	117
Sublease income	(5)	(6)
Net operating lease cost	107	111

1 Includes short-term leases and variable lease costs.

Other information related to operating leases is noted in the following tables:


year ended December 31
(millions of Canadian $)	2025	2024

Cash paid for amounts included in the measurement of operating lease liabilities	76	74
ROU assets obtained in exchange for new operating lease liabilities	18	96


at December 31	2025		2024

Weighted average remaining lease term	11 years		13 years
Weighted average discount rate	3.4	%	3.3	%

Maturities of operating lease liabilities are as follows:


at December 31
(millions of Canadian $)	2025	2024

Less than one year	73	73
One to two years	66	73
Two to three years	63	66
Three to four years	63	64
Four to five years	59	63
More than five years	185	275
Total operating lease payments	509	614
Imputed interest	(78)	(103)
Operating lease liabilities	431	511

The amounts recognized on TC Energy's Consolidated balance sheet for its operating lease liabilities were as follows:


at December 31
(millions of Canadian $)	2025	2024

Accounts payable and other (Note 16)	61	60
Other long-term liabilities (Note 17)	370	451
	431	511

As a Lessor

Operating Leases

The fixed portion of the operating lease income recorded by the Company for the year ended December 31, 2025 was $109 million (2024 – $114 million; 2023 – $112 million).

Future lease payments to be received under operating leases are as follows:


at December 31
(millions of Canadian $)	2025	2024

Less than one year	80	107
One to two years	9	76
Two to three years	10	9
Three to four years	10	10
Four to five years	10	10
More than five years	45	55
	164	267

Sales-Type Leases

Transportadora de Gas Natural de la Huasteca

Southeast Gateway Pipeline

Future lease payments to be received under the existing sales-type leases are as follows:


at December 31
(millions of Canadian $)	2025	2024

Less than one year	1,256	333
One to two years	1,000	333
Two to three years	1,000	333
Three to four years	1,000	333
Four to five years	1,000	333
More than five years	24,508	8,499
	29,764	10,164

The following table lists the components of the aggregate net investment in leases reflected on the Company's Consolidated balance sheet:


at December 31
(millions of Canadian $)	2025	2024

Net Investment in Leases
Minimum lease payments	29,764	10,164
Unearned lease income	(20,397)	(7,323)
Lease receivable	9,367	2,841
Expected credit loss provision1	(141)	(59)
Present value of unguaranteed residual value	140	28
	9,366	2,810
Current portion included in Other current assets (Note 7)	(1,256)	(333)
	8,110	2,477

1Includes $2 million gain (2024 – $6 million loss) on foreign currency translation.

For the year ended December 31, 2025, the Company recorded $787 million (2024 – $308 million; 2023 - $279 million) of sales-type lease income.

LEASES

As a Lessee

Operating lease cost was as follows:


year ended December 31
(millions of Canadian $)	2025	2024

Operating lease cost1	112	117
Sublease income	(5)	(6)
Net operating lease cost	107	111

1 Includes short-term leases and variable lease costs.

Other information related to operating leases is noted in the following tables:


year ended December 31
(millions of Canadian $)	2025	2024

Cash paid for amounts included in the measurement of operating lease liabilities	76	74
ROU assets obtained in exchange for new operating lease liabilities	18	96


at December 31	2025		2024

Weighted average remaining lease term	11 years		13 years
Weighted average discount rate	3.4	%	3.3	%

Maturities of operating lease liabilities are as follows:


at December 31
(millions of Canadian $)	2025	2024

Less than one year	73	73
One to two years	66	73
Two to three years	63	66
Three to four years	63	64
Four to five years	59	63
More than five years	185	275
Total operating lease payments	509	614
Imputed interest	(78)	(103)
Operating lease liabilities	431	511

The amounts recognized on TC Energy's Consolidated balance sheet for its operating lease liabilities were as follows:


at December 31
(millions of Canadian $)	2025	2024

Accounts payable and other (Note 16)	61	60
Other long-term liabilities (Note 17)	370	451
	431	511

As a Lessor

Operating Leases

The fixed portion of the operating lease income recorded by the Company for the year ended December 31, 2025 was $109 million (2024 – $114 million; 2023 – $112 million).

Future lease payments to be received under operating leases are as follows:


at December 31
(millions of Canadian $)	2025	2024

Less than one year	80	107
One to two years	9	76
Two to three years	10	9
Three to four years	10	10
Four to five years	10	10
More than five years	45	55
	164	267

Sales-Type Leases

Transportadora de Gas Natural de la Huasteca

Southeast Gateway Pipeline

Future lease payments to be received under the existing sales-type leases are as follows:


at December 31
(millions of Canadian $)	2025	2024

Less than one year	1,256	333
One to two years	1,000	333
Two to three years	1,000	333
Three to four years	1,000	333
Four to five years	1,000	333
More than five years	24,508	8,499
	29,764	10,164

The following table lists the components of the aggregate net investment in leases reflected on the Company's Consolidated balance sheet:


at December 31
(millions of Canadian $)	2025	2024

Net Investment in Leases
Minimum lease payments	29,764	10,164
Unearned lease income	(20,397)	(7,323)
Lease receivable	9,367	2,841
Expected credit loss provision1	(141)	(59)
Present value of unguaranteed residual value	140	28
	9,366	2,810
Current portion included in Other current assets (Note 7)	(1,256)	(333)
	8,110	2,477

1Includes $2 million gain (2024 – $6 million loss) on foreign currency translation.

For the year ended December 31, 2025, the Company recorded $787 million (2024 – $308 million; 2023 - $279 million) of sales-type lease income.

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - Unrealized and Realized (Losses) / Gains on Derivative Instruments (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Derivative [Line Items]
Gain (loss) on cash flow hedge	$ 2	$ 6	$ 0
Commodities
Derivative [Line Items]
Amount of unrealized (losses) / gains in the year	25	(71)	132
Realized gains (losses) in the year	(10)	199	192
Commodities \| Derivative instruments in hedging relationships
Derivative [Line Items]
Realized gains (losses) in the year	24	33	(2)
Foreign exchange
Derivative [Line Items]
Amount of unrealized (losses) / gains in the year	210	(266)	246
Realized gains (losses) in the year	142	(152)	155
Foreign exchange \| Derivative instruments in hedging relationships
Derivative [Line Items]
Realized gains (losses) in the year	10	0	0
Interest rate
Derivative [Line Items]
Amount of unrealized (losses) / gains in the year	0	(71)	0
Realized gains (losses) in the year	8	29	0
Interest rate \| Derivative instruments in hedging relationships
Derivative [Line Items]
Realized gains (losses) in the year	$ (30)	$ (52)	$ (43)

NON-CONTROLLING INTERESTS

12 Months Ended

Dec. 31, 2025

Noncontrolling Interest [Abstract]

NON-CONTROLLING INTERESTS

The Company's Net income (loss) attributable to non-controlling interests included in the Consolidated statement of income and Non-controlling interests included on the Consolidated balance sheet were as follows:


(millions of Canadian $)	Non-Controlling Interests Ownership at December 31, 2025			Income (Loss) Attributable to Non-Controlling Interests			Non-Controlling Interests
				year ended December 31			at December 31
				2025	2024	2023	2025	2024

Columbia Gas and Columbia Gulf	40	%	1	631	571	143	8,779	9,844
Portland Natural Gas Transmission System	nil		1	—	30	41	—	—
Texas Wind Farms	100	%	1,2	(38)	(29)	(38)	123	168
TGNH	13.01	%	1	(18)	109	—	702	756
				575	681	146	9,604	10,768

1 Refer to Note 29, Acquisitions and dispositions, for additional information.

2 Tax equity investors own 100 per cent of the Class A Membership Interests, to which a percentage of earnings, tax attributes and cash flows are allocated. TC Energy owns 100 per cent of the Class B Membership Interests.

OTHER CURRENT ASSETS (Details) - CAD ($) $ in Millions	Dec. 31, 2025	Dec. 31, 2024
Other Assets [Abstract]
Net investment in leases (Note 9)	$ 1,256	$ 333
Fair value of derivative instruments (Note 27)	438	347
Contract assets (Note 6)	216	165
Cash provided as collateral	93	128
Prepaid expenses	82	86
Emissions credits	67	75
Regulatory assets (Note 12)	58	123
Other	165	82
Other current assets	$ 2,375	$ 1,339

OTHER LONG-TERM LIABILITIES

12 Months Ended

Dec. 31, 2025

Deferred Costs, Noncurrent [Abstract]

OTHER LONG-TERM LIABILITIES


at December 31	2025	2024
(millions of Canadian $)

Operating lease liabilities (Note 9)	370	451
Fair value of derivative instruments (Note 27)	149	209
Asset retirement obligations	119	108
Loan from affiliate (Note 11)	111	—
Employee post-retirement benefits (Note 26)	69	94

Other	216	189
	1,034	1,051

OTHER COMPREHENSIVE INCOME(LOSS) AND ACCUMULATED OTHER COMPREHENSIVE INCOME(LOSS) - Components (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Before Tax Amount
Other Comprehensive Income (Loss)	$ (851)	$ 1,891	$ (1,326)
Income Tax (Expense) Recovery
Other Comprehensive Income (Loss)	(36)	(63)	54
Net of Tax Amount
Other comprehensive income (loss) (Note 25)	(887)	1,828	(1,272)
Foreign currency translation gains and losses on net investment in foreign operations
Before Tax Amount
Other comprehensive income (loss), before reclassifications	(970)	1,582	(1,148)
Income Tax (Expense) Recovery
Other comprehensive income (loss) before reclassifications	(8)	20	7
Net of Tax Amount
Other comprehensive income/(loss), before reclassifications	(978)	1,602	(1,141)
Reclassification of foreign currency translation (gains) losses on net investment on disposal of foreign operations
Before Tax Amount
Other comprehensive income (loss), before reclassifications		(25)
Income Tax (Expense) Recovery
Other comprehensive income (loss) before reclassifications		0
Net of Tax Amount
Other comprehensive income/(loss), before reclassifications		(25)
Change in fair value of net investment hedges
Before Tax Amount
Other comprehensive income (loss), before reclassifications	1	(23)	23
Income Tax (Expense) Recovery
Other comprehensive income (loss) before reclassifications	0	5	(6)
Net of Tax Amount
Other comprehensive income/(loss), before reclassifications	1	(18)	17
Cash Flow Hedges
Before Tax Amount
Other comprehensive income (loss), before reclassifications	(31)	46
Reclassification from accumulated other comprehensive Income (loss)	43	(20)	97
Income Tax (Expense) Recovery
Other comprehensive income (loss) before reclassifications	9	(11)
Reclassification from AOCI	(12)	4	(23)
Net of Tax Amount
Other comprehensive income/(loss), before reclassifications	(22)	35
Reclassification from accumulated other comprehensive income (loss)	31	(16)	74
Unrealized actuarial gains and losses and reclassification of actuarial gains and losses of pension and other post-retirement benefits
Before Tax Amount
Other comprehensive income (loss), before reclassifications	104	107	(15)
Reclassification from accumulated other comprehensive Income (loss)		(6)
Income Tax (Expense) Recovery
Other comprehensive income (loss) before reclassifications	(25)	(24)	4
Reclassification from AOCI		0
Net of Tax Amount
Other comprehensive income/(loss), before reclassifications	79	83	(11)
Reclassification from accumulated other comprehensive income (loss)		(6)
Other comprehensive income (loss) on equity investments
Before Tax Amount
Other Comprehensive Income (Loss)	2	230	(283)
Income Tax (Expense) Recovery
Other Comprehensive Income (Loss)	0	(57)	72
Net of Tax Amount
Other comprehensive income (loss) (Note 25)	$ 2	$ 173	$ (211)

COMMON SHARES - Dividend Reinvestment and Share Purchase Plan (Details)	1 Months Ended	31 Months Ended
	Aug. 31, 2022	Jul. 31, 2023
Common Stock, Number of Shares, Par Value and Other Disclosure [Abstract]
Discount of shares issued from treasury	2.00%
Price of shares issued from treasury		100.00%

LEASES - Sales-Type Leases (Details) - CAD ($) $ in Millions	Dec. 31, 2025	Dec. 31, 2024
Leases [Abstract]
Less than one year	$ 1,256	$ 333
One to two years	1,000	333
Two to three years	1,000	333
Three to four years	1,000	333
Four to five years	1,000	333
More than five years	24,508	8,499
Payments to be received	$ 29,764	$ 10,164

PREFERRED SHARES - Narrative (Details) $ in Millions					12 Months Ended
PREFERRED SHARES - Narrative (Details) $ in Millions	Nov. 28, 2025 $ / shares shares	Jun. 30, 2025 shares	Dec. 31, 2024 $ / shares shares	Oct. 31, 2024 shares	Dec. 31, 2025 $ / shares	Oct. 31, 2025 USD ($)
Junior Subordinated Notes Due October 2025 \| Junior subordinated notes \| TransCanada Trust
Class of Stock [Line Items]
Amount \| $						$ 370
Series 2, Series 4, Series 6 and Series 10 Preferred Stock
Class of Stock [Line Items]
Redemption price per share (in Canadian dollars per share)			$ 25.50
Series 11
Class of Stock [Line Items]
Redemption price per share (in Canadian dollars per share)	$ 25.00				$ 0
Stock redeemed during period (in shares) \| shares	10,000,000
Annual dividend ( in Canadian dollars per share)	$ 0.2094375				0
Series 3
Class of Stock [Line Items]
Redemption price per share (in Canadian dollars per share)					25.00
Annual dividend ( in Canadian dollars per share)					1.0255
Shares converted (in shares) \| shares		104,778
Conversion ratio		1
Series 4
Class of Stock [Line Items]
Redemption price per share (in Canadian dollars per share)					25.00
Shares converted (in shares) \| shares		1,822,829
Conversion ratio		1
Series 1
Class of Stock [Line Items]
Redemption price per share (in Canadian dollars per share)					25.00
Annual dividend ( in Canadian dollars per share)					1.23475
Shares converted (in shares) \| shares			42,200
Conversion ratio			1
Series 2
Class of Stock [Line Items]
Redemption price per share (in Canadian dollars per share)					25.00
Shares converted (in shares) \| shares			3,889,020
Conversion ratio			1
Series 9
Class of Stock [Line Items]
Redemption price per share (in Canadian dollars per share)					25.00
Annual dividend ( in Canadian dollars per share)					$ 1.27
Shares converted (in shares) \| shares				1,297,203
Conversion ratio				1

OTHER COMPREHENSIVE INCOME(LOSS) AND ACCUMULATED OTHER COMPREHENSIVE INCOME(LOSS) - Reclassifications (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Revenues (Power and Energy Solutions)	$ 15,239	$ 13,771	$ 13,267
Interest expense	(3,407)	(3,019)	(2,966)
Total before tax	5,444	5,906	3,298
Income tax (expense) recovery	(1,138)	(922)	(842)
Net income (loss) attributable to common shares from continuing operations	3,400	4,594	2,829
Plant operating costs and other	4,619	4,413	4,073
Income (loss) from equity investments	1,274	1,558	1,310
Net gain (loss) on sale of assets	0	620	0
Amounts reclassified from AOCI \| Cash flow hedges
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Total before tax	(43)	20	(97)
Income tax (expense) recovery	12	(4)	23
Net income (loss) attributable to common shares from continuing operations	(31)	16	(74)
Amounts reclassified from AOCI \| Cash flow hedges \| Commodities \| Power and Energy Solutions
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Revenues (Power and Energy Solutions)	19	32	(85)
Amounts reclassified from AOCI \| Cash flow hedges \| Foreign Exchange
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Interest expense and Foreign exchange gains (losses), net	(50)	0	0
Interest expense	(12)	(12)	(12)
Amounts reclassified from AOCI \| Pension and other post-retirement benefit plan adjustments
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Total before tax	0	6	0
Income tax (expense) recovery	0	0	0
Net income (loss) attributable to common shares from continuing operations	0	6	0
Amounts reclassified from AOCI \| Amortization of actuarial gains (losses)
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Plant operating costs and other	0	6	0
Amounts reclassified from AOCI \| Equity investments
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Income tax (expense) recovery	(2)	(4)	(6)
Net income (loss) attributable to common shares from continuing operations	1	15	16
Income (loss) from equity investments	3	19	22
Amounts reclassified from AOCI \| Currency Translation Adjustments
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Income tax (expense) recovery	0	0	0
Net income (loss) attributable to common shares from continuing operations	0	15	0
Net gain (loss) on sale of assets	$ 0	$ 15	$ 0

ACCOUNTS PAYABLE AND OTHER (Tables)

12 Months Ended

Dec. 31, 2025

Payables and Accruals [Abstract]

Schedule of Accounts Payable and Other


at December 31	2025	2024
(millions of Canadian $)

Trade payables	3,263	3,699
Regulatory liabilities (Note 12)	532	353
Fair value of derivative instruments (Note 27)	380	507
Factoring arrangement (Note 9)	351	—
Gas transportation and exchange payable	158	118
Emissions expense payable	91	101
Operating lease liabilities (Note 9)	61	60
Contract liabilities (Note 6)	46	30
Income tax liabilities	38	143
Other	354	286
	5,274	5,297

ACQUISITIONS AND DISPOSITIONS (Details) $ in Millions, $ in Millions				1 Months Ended							3 Months Ended			6 Months Ended		12 Months Ended
	May 29, 2024	Oct. 04, 2023 CAD ($)	Oct. 04, 2023 USD ($)	Aug. 31, 2024 CAD ($)	Aug. 31, 2024 USD ($)	Oct. 31, 2023	Jun. 30, 2023 CAD ($)	Jun. 30, 2023 USD ($)	Mar. 31, 2023 CAD ($)	Mar. 31, 2023 USD ($)	Jun. 30, 2025 CAD ($)	Jun. 30, 2024 CAD ($)	Jun. 30, 2024 USD ($)	Jun. 30, 2023 CAD ($)	Jun. 30, 2023 USD ($)	Dec. 31, 2025 CAD ($)	Dec. 31, 2024 CAD ($)	Dec. 31, 2024 USD ($)	Dec. 31, 2023 CAD ($)	Dec. 31, 2023 USD ($)
Business Combination [Line Items]
Foreign currency translation gains and losses on net investment in foreign operations																$ (978)	$ 1,602		$ (1,141)
Sale of equity, noncontrolling interest		$ 9,500	$ 6,900
Contributions to equity investments, net of distributions																1,051
Reclassification of net investment hedge losses from AOCI to non-controlling interests (NCI) related to the sale											$ (348)					$ 348
Reclassification of net investment hedge losses from AOCI to non-controlling interests related to sale percent											40.00%					40.00%
Non-Controlling Interests																$ 9,604	10,768
Comprehensive income (loss) attributable to non-controlling interests																64	1,584		(220)
Acquisitions, net of cash acquired														$ 222	$ 167
Transportadora de Gas Natural de la Huasteca
Business Combination [Line Items]
Non-Controlling Interests												$ 588
Transportadora de Gas Natural de la Huasteca \| Equity Attributable to Non-Controlling Interests
Business Combination [Line Items]
Proceeds from sale of equity												561	$ 411
Reduction to additional paid-in capital												27
Comprehensive income (loss) attributable to non-controlling interests												$ 21
Columbia Gas and Columbia Gulf
Business Combination [Line Items]
Reduction to additional paid-in capital																			$ 3,500	$ 3,000
Texas Wind Farms \| Common Class A
Business Combination [Line Items]
Business acquisition, percentage of voting interests acquired							100.00%	100.00%						100.00%	100.00%
Texas Wind Farms \| Common Class B
Business Combination [Line Items]
Business acquisition, percentage of voting interests acquired							100.00%	100.00%						100.00%	100.00%
Fluvanna Wind Farm
Business Combination [Line Items]
Noncontrolling interest acquired									$ 106	$ 80
Blue Cloud Wind Farm
Business Combination [Line Items]
Noncontrolling interest acquired							$ 116	$ 87
Portland Natural Gas Transmission System
Business Combination [Line Items]
Proceeds from sale of equity				$ 1,600	$ 1,100
Proceeds from sale of interest in partnership unit				743	546
Gain on sale, before tax				572	408
Gain on sale, after tax				456	323
Foreign currency translation gains and losses on net investment in foreign operations				$ 15
Non-Controlling Interests																0	0
Portland Natural Gas Transmission System \| Senior notes
Business Combination [Line Items]
Proceeds from sale of equity					$ 250
TC Energy
Business Combination [Line Items]
Equity interest percentage				61.70%	61.70%
Energir L.P
Business Combination [Line Items]
Equity interest percentage				38.30%	38.30%
Columbia Gas and Columbia Gulf
Business Combination [Line Items]
Proceeds from sale of equity		$ 5,300	$ 3,900
Equity interest percentage		40.00%	40.00%			40.00%
Contributions to equity investments, net of distributions																	33	$ 23
Consideration received as a reduction to additional paid in capital																	24	$ 17
Non-Controlling Interests																$ 8,779	$ 9,844
Transportadora de Gas Natural de la Huasteca
Business Combination [Line Items]
Equity interest percentage	13.01%	13.01%	13.01%

REVENUES (Tables)

12 Months Ended

Dec. 31, 2025

Revenue from Contract with Customer [Abstract]

Schedule of Disaggregation of Revenues


year ended December 31, 2025	Canadian Natural Gas Pipelines	U.S. Natural Gas Pipelines	Mexico Natural Gas Pipelines	Power and Energy Solutions	Total
(millions of Canadian $)

Revenues from contracts with customers
Capacity arrangements and transportation	5,785	5,698	445	—	11,928
Power generation	—	—	—	236	236
Natural gas storage and other1	—	1,141	218	440	1,799
	5,785	6,839	663	676	13,963
Sales-type lease income2	—	—	787	—	787
Other revenues3	—	306	—	169	475
	5,785	7,145	1,450	845	15,225
Corporate revenues4					14
					15,239

2Represents the sales-type lease income on the in-service TGNH pipelines. Refer to Note 9, Leases, for additional information.

4Revenues generated from the Transition Services Agreement with South Bow. Refer to Note 4, Discontinued operations, for additional information.


year ended December 31, 2024	Canadian Natural Gas Pipelines	U.S. Natural Gas Pipelines	Mexico Natural Gas Pipelines	Power and Energy Solutions	Total
(millions of Canadian $)

Revenues from contracts with customers
Capacity arrangements and transportation	5,586	5,382	438	—	11,406
Power generation	—	—	—	266	266
Natural gas storage and other1,2	14	869	124	383	1,390
	5,600	6,251	562	649	13,062
Sales-type lease income3	—	—	308	—	308
Other revenues4	—	88	—	305	393
	5,600	6,339	870	954	13,763
Corporate revenues5					8
					13,771

3Represents the sales-type lease income on the in-service TGNH pipelines. Refer to Note 9, Leases, for additional information.

5 Includes $7 million of revenues generated from the Transition Services Agreement with South Bow. Refer to Note 4, Discontinued operations, for additional information.


year ended December 31, 2023	Canadian Natural Gas Pipelines	U.S. Natural Gas Pipelines	Mexico Natural Gas Pipelines	Power and Energy Solutions	Total
(millions of Canadian $)

Revenues from contracts with customers
Capacity arrangements and transportation	5,141	5,107	442	—	10,690
Power generation	—	—	—	427	427
Natural gas storage and other1,2	32	874	125	363	1,394
	5,173	5,981	567	790	12,511
Sales-type lease income3	—	—	279	—	279
Other revenues4	—	248	—	229	477
	5,173	6,229	846	1,019	13,267

3Represents the sales-type lease income on the in-service TGNH pipelines. Refer to Note 9, Leases, for additional information.

Schedule of Contract Balances

Contract Balances


at December 31	2025	2024	Affected line item on the Consolidated balance sheet
(millions of Canadian $)

Receivables from contracts with customers	1,822	1,452	Accounts receivable
Contract assets (Note 7)	216	165	Other current assets
Long-term contract assets (Note 14)	627	608	Other long-term assets
Contract liabilities1 (Note 16)	46	30	Accounts payable and other

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - Derivatives in Cash Flow Hedging Relationships (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Components of OCI related to derivatives
Change in fair value of derivative instruments recognized in OCI	$ (31)	$ 46	$ 0
Commodities
Components of OCI related to derivatives
Change in fair value of derivative instruments recognized in OCI	7	46	0
Foreign exchange
Components of OCI related to derivatives
Change in fair value of derivative instruments recognized in OCI	$ (38)	$ 0	$ 0

- Definition

Line items represent financial concepts included in a table. These concepts are used to disclose reportable information associated with domain members defined in one or many axes to the table.

+ References

+ Details

ACQUISITIONS AND DISPOSITIONS	12 Months Ended
ACQUISITIONS AND DISPOSITIONS	Dec. 31, 2025
Business Combination, Asset Acquisition, Transaction between Entities under Common Control, and Joint Venture Formation [Abstract]
ACQUISITIONS AND DISPOSITIONS	ACQUISITIONS AND DISPOSITIONS U.S. Natural Gas Pipelines Portland Natural Gas Transmission System (PNGTS) In August 2024, the Company and its partner, Northern New England Investment Company, Inc., a subsidiary of Énergir L.P. (Énergir), completed the sale of PNGTS to a third party for a gross purchase price of approximately $1.6 billion (US$1.1 billion), including the third party's assumption of US$250 million of senior notes outstanding at PNGTS, split pro rata according to the PNGTS ownership interests (TC Energy – 61.7 per cent, Énergir – 38.3 per cent). The Company's share of the proceeds was $743 million (US$546 million), net of transaction costs. The pre-tax gain attributable to the Company of $572 million (US$408 million) was included in Net gain (loss) on sale of assets in the Consolidated statement of income, and the after-tax gain attributable to the Company was $456 million (US$323 million). The gain includes foreign currency translation gains of $15 million which were reclassified from AOCI to Net income (loss). Columbia Gas and Columbia Gulf In October 2023, TC Energy completed the sale of a 40 per cent non-controlling equity interest in Columbia Gas and Columbia Gulf to Global Infrastructure Partners (GIP) for proceeds of $5.3 billion (US$3.9 billion). The Company continues to have a controlling interest in these companies and will remain the operator of the pipelines. TC Energy and GIP will each fund their proportionate share of annual maintenance, modernization and sanctioned growth capital expenditures through internally generated cash flows, debt financing within the Columbia entities, or from proportionate contributions from TC Energy and GIP. The sale was accounted for as an equity transaction of which $9.5 billion (US$6.9 billion) was recorded as non-controlling interests to reflect the 40 per cent change in the Company’s ownership interest in Columbia Gulf and Columbia Gas. The difference between the non-controlling ownership interest recognized and the consideration received was recorded as a reduction to Additional paid-in capital of $3.5 billion (US$3.0 billion), net of tax and transaction costs for the year ended December 31, 2023. At December 31, 2024, as part of the contingent consideration included in the sale, TC Energy accrued a one-time special distribution to GIP of $33 million (US$23 million), or $24 million (US$17 million) net of tax, in Additional paid-in capital. For the year ended December 31, 2025, the Company recorded $348 million as an out-of-period adjustment to reclassify a pro rata portion of its net investment hedge losses from AOCI to NCI related to the sale of 40 per cent of Columbia Gas and Columbia Gulf on October 4, 2023. Refer to Note 2, Accounting policies, for additional information. Mexico Natural Gas Pipelines Transportadora de Gas Natural de la Huasteca In second quarter 2024, in accordance with the terms of the Company's strategic alliance, and in exchange for cash and non-cash consideration of $561 million (US$411 million), the CFE became a partner in TGNH with a 13.01 per cent equity interest. The transaction was accounted for as an equity transaction, of which $588 million was recognized in Non-controlling interests and $21 million was recognized as AOCI attributable to the CFE’s non-controlling interest. The difference between these amounts and the consideration received was recorded as a reduction to Additional paid-in capital of $27 million. Power and Energy Solutions Texas Wind Farms In the first half of 2023, TC Energy acquired 100 per cent of the Class B Membership Interests in Fluvanna Wind Farm (Fluvanna) and Blue Cloud Wind Farm (Blue Cloud), respectively. Each of these operating assets has a tax equity investor which owns 100 per cent of the Class A Membership Interests, to which a percentage of earnings, tax attributes and cash flows are allocated. The tax equity investors' interests were recorded as non-controlling interests at their aggregate estimated fair value of $222 million (US$167 million). TC Energy has determined that the use of the Hypothetical Liquidation at Book Value (HLBV) method of allocating earnings between the Company and the tax equity investors is appropriate as the earnings, tax attributes and cash flows from Fluvanna and Blue Cloud are allocated to its Class A and Class B Membership Interest owners on a basis other than ownership percentages. Using the HLBV method, the Company's earnings from the projects are calculated based on how the projects would allocate and distribute cash if the net assets were sold at their carrying amounts on the reporting date under the provisions of the tax equity agreements. TC Energy determined it has a controlling financial interest in both projects and has consolidated the acquired entities as voting interest entities. The tax equity investors’ interests were recorded as non-controlling interests at their estimated fair values of $106 million (US$80 million) for Fluvanna and $116 million (US$87 million) for Blue Cloud. These transactions are accounted for as asset acquisitions and therefore did not result in the recognition of goodwill.

RATE-REGULATED BUSINESSES - Assets and Liabilities (Details) $ in Millions, $ in Millions	Dec. 31, 2025 CAD ($)	Dec. 31, 2025 USD ($)	Dec. 31, 2024 CAD ($)
Regulatory Assets
Regulatory Assets	$ 2,971		$ 2,805
Less: Current portion included in Other current assets (Note 7)	58		123
Regulatory Assets, noncurrent	2,913		2,682
Regulatory Liabilities
Regulatory Liabilities	6,373		5,656
Less: Current portion included in Accounts payable and other (Note 16)	532		353
Regulatory liabilities, noncurrent	5,841		5,303
Pipeline abandonment trust balances
Regulatory Liabilities
Regulatory Liabilities	3,143		2,686
Deferred income taxes - U.S. Tax Reform
Regulatory Liabilities
Regulatory Liabilities	1,098		1,197
Canadian Mainline short-term adjustment and toll-stabilization accounts
Regulatory Liabilities
Regulatory Liabilities	705		553
Cost of removal
Regulatory Liabilities
Regulatory Liabilities	$ 407		376
Canadian Mainline bridging amortization account
Regulatory Assets
Remaining Recovery/ Settlement Period (years)	5 years	5 years
Regulatory Liabilities
Regulatory Liabilities	$ 268		322
Pensions and other post retirement benefits
Regulatory Liabilities
Regulatory Liabilities	266		122
Pensions and other post retirement benefits \| ANR PIPELINE COMPANY
Regulatory Liabilities
Regulatory Liabilities	43		45
Deferred income taxes
Regulatory Liabilities
Regulatory Liabilities	$ 195		188
Operating and debt-service regulatory liabilities
Regulatory Assets
Remaining Recovery/ Settlement Period (years)	1 year	1 year
Regulatory Liabilities
Regulatory Liabilities	$ 134		50
Canadian Mainline long-term adjustment account
Regulatory Assets
Remaining Recovery/ Settlement Period (years)	1 year	1 year
Regulatory Liabilities
Regulatory Liabilities	$ 37		74
Other
Regulatory Liabilities
Regulatory Liabilities	77		43
Postretirement benefit costs \| ANR PIPELINE COMPANY
Regulatory Liabilities
Amount to be addressed In next settlement	43	$ 32
Long term adjustment account, amount to be amortized over one year
Regulatory Liabilities
Regulatory Liabilities	$ 223
Regulatory liability, amortization period	6 years	6 years
Deferred income taxes
Regulatory Assets
Regulatory Assets	$ 2,760		2,593
Operating and debt-service regulatory assets
Regulatory Assets
Remaining Recovery/ Settlement Period (years)	1 year	1 year
Regulatory Assets	$ 0		56
Foreign exchange on long-term debt
Regulatory Assets
Regulatory Assets	$ 23		39
Foreign exchange on long-term debt \| Minimum
Regulatory Assets
Remaining Recovery/ Settlement Period (years)	1 year	1 year
Foreign exchange on long-term debt \| Maximum
Regulatory Assets
Remaining Recovery/ Settlement Period (years)	4 years	4 years
Other
Regulatory Assets
Regulatory Assets	$ 188		$ 117

NOTES PAYABLE (Tables)

12 Months Ended

Dec. 31, 2025

Short-Term Debt [Abstract]

Schedule of Notes Payable


at December 31	2025			2024
(millions of Canadian $, unless otherwise noted)	Outstanding	Weighted Average Interest Rate per Annum		Outstanding	Weighted Average Interest Rate per Annum

Canada1	584	3.9	%	308	4.7	%
U.S. (2025 – US$449; 2024 – US$55)	616	4.1	%	79	4.7	%

	1,200			387

1At December 31, 2025, Notes payable consisted of Canadian dollar-denominated notes of $68 million (2024 – nil) and U.S. dollar-denominated notes of US$348 million (2024 – US$214 million).

Schedule of Credit Facilities

These unsecured credit facilities included the following:

at December 31

(billions of Canadian $, unless otherwise noted)

2025

2024

Borrowers

Description

Matures

Total Facilities

Unused Capacity1

Total Facilities

Committed, syndicated, revolving, extendible, senior unsecured credit facilities2:

TCPL

Supports commercial paper program and for general corporate purposes

December 2030

3.0

2.9

3.0

TCPL / TCPL USA

Supports commercial paper programs and for general corporate purposes of the borrowers, guaranteed by TCPL

December 2026

US 1.0

US 0.8

US 1.0

TCPL / TCPL USA

Supports commercial paper programs and for general corporate purposes of the borrowers, guaranteed by TCPL

December 2028

US 2.5

US 2.3

US 2.5

Columbia Pipelines Holding Company LLC3

Supports commercial paper program and general corporate purposes of the borrower

December 2028

US 1.5

US 1.1

US 1.5

Demand senior unsecured revolving credit facilities2:

TCPL / TCPL USA

Supports the issuance of letters of credit and provides additional liquidity; TCPL USA facility guaranteed by TCPL

Demand

2.0

1.3

2.0

1Unused capacity is net of commercial paper outstanding and facility draws.

3Columbia Pipelines Holding Company LLC is a partially-owned subsidiary of TC Energy with 40 per cent non-controlling interest.

4Or the U.S. dollar equivalent.

INCOME TAXES

12 Months Ended

Dec. 31, 2025

Income Tax Disclosure [Abstract]

INCOME TAXES

Geographic Components of Income before Income Taxes


year ended December 31	2025	2024	2023
(millions of Canadian $)

Canada	1,959	1,469	(194)
Foreign	3,485	4,437	3,492
Income before Income Taxes	5,444	5,906	3,298

Provision for Income Taxes


year ended December 31	2025	2024	2023
(millions of Canadian $)

Current
Canada - federal	54	90	34
Canada - provincial	5	71	40
Foreign	308	334	790
	367	495	864
Deferred
Canada - federal	213	80	3
Canada - provincial	139	56	3
Foreign	419	291	(28)
	771	427	(22)
Income Tax Expense	1,138	922	842

Reconciliation of Income Tax Expense


year ended December 31	2025				2024				2023
(millions of Canadian $, unless otherwise noted)	Amount		Percentage		Amount		Percentage		Amount		Percentage

Income before income taxes	5,444				5,906				3,298
Canadian federal statutory income tax rate	15	%			15	%			15	%
Expected income tax expense	817				886				495
Canadian federal reconciling items
Income tax differential related to regulated operations	(24)		(0.4	%)	(68)		(1.2	%)	(108)		(3.3	%)


Non-taxable capital (gain) loss	(20)		(0.4	%)	12		0.2	%	113		3.4	%
Changes in valuation allowances	—		—		3		0.1	%	114		3.5	%
Effect of cross-border taxes	(25)		(0.5	%)	(23)		(0.4	%)	(27)		(0.8	%)
Canadian provincial taxes1	143		2.6	%	103		1.7	%	22		0.7	%
Foreign reconciling items
United States
Rate differential	177		3.3	%	168		2.8	%	136		4.1	%
State and local income taxes, net of federal effect	(28)		(0.5	%)	123		2.1	%	76		2.3	%

Income from non-controlling interests	(125)		(2.3	%)	(121)		(2.0	%)	(31)		(0.9	%)
Other	(16)		(0.3	%)	(12)		(0.2	%)	(8)		(0.2	%)
Mexico
Mexico foreign exchange exposure	213		3.9	%	(246)		(4.2	%)	163		4.9	%
Rate differential	57		1.0	%	234		4.0	%	94		2.9	%
Income from equity investments	(28)		(0.5	%)	(84)		(1.4	%)	(23)		(0.7	%)
Income tax differential related to regulated operations	(45)		(0.8	%)	(109)		(1.8	%)	(79)		(2.4	%)
Withholding tax	41		0.8	%	35		0.6	%	12		0.4	%
Other	8		0.1	%	2		—		2		0.1	%
Other foreign jurisdictions	(2)		—		3		0.1	%	(91)		(2.8	%)

Other adjustments	(5)		(0.1	%)	16		0.3	%	(18)		(0.5	%)
Income Tax Expense	1,138		20.9	%	922		15.7	%	842		25.7	%

1 Ontario provincial tax comprises the majority of Canada provincial taxes.

Deferred Income Tax Assets and Liabilities


at December 31	2025	2024
(millions of Canadian $)

Deferred Income Tax Assets
Tax loss and credit carryforwards	1,728	1,987
Disallowed interest carryforward	100	115
Regulatory and other deferred amounts	644	612
Unrealized foreign exchange losses on long-term debt	290	467

Other	57	143
	2,819	3,324
Less: Valuation allowance	789	931
	2,030	2,393
Deferred Income Tax Liabilities
Difference in accounting and tax bases of plant, property and equipment	6,792	6,488
Equity investments	1,478	1,280
Taxes on future revenue requirement	654	612
Financial instruments	176	168
Other	251	301
	9,351	8,849
Net Deferred Income Tax Liabilities	7,321	6,456

The above deferred tax amounts have been classified on the Consolidated balance sheet as follows:


at December 31	2025	2024
(millions of Canadian $)

Deferred Income Tax Assets
Other long-term assets (Note 14)	356	428
Deferred Income Tax Liabilities
Deferred income tax liabilities	7,677	6,884
Net Deferred Income Tax Liabilities	7,321	6,456

The following table provides details of the tax loss and credit carryforwards and valuation allowances:


at December 31, 2025	Unused Amounts	Deferred Tax Asset	Valuation Allowance	Expiry Years
(millions of Canadian $)

Tax Loss and Credit Carryforwards
Operating losses	5,838	1,302	—	2026-2045
Foreign federal and state operating losses	1,746	173	41	2026-2037
Capital loss	618	74	74	Indefinite
Minimum tax	—	179	42	2033-Indefinite
		1,728	157
Restricted Interest and Financing Expense	424	100	—	Indefinite
Unrealized Foreign Exchange on Long-Term Debt	—	290	290
Equity Investments	—	342	342
			789

TC Energy recorded a decrease in valuation allowance in the year primarily resulting from unrealized foreign exchange movements.

Unremitted Earnings of Foreign Investments

Income taxes have not been provided on the unremitted earnings of foreign investments that the Company does not intend to repatriate in the foreseeable future. Deferred income tax liabilities would have increased at December 31, 2025 by approximately $2,198 million (2024 – $1,728 million) if there had been a provision for these taxes.

Income Tax Payments (Refunds)


at December 31	2025	2024	2023
(millions of Canadian $)
Jurisdiction
Canada - federal	73	53	61
Canada - provincial	17	6	(1)
United States	368	302	692
Mexico	84	34	26
Other - foreign	1	(8)	13
	543	387	791

Reconciliation of Unrecognized Tax Benefit

Below is the reconciliation of the annual changes in the total unrecognized tax benefit:


at December 31	2025	2024	2023
(millions of Canadian $)

Unrecognized tax benefit at beginning of year	72	85	91
Gross increase - tax positions in prior years	2	3	9
Gross decrease - tax positions in prior years	(4)	(2)	(1)
Gross increase - tax positions in current year	18	5	16
Gross decrease - tax positions in current year	—	(2)	—
Settlement	—	(13)	—
Lapse of statutes of limitations	(5)	(4)	(30)
Unrecognized Tax Benefit at End of Year	83	72	85

TC Energy's practice is to recognize interest and penalties related to income tax uncertainties in Income tax expense. Income tax expense for the year ended December 31, 2025 reflects $7 million interest expense (2024 – $1 million recovery; 2023 – $3 million expense). At December 31, 2025, the Company accrued $26 million in interest expense (2024 – $19 million; 2023 – $20 million). The Company incurred no penalties associated with income tax uncertainties related to income tax expense for the years ended December 31, 2025, 2024 and 2023 and no penalties were accrued as at December 31, 2025, 2024 and 2023.

The Company has substantially concluded all Canadian federal and provincial income tax matters for the years through 2017. Substantially all material U.S. federal, state and local income tax matters have been concluded for years through 2019. Substantially all material Mexico income tax matters have been concluded for years through 2019.

- Definition

The entire disclosure for income tax.

+ References

Reference 1: http://www.xbrl.org/2003/role/disclosureRef
-Topic 942
-SubTopic 740
-Name Accounting Standards Codification
-Section 50
-Paragraph 1
-Subparagraph (a)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147477617/942-740-50-1

Reference 2: http://www.xbrl.org/2003/role/disclosureRef
-Topic 235
-SubTopic 10
-Name Accounting Standards Codification
-Section S50
-Paragraph 1
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480738/235-10-S50-1

Reference 3: http://www.xbrl.org/2003/role/disclosureRef
-Topic 944
-SubTopic 740
-Name Accounting Standards Codification
-Section 50
-Paragraph 1
-Subparagraph (a)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147478822/944-740-50-1

Reference 4: http://www.xbrl.org/2003/role/disclosureRef
-Topic 740
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 12
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482685/740-10-50-12

Reference 5: http://www.xbrl.org/2003/role/exampleRef
-Topic 740
-SubTopic 10
-Name Accounting Standards Codification
-Section 55
-Paragraph 231
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482663/740-10-55-231

Reference 6: http://www.xbrl.org/2003/role/disclosureRef
-Topic 740
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 12C
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482685/740-10-50-12C

Reference 7: http://www.xbrl.org/2003/role/disclosureRef
-Topic 740
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 12B
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482685/740-10-50-12B

Reference 8: http://www.xbrl.org/2003/role/disclosureRef
-Topic 740
-SubTopic 270
-Name Accounting Standards Codification
-Section 50
-Paragraph 1
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147477891/740-270-50-1

Reference 9: http://www.xbrl.org/2003/role/disclosureRef
-Topic 740
-SubTopic 10
-Name Accounting Standards Codification
-Section S99
-Paragraph 1
-Subparagraph (SAB Topic 6.I.5.Q1)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147479360/740-10-S99-1

Reference 10: http://www.xbrl.org/2003/role/disclosureRef
-Topic 946
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 13
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480990/946-20-50-13

Reference 11: http://www.xbrl.org/2003/role/disclosureRef
-Topic 235
-SubTopic 10
-Name Accounting Standards Codification
-Section S99
-Paragraph 1
-Subparagraph (SX 210.4-08(h)(2))
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480678/235-10-S99-1

Reference 12: http://www.xbrl.org/2003/role/disclosureRef
-Topic 740
-Name Accounting Standards Codification
-Publisher FASB
-URI https://asc.fasb.org/740/tableOfContent

Reference 13: http://www.xbrl.org/2003/role/disclosureRef
-Topic 740
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 14
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482685/740-10-50-14

Reference 14: http://www.xbrl.org/2003/role/disclosureRef
-Topic 740
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 21
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482685/740-10-50-21

Reference 15: http://www.xbrl.org/2003/role/disclosureRef
-Topic 740
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 17
-Subparagraph (b)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482685/740-10-50-17

Reference 16: http://www.xbrl.org/2003/role/disclosureRef
-Topic 740
-SubTopic 10
-Name Accounting Standards Codification
-Section S99
-Paragraph 2
-Subparagraph (SAB Topic 11.C)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147479360/740-10-S99-2

Reference 17: http://www.xbrl.org/2003/role/disclosureRef
-Topic 740
-SubTopic 30
-Name Accounting Standards Codification
-Section 50
-Paragraph 2
-Subparagraph (a)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482603/740-30-50-2

+ Details

PLANT, PROPERTY AND EQUIPMENT (Details) - CAD ($) $ in Millions	Dec. 31, 2025	Dec. 31, 2024
Property, Plant and Equipment [Line Items]
Cost	$ 108,005	$ 112,898
Accumulated Depreciation	36,951	35,397
Net Book Value	71,054	77,501
TGNH
Property, Plant and Equipment [Line Items]
Sales-type lease, net investment in lease, before allowance for credit loss	6,595	0
Operating segments \| Canadian Natural Gas Pipelines
Property, Plant and Equipment [Line Items]
Cost	50,102	49,131
Accumulated Depreciation	25,648	24,479
Net Book Value	24,454	24,652
Operating segments \| Canadian Natural Gas Pipelines \| NGTL System
Property, Plant and Equipment [Line Items]
Cost	30,431	29,814
Accumulated Depreciation	11,672	10,793
Net Book Value	18,759	19,021
Operating segments \| Canadian Natural Gas Pipelines \| Canadian Mainline
Property, Plant and Equipment [Line Items]
Cost	16,705	16,359
Accumulated Depreciation	12,199	11,944
Net Book Value	4,506	4,415
Operating segments \| Canadian Natural Gas Pipelines \| Other Natural Gas Pipelines
Property, Plant and Equipment [Line Items]
Cost	2,966	2,958
Accumulated Depreciation	1,777	1,742
Net Book Value	1,189	1,216
Operating segments \| Canadian Natural Gas Pipelines \| Property, plant and equipment excluding under construction \| NGTL System
Property, Plant and Equipment [Line Items]
Cost	29,768	29,311
Accumulated Depreciation	11,672	10,793
Net Book Value	18,096	18,518
Operating segments \| Canadian Natural Gas Pipelines \| Property, plant and equipment excluding under construction \| Canadian Mainline
Property, Plant and Equipment [Line Items]
Cost	16,584	16,196
Accumulated Depreciation	12,199	11,944
Net Book Value	4,385	4,252
Operating segments \| Canadian Natural Gas Pipelines \| Pipeline \| NGTL System
Property, Plant and Equipment [Line Items]
Cost	20,806	20,497
Accumulated Depreciation	8,037	7,413
Net Book Value	12,769	13,084
Operating segments \| Canadian Natural Gas Pipelines \| Pipeline \| Canadian Mainline
Property, Plant and Equipment [Line Items]
Cost	11,126	10,907
Accumulated Depreciation	8,355	8,165
Net Book Value	2,771	2,742
Operating segments \| Canadian Natural Gas Pipelines \| Compression \| NGTL System
Property, Plant and Equipment [Line Items]
Cost	7,277	7,146
Accumulated Depreciation	2,732	2,497
Net Book Value	4,545	4,649
Operating segments \| Canadian Natural Gas Pipelines \| Compression \| Canadian Mainline
Property, Plant and Equipment [Line Items]
Cost	4,661	4,540
Accumulated Depreciation	3,500	3,448
Net Book Value	1,161	1,092
Operating segments \| Canadian Natural Gas Pipelines \| Metering and other \| NGTL System
Property, Plant and Equipment [Line Items]
Cost	1,685	1,668
Accumulated Depreciation	903	883
Net Book Value	782	785
Operating segments \| Canadian Natural Gas Pipelines \| Metering and other \| Canadian Mainline
Property, Plant and Equipment [Line Items]
Cost	797	749
Accumulated Depreciation	344	331
Net Book Value	453	418
Operating segments \| Canadian Natural Gas Pipelines \| Other \| Other Natural Gas Pipelines
Property, Plant and Equipment [Line Items]
Cost	2,947	2,927
Accumulated Depreciation	1,777	1,742
Net Book Value	1,170	1,185
Operating segments \| Canadian Natural Gas Pipelines \| Under construction \| NGTL System
Property, Plant and Equipment [Line Items]
Cost	663	503
Accumulated Depreciation	0	0
Net Book Value	663	503
Operating segments \| Canadian Natural Gas Pipelines \| Under construction \| Canadian Mainline
Property, Plant and Equipment [Line Items]
Cost	121	163
Accumulated Depreciation	0	0
Net Book Value	121	163
Operating segments \| Canadian Natural Gas Pipelines \| Under construction \| Other Natural Gas Pipelines
Property, Plant and Equipment [Line Items]
Cost	19	31
Accumulated Depreciation	0	0
Net Book Value	19	31
Operating segments \| U.S. Natural Gas Pipelines
Property, Plant and Equipment [Line Items]
Cost	49,241	48,571
Accumulated Depreciation	8,968	8,744
Net Book Value	40,273	39,827
Operating segments \| U.S. Natural Gas Pipelines \| Columbia Gas
Property, Plant and Equipment [Line Items]
Cost	26,369	26,440
Accumulated Depreciation	2,853	2,604
Net Book Value	23,516	23,836
Operating segments \| U.S. Natural Gas Pipelines \| ANR
Property, Plant and Equipment [Line Items]
Cost	10,254	9,608
Accumulated Depreciation	2,201	2,204
Net Book Value	8,053	7,404
Operating segments \| U.S. Natural Gas Pipelines \| Property, plant and equipment excluding under construction \| Other Natural Gas Pipelines
Property, Plant and Equipment [Line Items]
Cost	11,975	11,829
Accumulated Depreciation	3,914	3,936
Net Book Value	8,061	7,893
Operating segments \| U.S. Natural Gas Pipelines \| Property, plant and equipment excluding under construction \| Columbia Gas
Property, Plant and Equipment [Line Items]
Cost	25,694	25,549
Accumulated Depreciation	2,853	2,604
Net Book Value	22,841	22,945
Operating segments \| U.S. Natural Gas Pipelines \| Property, plant and equipment excluding under construction \| ANR
Property, Plant and Equipment [Line Items]
Cost	9,892	8,755
Accumulated Depreciation	2,201	2,204
Net Book Value	7,691	6,551
Operating segments \| U.S. Natural Gas Pipelines \| Pipeline \| Other Natural Gas Pipelines
Property, Plant and Equipment [Line Items]
Cost	1,646	1,695
Accumulated Depreciation	655	628
Net Book Value	991	1,067
Operating segments \| U.S. Natural Gas Pipelines \| Pipeline \| Columbia Gas
Property, Plant and Equipment [Line Items]
Cost	14,996	14,826
Accumulated Depreciation	1,610	1,472
Net Book Value	13,386	13,354
Operating segments \| U.S. Natural Gas Pipelines \| Pipeline \| ANR
Property, Plant and Equipment [Line Items]
Cost	3,092	2,477
Accumulated Depreciation	744	745
Net Book Value	2,348	1,732
Operating segments \| U.S. Natural Gas Pipelines \| Pipeline \| Columbia Gulf
Property, Plant and Equipment [Line Items]
Cost	4,427	4,127
Accumulated Depreciation	274	304
Net Book Value	4,153	3,823
Operating segments \| U.S. Natural Gas Pipelines \| Pipeline \| GTN
Property, Plant and Equipment [Line Items]
Cost	3,325	3,405
Accumulated Depreciation	1,476	1,467
Net Book Value	1,849	1,938
Operating segments \| U.S. Natural Gas Pipelines \| Pipeline \| Great Lakes
Property, Plant and Equipment [Line Items]
Cost	2,577	2,602
Accumulated Depreciation	1,509	1,537
Net Book Value	1,068	1,065
Operating segments \| U.S. Natural Gas Pipelines \| Compression \| Columbia Gas
Property, Plant and Equipment [Line Items]
Cost	6,169	6,153
Accumulated Depreciation	741	677
Net Book Value	5,428	5,476
Operating segments \| U.S. Natural Gas Pipelines \| Compression \| ANR
Property, Plant and Equipment [Line Items]
Cost	4,933	4,446
Accumulated Depreciation	948	938
Net Book Value	3,985	3,508
Operating segments \| U.S. Natural Gas Pipelines \| Metering and other \| Columbia Gas
Property, Plant and Equipment [Line Items]
Cost	4,529	4,570
Accumulated Depreciation	502	455
Net Book Value	4,027	4,115
Operating segments \| U.S. Natural Gas Pipelines \| Metering and other \| ANR
Property, Plant and Equipment [Line Items]
Cost	1,867	1,832
Accumulated Depreciation	509	521
Net Book Value	1,358	1,311
Operating segments \| U.S. Natural Gas Pipelines \| Under construction
Property, Plant and Equipment [Line Items]
Accumulated Depreciation	0	0
Operating segments \| U.S. Natural Gas Pipelines \| Under construction \| Other Natural Gas Pipelines
Property, Plant and Equipment [Line Items]
Cost	643	694
Accumulated Depreciation	0	0
Net Book Value	643	694
Operating segments \| U.S. Natural Gas Pipelines \| Under construction \| Columbia Gas
Property, Plant and Equipment [Line Items]
Cost	675	891
Accumulated Depreciation	0	0
Net Book Value	675	891
Operating segments \| U.S. Natural Gas Pipelines \| Under construction \| ANR
Property, Plant and Equipment [Line Items]
Cost	362	853
Net Book Value	362	853
Operating segments \| U.S. Natural Gas Pipelines \| Property, plant and equipment, including under construction \| Other Natural Gas Pipelines
Property, Plant and Equipment [Line Items]
Cost	12,618	12,523
Accumulated Depreciation	3,914	3,936
Net Book Value	8,704	8,587
Operating segments \| Mexico Natural Gas Pipelines \| Property, plant and equipment excluding under construction
Property, Plant and Equipment [Line Items]
Cost	3,311	3,464
Accumulated Depreciation	765	729
Net Book Value	2,546	2,735
Operating segments \| Mexico Natural Gas Pipelines \| Pipeline
Property, Plant and Equipment [Line Items]
Cost	2,468	2,590
Accumulated Depreciation	545	523
Net Book Value	1,923	2,067
Operating segments \| Mexico Natural Gas Pipelines \| Compression
Property, Plant and Equipment [Line Items]
Cost	449	476
Accumulated Depreciation	113	107
Net Book Value	336	369
Operating segments \| Mexico Natural Gas Pipelines \| Metering and other
Property, Plant and Equipment [Line Items]
Cost	394	398
Accumulated Depreciation	107	99
Net Book Value	287	299
Operating segments \| Mexico Natural Gas Pipelines \| Under construction
Property, Plant and Equipment [Line Items]
Cost	1,454	7,807
Accumulated Depreciation	0	0
Net Book Value	1,454	7,807
Operating segments \| Mexico Natural Gas Pipelines \| Property, plant and equipment, including under construction
Property, Plant and Equipment [Line Items]
Cost	4,765	11,271
Accumulated Depreciation	765	729
Net Book Value	4,000	10,542
Operating segments \| Power and Energy Solutions \| Property, plant and equipment excluding under construction
Property, Plant and Equipment [Line Items]
Cost	2,946	2,925
Accumulated Depreciation	1,110	1,006
Net Book Value	1,836	1,919
Operating segments \| Power and Energy Solutions \| Natural Gas Power Generation
Property, Plant and Equipment [Line Items]
Cost	1,322	1,273
Accumulated Depreciation	719	671
Net Book Value	603	602
Operating segments \| Power and Energy Solutions \| Natural Gas Storage and Other
Property, Plant and Equipment [Line Items]
Cost	887	873
Accumulated Depreciation	308	281
Net Book Value	579	592
Operating segments \| Power and Energy Solutions \| Renewable Power Generation
Property, Plant and Equipment [Line Items]
Cost	737	779
Accumulated Depreciation	83	54
Net Book Value	654	725
Operating segments \| Power and Energy Solutions \| Under construction
Property, Plant and Equipment [Line Items]
Cost	56	56
Accumulated Depreciation	0	0
Net Book Value	56	56
Operating segments \| Power and Energy Solutions \| Property, plant and equipment, including under construction
Property, Plant and Equipment [Line Items]
Cost	3,002	2,981
Accumulated Depreciation	1,110	1,006
Net Book Value	1,892	1,975
Corporate
Property, Plant and Equipment [Line Items]
Cost	895	944
Accumulated Depreciation	460	439
Net Book Value	$ 435	$ 505

VARIABLE INTEREST ENTITIES - Carrying Value of Non-consolidated VIEs and Maximum Exposure (Details) - CAD ($) $ in Millions	1 Months Ended	12 Months Ended
	Oct. 31, 2025	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023	Dec. 17, 2024
Balance Sheet Exposure
Equity Investments		$ 11,358	$ 10,636
Off-balance sheet
Maximum exposure to loss		10,989	10,353
Payment to reduce company's funding commitment		1,051	4,683	$ 4,149
Bruce Power
Off-balance sheet
Off-balance Sheet potential exposure to guarantees		1,955	1,877
Coastal GasLink
Off-balance sheet
Off-balance Sheet potential exposure to guarantees		200	265
Coastal GasLink \| Equity Contribution Agreement \| Subordinated debt \| Coastal GasLink
Off-balance sheet
Payment to reduce company's funding commitment	$ 65		3,137
Line of credit facility, outstanding amount					$ 3,147
Funding commitment	$ 163		228
Revolving credit facility, borrowing capacity			37
Other equity investments
Off-balance sheet
Off-balance Sheet potential exposure to guarantees		0	2
VIE, not primary beneficiary \| Bruce Power
Balance Sheet Exposure
Equity Investments		7,780	7,043
VIE, not primary beneficiary \| Coastal GasLink
Balance Sheet Exposure
Equity Investments		896	1,006
VIE, not primary beneficiary \| Other equity investments
Balance Sheet Exposure
Equity Investments		$ 158	$ 160

GOODWILL (Tables)

12 Months Ended

Dec. 31, 2025

Goodwill and Intangible Assets Disclosure [Abstract]

Schedule of Goodwill

The Company's Goodwill balance on the Consolidated balance sheet is comprised of the following amounts:


at December 31	2025		2024
(millions)	Canadian dollars	U.S. dollars1	Canadian dollars	U.S. dollars1

Columbia	10,082	7,351	10,588	7,351
ANR	2,669	1,946	2,803	1,946
Great Lakes	167	122	176	122
North Baja	66	48	70	48
Tuscarora	32	23	33	23
	13,016	9,490	13,670	9,490

1Represents gross amounts of goodwill as at December 31, 2025 and 2024 of US$10,828 million, net of accumulated impairment of US$1,338 million.

Changes in Goodwill were as follows:


(millions of Canadian $)			U.S. Natural Gas Pipelines

Balance at January 1, 2024			12,532

Foreign exchange rate changes			1,138
Balance at December 31, 2024			13,670

Foreign exchange rate changes			(654)
Balance at December 31, 2025			13,016

- Definition

Tabular disclosure of goodwill by reportable segment and in total which includes a rollforward schedule.

+ References

Reference 1: http://www.xbrl.org/2003/role/exampleRef
-Topic 350
-SubTopic 20
-Name Accounting Standards Codification
-Section 55
-Paragraph 24
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482548/350-20-55-24

Reference 2: http://www.xbrl.org/2009/role/commonPracticeRef
-Topic 350
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 1
-Subparagraph (a)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482573/350-20-50-1

Reference 3: http://www.xbrl.org/2009/role/commonPracticeRef
-Topic 350
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 1
-Subparagraph (h)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482573/350-20-50-1

Reference 4: http://www.xbrl.org/2009/role/commonPracticeRef
-Topic 350
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 1
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482573/350-20-50-1

Reference 5: http://www.xbrl.org/2009/role/commonPracticeRef
-Topic 350
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 1
-Subparagraph (b)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482573/350-20-50-1

Reference 6: http://www.xbrl.org/2009/role/commonPracticeRef
-Topic 350
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 1
-Subparagraph (c)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482573/350-20-50-1

Reference 7: http://www.xbrl.org/2009/role/commonPracticeRef
-Topic 350
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 1
-Subparagraph (d)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482573/350-20-50-1

Reference 8: http://www.xbrl.org/2009/role/commonPracticeRef
-Topic 350
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 1
-Subparagraph (e)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482573/350-20-50-1

Reference 9: http://www.xbrl.org/2009/role/commonPracticeRef
-Topic 350
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 1
-Subparagraph (f)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482573/350-20-50-1

Reference 10: http://www.xbrl.org/2009/role/commonPracticeRef
-Topic 350
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 1
-Subparagraph (g)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482573/350-20-50-1

Reference 11: http://www.xbrl.org/2009/role/commonPracticeRef
-Topic 350
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 1A
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482573/350-20-50-1A

Reference 12: http://www.xbrl.org/2009/role/commonPracticeRef
-Topic 350
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 2
-Subparagraph (b)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482573/350-20-50-2

+ Details

REVENUES - Remaining Performance Obligations - Narrative (Details) $ in Billions	Dec. 31, 2025 CAD ($)
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Future revenues, remaining performance obligation	$ 33.8
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2026-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Future revenues, remaining performance obligation	$ 7.0
Future revenues, expected timing of satisfaction, period	1 year

INCOME TAXES - Deferred Assets and Liabilities, Net (Details) - CAD ($) $ in Millions	Dec. 31, 2025	Dec. 31, 2024
Deferred Income Tax Assets
Other long-term assets (Note 14)	$ 356	$ 428
Deferred Income Tax Liabilities
Deferred Income Tax Liabilities	7,677	6,884
Net Deferred Income Tax Liabilities	$ 7,321	$ 6,456

NOTES PAYABLE - Narratives (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Revolving credit facility
Notes payable
Cost to maintain	$ 15	$ 18	$ 16
Revolving and demand credit facility
Notes payable
Revolving credit facility, borrowing capacity	$ 11,900	$ 12,200

FOREIGN EXCHANGE (GAINS) LOSSES, NET

12 Months Ended

Dec. 31, 2025

Foreign Currency [Abstract]

FOREIGN EXCHANGE (GAINS) LOSSES, NET


year ended December 31	2025	2024	2023
(millions of Canadian $)

Derivative instruments held for trading (Note 27)	(352)	418	(401)
Other	195	(271)	81
	(157)	147	(320)

- Definition

The entire disclosure for foreign currency transactions and translation. This may include description of foreign currency transactions, foreign currency gains and losses, explanation of change in cumulative translation adjustment, description of effect of subsequent foreign currency exchange rate change, cumulative translation adjustment movement, foreign currency translation adjustment by component movement, translation adjustment for net investment hedge movement, adjustment for long-term intercompany transactions, schedule of long-term intercompany balances and any other foreign currency transactions and translation related items.

+ References + Details

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - Effect of Fair Value and Cash Flow Hedging Relationships (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Gain (loss) on cash flow hedge	$ 2	$ 6	$ 0
Interest rate contracts \| Interest Expense
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Hedged items	(179)	(126)	(98)
Derivatives designated as hedging instruments	(30)	(52)	(43)
Reclassification of gains/(losses) on derivative instruments from AOCI to net income	(12)	(12)	(12)
Commodity contracts \| Revenue
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Reclassification of gains/(losses) on derivative instruments from AOCI to net income	19	32	(85)
Foreign exchange \| Revenue
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Reclassification of gains/(losses) on derivative instruments from AOCI to net income	$ (50)	$ 0	$ 0

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS (Tables)

12 Months Ended

Dec. 31, 2025

Risk Management and Financial Instruments [Abstract]

Schedule of Derivative Instruments

The fair values and notional amounts for the derivatives designated as a net investment hedge were as follows:

at December 31

2025

2024

Fair
Value

Notional Amount

Fair
Value1,2

Notional Amount

(millions of Canadian $, unless otherwise noted)

U.S. dollar cross-currency interest rate swaps3

—

(11)

US 100

1Fair value equals carrying value.

2No amounts have been excluded from the assessment of hedge effectiveness.

The notional amounts and fair values of U.S. dollar-denominated debt designated as a net investment hedge were as follows:

at December 31

2025

2024

(millions of Canadian $, unless otherwise noted)

Notional amount

25,700 (US 18,700)

26,000 (US 18,000)

Fair value

25,800 (US 18,800)

25,700 (US 17,800)

The maturity and notional amount or quantity outstanding related to the Company's derivative instruments excluding hedges of the net investment in foreign operations was as follows:


at December 31, 2025	Power	Natural Gas	Foreign Exchange	Interest Rate

Net sales (purchases)1	10,221	26	—	—
Millions of U.S. dollars	—	—	6,342	2,950
Millions of Mexican pesos	—	—	15,750	—
Maturity dates	2026-2044	2026-2032	2026-2030	2030-2034

1Volumes for power and natural gas derivatives are in GWh and Bcf, respectively.


at December 31, 2024	Power	Natural Gas	Foreign Exchange	Interest Rate

Net sales (purchases)1	10,192	53	—	—
Millions of U.S. dollars	—	—	5,648	2,800
Millions of Mexican pesos	—	—	16,750	—
Maturity dates	2025-2044	2025-2031	2025-2027	2030-2034

1Volumes for power and natural gas derivatives are in GWh and Bcf, respectively.

Schedule of Financial Instruments


at December 31	2025		2024
	Carrying Amount	Fair Value	Carrying Amount	Fair Value
(millions of Canadian $)

Long-term debt, including current portion (Note 19)1,2	(46,792)	(47,720)	(47,931)	(48,318)
Junior subordinated notes (Note 20)	(12,094)	(12,061)	(11,048)	(10,824)
	(58,886)	(59,781)	(58,979)	(59,142)

1Long-term debt is recorded at amortized cost, except for $4.0 billion (2024 – $4.0 billion) that is attributed to hedged risk and recorded at fair value.


at December 31	2025		2024
	LMCI Restricted Investments	Other Restricted Investments1	LMCI Restricted Investments	Other Restricted Investments1
(millions of Canadian $)

Fair value of fixed income securities2,3
Maturing within 1 year	—	94	—	33
Maturing within 1-5 years	26	251	3	256
Maturing within 5-10 years	1,846	4	1,578	—
Maturing after 10 years	—	16	—	—
Fair value of equity securities2,4	1,252	94	1,070	64
	3,124	459	2,651	353

3Classified in Level II of the fair value hierarchy.

4Classified in Level I of the fair value hierarchy.

The balance sheet classification of the fair value of derivative instruments was as follows:


at December 31, 2025	Cash Flow Hedges	Fair Value Hedges	Held for Trading	Total Fair Value of Derivative Instruments1
(millions of Canadian $)

Other current assets (Note 7)
Commodities2	13	—	371	384
Foreign exchange	9	—	42	51
Interest rate	—	3	—	3
	22	3	413	438
Other long-term assets (Note 14)
Commodities2	2	—	122	124
Foreign exchange	—	—	15	15
Interest rate	—	22	—	22
	2	22	137	161
Total Derivative Assets	24	25	550	599

Accounts payable and other (Note 16)
Commodities2	(1)	—	(341)	(342)
Foreign exchange	—	—	(30)	(30)
Interest rate	—	(8)	—	(8)
	(1)	(8)	(371)	(380)
Other long-term liabilities (Note 17)
Commodities2	(1)	—	(61)	(62)
Foreign exchange	(51)	—	(2)	(53)
Interest rate	—	(34)	—	(34)
	(52)	(34)	(63)	(149)
Total Derivative Liabilities	(53)	(42)	(434)	(529)
Total Derivatives	(29)	(17)	116	70

1Fair value equals carrying value.

2Includes purchases and sales of power and natural gas.

The balance sheet classification of the fair value of derivative instruments was as follows:


at December 31, 2024	Cash Flow Hedges	Fair Value Hedges	Net Investment Hedges	Held for Trading	Total Fair Value of Derivative Instruments1
(millions of Canadian $)

Other current assets (Note 7)
Commodities2	18	—	—	287	305
Foreign exchange	—	—	—	42	42

	18	—	—	329	347
Other long-term assets (Note 14)
Commodities2	9	—	—	104	113
Foreign exchange	—	—	—	9	9

	9	—	—	113	122
Total Derivative Assets	27	—	—	442	469

Accounts payable and other (Note 16)
Commodities2	(1)	—	—	(291)	(292)
Foreign exchange	—	—	(11)	(183)	(194)
Interest rate	—	(21)	—	—	(21)
	(1)	(21)	(11)	(474)	(507)
Other long-term liabilities (Note 17)
Commodities2	(1)	—	—	(46)	(47)
Foreign exchange	—	—	—	(44)	(44)
Interest rate	—	(118)	—	—	(118)
	(1)	(118)	—	(90)	(209)
Total Derivative Liabilities	(2)	(139)	(11)	(564)	(716)
Total Derivatives	25	(139)	(11)	(122)	(247)

1Fair value equals carrying value.

2Includes purchases and sales of power and natural gas.

Schedule of Unrealized Gain (Loss) on Investments


year ended December 31	2025		2024		2023
(millions of Canadian $)	LMCI Restricted Investments1	Other Restricted Investments2	LMCI Restricted Investments1	Other Restricted Investments2	LMCI Restricted Investments1	Other Restricted Investments2

Net unrealized gains (losses)	167	(1)	218	9	179	13
Net realized gains (losses)3	21	22	3	2	(28)	—

2Unrealized and realized gains (losses) on other restricted investments are included in Interest income and other in the Company's Consolidated statement
of income.

3Realized gains (losses) on the sale of LMCI restricted investments are determined using the average cost basis.

Schedule of Realized Gain (Loss) on Investments


year ended December 31	2025		2024		2023
(millions of Canadian $)	LMCI Restricted Investments1	Other Restricted Investments2	LMCI Restricted Investments1	Other Restricted Investments2	LMCI Restricted Investments1	Other Restricted Investments2

Net unrealized gains (losses)	167	(1)	218	9	179	13
Net realized gains (losses)3	21	22	3	2	(28)	—

2Unrealized and realized gains (losses) on other restricted investments are included in Interest income and other in the Company's Consolidated statement
of income.

3Realized gains (losses) on the sale of LMCI restricted investments are determined using the average cost basis.

Schedule of Derivative Instruments - Balance Sheet and Income Statement Information

The following table details amounts recorded on the Consolidated balance sheet in relation to cumulative adjustments for fair value hedges included in the carrying amount of the hedged liabilities:


at December 31	Carrying Amount		Fair Value Hedging Adjustments1
(millions of Canadian $)	2025	2024	2025	2024


Long-term debt	(4,068)	(3,935)	(22)	98

1At December 31, 2025, adjustments for discontinued hedging relationships included in this balance was a liability of $39 million (2024 – $41 million).

The following summary does not include hedges of the net investment in foreign operations:


year ended December 31	2025	2024	2023
(millions of Canadian $)

Derivative Instruments Held for Trading1
Unrealized gains (losses) in the year
Commodities2	25	(71)	132
Foreign exchange (Note 21)	210	(266)	246
Interest rate	—	(71)	—
Realized gains (losses) in the year
Commodities	(10)	199	192
Foreign exchange (Note 21)	142	(152)	155
Interest rate	8	29	—
Derivative Instruments in Hedging Relationships
Realized gains (losses) in the year
Commodities	24	33	(2)
Foreign exchange	10	—	—
Interest rate	(30)	(52)	(43)

2In 2025, unrealized gains of $2 million were reclassified to Net Income (loss) from AOCI related to discontinued cash flow hedges (2024 – unrealized gains of $6 million; 2023 – nil).

The following table details amounts presented in the Consolidated statement of income in which the effects of fair value or cash flow hedging relationships were recorded:


year ended December 31	2025	2024	2023
(millions of Canadian $)

Fair Value Hedges
Interest rate contracts1
Hedged items	(179)	(126)	(98)
Derivatives designated as hedging instruments	(30)	(52)	(43)
Cash Flow Hedges
Reclassification of gains (losses) on derivative instruments from AOCI to Net income (loss)2,3
Commodities4	19	32	(85)
Foreign exchange5	(50)	—	—
Interest rate1	(12)	(12)	(12)

1Presented within Interest expense in the Consolidated statement of income.

2Refer to Note 25, Other comprehensive income (loss) and accumulated other comprehensive income (loss), for the components of OCI related to derivatives in cash flow hedging relationships.

3There are no amounts recognized in earnings that were excluded from effectiveness testing.

5Presented within Interest expense and Foreign exchange (gains) losses, net in the Consolidated statement of income.

Schedule of Components of OCI related to Derivatives in Cash Flow Hedging Relationships

The components of OCI (Note 25) related to the change in fair value of derivatives in cash flow hedging relationships before tax were as follows:


year ended December 31	2025	2024	2023
(millions of Canadian $, pre-tax)

Gains (losses) in fair value of derivative instruments recognized in OCI1
Commodities	7	46	—
Foreign exchange	(38)	—	—

	(31)	46	—

1No amounts have been excluded from the assessment of hedge effectiveness.

Schedule of Offsetting Assets

The following tables show the impact on the presentation of the fair value of derivative instrument assets and liabilities had the Company elected to present these contracts on a net basis:


at December 31, 2025	Gross Derivative Instruments	Amounts Available for Offset1	Net Amounts
(millions of Canadian $)

Derivative Instrument Assets
Commodities	508	(367)	141
Foreign exchange	66	(48)	18
Interest rate	25	(5)	20
	599	(420)	179
Derivative Instrument Liabilities
Commodities	(404)	367	(37)
Foreign exchange	(83)	48	(35)
Interest rate	(42)	5	(37)
	(529)	420	(109)

1Amounts available for offset do not include cash collateral pledged or received.


at December 31, 2024	Gross Derivative Instruments	Amounts Available for Offset1	Net Amounts
(millions of Canadian $)

Derivative Instrument Assets
Commodities	418	(290)	128
Foreign exchange	51	(49)	2

	469	(339)	130
Derivative Instrument Liabilities
Commodities	(339)	290	(49)
Foreign exchange	(238)	49	(189)
Interest rate	(139)	—	(139)
	(716)	339	(377)

1Amounts available for offset do not include cash collateral pledged or received.

Schedule of Offsetting Liabilities

The following tables show the impact on the presentation of the fair value of derivative instrument assets and liabilities had the Company elected to present these contracts on a net basis:


at December 31, 2025	Gross Derivative Instruments	Amounts Available for Offset1	Net Amounts
(millions of Canadian $)

Derivative Instrument Assets
Commodities	508	(367)	141
Foreign exchange	66	(48)	18
Interest rate	25	(5)	20
	599	(420)	179
Derivative Instrument Liabilities
Commodities	(404)	367	(37)
Foreign exchange	(83)	48	(35)
Interest rate	(42)	5	(37)
	(529)	420	(109)

1Amounts available for offset do not include cash collateral pledged or received.


at December 31, 2024	Gross Derivative Instruments	Amounts Available for Offset1	Net Amounts
(millions of Canadian $)

Derivative Instrument Assets
Commodities	418	(290)	128
Foreign exchange	51	(49)	2

	469	(339)	130
Derivative Instrument Liabilities
Commodities	(339)	290	(49)
Foreign exchange	(238)	49	(189)
Interest rate	(139)	—	(139)
	(716)	339	(377)

1Amounts available for offset do not include cash collateral pledged or received.

Schedule of Fair Value of Assets and Liabilities Measured on a Recurring Basis

The fair value of the Company's derivative assets and liabilities measured on a recurring basis, including both current and non‑current portions, were categorized as follows:


at December 31, 2025	Quoted Prices in Active Markets (Level I)	Significant Other Observable Inputs (Level II)1	Significant Unobservable Inputs (Level III)1	Total
(millions of Canadian $)

Derivative Instrument Assets
Commodities	154	279	75	508
Foreign exchange	—	66	—	66
Interest rate	—	25	—	25
Derivative Instrument Liabilities
Commodities	(151)	(252)	(1)	(404)
Foreign exchange	—	(83)	—	(83)
Interest rate	—	(42)	—	(42)
	3	(7)	74	70

1There were no transfers from Level II to Level III for the year ended December 31, 2025.


at December 31, 2024	Quoted Prices in Active Markets (Level I)	Significant Other Observable Inputs (Level II)1	Significant Unobservable Inputs (Level III)1	Total
(millions of Canadian $)

Derivative Instrument Assets
Commodities	126	214	78	418
Foreign exchange	—	51	—	51

Derivative Instrument Liabilities
Commodities	(116)	(217)	(6)	(339)
Foreign exchange	—	(238)	—	(238)
Interest rate	—	(139)	—	(139)
	10	(329)	72	(247)

1There were no transfers from Level II to Level III for the year ended December 31, 2024.

Schedule of Net Change in the Level III Fair Value Category

The following table presents the net change in fair value of derivative assets and liabilities classified in Level III of the fair
value hierarchy:


(millions of Canadian $, pre-tax)	2025	2024

Balance at beginning of year	72	(11)
Net gains (losses) included in Net income (loss)	21	54

Transfers to Level II	(4)	29
Purchases	(1)	—
Settlements	(14)	—
Balance at End of Year1	74	72

1Revenues include unrealized gains of $21 million attributed to derivatives in the Level III category that were still held at December 31, 2025 (2024 – unrealized gains of $54 million).

LEASES - (Lessor) Future Lease Payments to be Received Under Operating Leases (Details) - CAD ($) $ in Millions	Dec. 31, 2025	Dec. 31, 2024
Leases [Abstract]
Less than one year	$ 80	$ 107
One to two years	9	76
Two to three years	10	9
Three to four years	10	10
Four to five years	10	10
More than five years	45	55
Total payments to be received	$ 164	$ 267

LEASES - (Lessee) Maturities of Operating Lease Liabilities (Details) - CAD ($) $ in Millions	Dec. 31, 2025	Dec. 31, 2024
Leases [Abstract]
Less than one year	$ 73	$ 73
One to two years	66	73
Two to three years	63	66
Three to four years	63	64
Four to five years	59	63
More than five years	185	275
Total operating lease payments	509	614
Imputed interest	(78)	(103)
Operating lease liabilities	431	511
Operating lease, reported as accounts payable and other	61	60
Operating lease, reported as other long-term liabilities	$ 370	$ 451
Operating Lease, Liability, Current, Statement of Financial Position [Extensible List]	Accounts payable and other (Note 16)	Accounts payable and other (Note 16)
Operating Lease, Liability, Noncurrent, Statement of Financial Position [Extensible List]	Other Long-Term Liabilities (Note 17)	Other Long-Term Liabilities (Note 17)

LEASES - Component of Aggregate Investment in Leases (Details) - CAD ($) $ in Millions	Dec. 31, 2025	Dec. 31, 2024
Lessee, Lease, Description [Line Items]
Minimum lease payments	$ 29,764	$ 10,164
Unearned lease income	(20,397)	(7,323)
Lease receivable	9,367	2,841
Expected credit loss provision	(141)	(59)
Present value of unguaranteed residual value	140	28
Sales-type lease, net investment in lease, before allowance for credit loss	9,366	2,810
Current portion included in Other current assets (Note 7)	(1,256)	(333)
Sales-type lease, net investment in lease, before allowance for credit loss, noncurrent	8,110	2,477
Currency Translation Adjustments
Lessee, Lease, Description [Line Items]
Expected credit loss provision	$ (2)	$ 6

OTHER COMPREHENSIVE INCOME(LOSS) AND ACCUMULATED OTHER COMPREHENSIVE INCOME(LOSS)

12 Months Ended

Dec. 31, 2025

Equity [Abstract]

OTHER COMPREHENSIVE INCOME(LOSS) AND ACCUMULATED OTHER COMPREHENSIVE INCOME(LOSS)

Components of other comprehensive income (loss), including the portion attributable to non-controlling interests and related tax effects, were as follows:


year ended December 31, 2025	Before Tax Amount	Income Tax (Expense) Recovery	Net of Tax Amount
(millions of Canadian $)

Foreign currency translation gains and losses on net investment in foreign operations	(970)	(8)	(978)

Change in fair value of net investment hedges	1	—	1
Change in fair value of cash flow hedges (Note 27)	(31)	9	(22)
Reclassification to net income of (gains) losses on cash flow hedges	43	(12)	31
Unrealized actuarial gains (losses) on pension and other post-retirement benefit plans	104	(25)	79

Other comprehensive income (loss) on equity investments	2	—	2
Other Comprehensive Income (Loss)	(851)	(36)	(887)


year ended December 31, 2024	Before Tax Amount	Income Tax (Expense) Recovery	Net of Tax Amount
(millions of Canadian $)

Foreign currency translation gains and losses on net investment in foreign operations	1,582	20	1,602
Reclassification of foreign currency translation (gains) losses on net investment on disposal of foreign operations1	(25)	—	(25)
Change in fair value of net investment hedges	(23)	5	(18)
Change in fair value of cash flow hedges (Note 27)	46	(11)	35
Reclassification to net income of (gains) losses on cash flow hedges	(20)	4	(16)
Unrealized actuarial gains (losses) on pension and other post-retirement benefit plans	107	(24)	83
Reclassification to net income of actuarial (gains) losses on pension and other post-retirement benefit plans	(6)	—	(6)
Other comprehensive income (loss) on equity investments	230	(57)	173
Other Comprehensive Income (Loss)	1,891	(63)	1,828

1 Represents the controlling and non-controlling currency translation adjustment gains related to PNGTS. Refer to Note 29, Acquisitions and dispositions, for additional information.


year ended December 31, 2023	Before Tax Amount	Income Tax (Expense) Recovery	Net of Tax Amount
(millions of Canadian $)

Foreign currency translation gains and losses on net investment in foreign operations	(1,148)	7	(1,141)

Change in fair value of net investment hedges	23	(6)	17

Reclassification to net income of (gains) losses on cash flow hedges	97	(23)	74
Unrealized actuarial gains (losses) on pension and other post-retirement benefit plans	(15)	4	(11)

Other comprehensive income (loss) on equity investments	(283)	72	(211)
Other Comprehensive Income (Loss)	(1,326)	54	(1,272)

The changes in AOCI by component, net of tax, are as follows:


(millions of Canadian $)	Currency Translation Adjustments	Cash Flow Hedges	Pension and Other Post-Retirement Benefit Plan Adjustments	Equity Investments	Total

AOCI balance at January 1, 2023	441	(109)	(44)	667	955
Other comprehensive income (loss) before reclassifications1	(231)	—	(11)	(195)	(437)
Amounts reclassified from AOCI	—	74	—	(16)	58
Net current period other comprehensive income (loss)	(231)	74	(11)	(211)	(379)
Impact of non-controlling interest2	(527)	—	—	—	(527)
AOCI balance at December 31, 2023	(317)	(35)	(55)	456	49
Other comprehensive income (loss) before reclassifications1	692	35	83	188	998
Amounts reclassified from AOCI3	(15)	(16)	(6)	(15)	(52)
Net current period other comprehensive income (loss)	677	19	77	173	946
Impact of non-controlling interest4	(21)	—	—	—	(21)
Impact of spinoff of Liquids Pipelines business5	(741)	—	—	—	(741)
AOCI balance at December 31, 2024	(402)	(16)	22	629	233
Other comprehensive income (loss) before reclassifications1	(466)	(22)	79	3	(406)
Amounts reclassified from AOCI6	—	31	—	(1)	30
Net current period other comprehensive income (loss)	(466)	9	79	2	(376)
Impact of non-controlling interest2	348	—	—	—	348
Impact of spinoff of Liquids Pipelines business5	542	—	—	—	542
AOCI balance at December 31, 2025	22	(7)	101	631	747

1Other comprehensive income (loss) before reclassifications of currency translation adjustments are net of non-controlling interest losses of $511 million (2024 – gains of $903 million; 2023 – losses of $366 million).

2Represents the AOCI and adjustment attributable to the 40 per cent non-controlling equity interest in Columbia Gas and Columbia Gulf upon its sale in October 2023. Refer to Note 29, Acquisitions and dispositions and Note 2, Accounting policies, for additional information.

3Includes the controlling interest of the AOCI attributable to PNGTS recognized in Net gain (loss) on sale of assets upon the sale of PNGTS in August 2024. Refer to Note 29, Acquisitions and dispositions, for additional information.

4Represents the AOCI attributable to the CFE's 13.01 per cent non-controlling equity interest in TGNH. Refer to Note 29, Acquisitions and dispositions, for additional information.

5Represents the AOCI and adjustment attributable to the Spinoff Transaction. Refer to Note 4, Discontinued operations and Note 2, Accounting policies, for additional information.

6Gains related to cash flow hedges reported in AOCI and expected to be reclassified to net income in the next 12 months are estimated to be $9 million ($7 million, net of tax) at December 31, 2025. These estimates assume constant commodity prices, interest rates and foreign exchange rates over time; however, the amounts reclassified will vary based on the actual value of these factors at the date of settlement.

Details about reclassifications out of AOCI into the Consolidated statement of income were as follows:


year ended December 31	Amounts reclassified from AOCI			Affected line item in the Consolidated statement of income
(millions of Canadian $)	2025	2024	2023

Cash flow hedges
Commodities	19	32	(85)	Revenues (Power and Energy Solutions)
Foreign Exchange	(50)	—	—	Interest expense and Foreign exchange gains (losses), net
Interest rate	(12)	(12)	(12)	Interest expense
	(43)	20	(97)	Total before tax
	12	(4)	23	Income tax (expense) recovery
	(31)	16	(74)	Net of tax
Pension and other post-retirement benefit plan adjustments
Amortization of actuarial gains (losses)	—	6	—	Plant operating costs and other1

	—	6	—	Total before tax
	—	—	—	Income tax (expense) recovery
	—	6	—	Net of tax
Equity investments
Equity income (loss)	3	19	22	Income (loss) from equity investments
	(2)	(4)	(6)	Income tax (expense) recovery
	1	15	16	Net of tax
Currency translation adjustments
Foreign currency translation gains on disposal of foreign operations	—	15	—	Net gain (loss) on sale of assets
	—	—	—	Income tax (expense) recovery
	—	15	—	Net of tax

1These AOCI components are included in the computation of net benefit cost (recovery). Refer to Note 26, Employee post-retirement benefits, for additional information.

LONG-TERM DEBT

12 Months Ended

Dec. 31, 2025

Debt Disclosure [Abstract]

LONG-TERM DEBT


at December 31		2025			2024
	Maturity Dates	Outstanding	Interest Rate1		Outstanding	Interest Rate1
(millions of Canadian $, unless otherwise noted)

TRANSCANADA PIPELINES LIMITED



Medium Term Notes
Canadian	2026 to 2055	14,241	4.8	%	13,141	4.7	%
Senior Unsecured Notes
U.S. (2025 – US$10,850 and 2024 – US$11,792)	2028 to 2049	14,882	5.5	%	16,985	5.5	%
		29,123			30,126
NOVA GAS TRANSMISSION LTD.



Medium Term Notes
Canadian	2026 to 2030	417	7.1	%	504	7.4	%
U.S. (2025 and 2024 – US$33)	2026	45	7.5	%	47	7.5	%
		462			551






COLUMBIA PIPELINES OPERATING COMPANY LLC
Senior Unsecured Notes
U.S. (2025 and 2024 – US$6,500)	2030 to 2063	8,915	6.2	%	9,362	6.0	%
COLUMBIA PIPELINES HOLDING COMPANY LLC
Senior Unsecured Notes
U.S. (2025 – US$2,650; 2024 – US$1,900)	2026 to 2034	3,634	5.7	%	2,737	5.9	%
ANR PIPELINE COMPANY
Senior Unsecured Notes
U.S. (2025 – US$1,640; 2024 – US$1,047)	2026 to 2037	2,249	4.3	%	1,509	3.7	%
TC PIPELINES, LP
Senior Unsecured Notes
U.S. (2025 – US$500 and 2024 – US$850)	2027	686	4.0	%	1,224	4.2	%
GAS TRANSMISSION NORTHWEST LLC


Senior Unsecured Notes
U.S. (2025 and 2024 – US$375)	2030 to 2035	514	4.4	%	540	4.4	%
GREAT LAKES GAS TRANSMISSION LIMITED PARTNERSHIP
Unsecured Term Loan
U.S. (2025 – US$205; 2024 – nil)	2028	281	5.0	%	—	—
Senior Unsecured Notes
U.S. (2025 – US$83; 2024 – US$104)	2028 to 2030	114	7.6	%	150	7.6	%
		395			150
TC ENERGÍA MEXICANA, S. DE R.L. DE C.V.
Senior Unsecured Term Loan
U.S. (2025 – US$693; 2024 – US$1,370)	2028	950	6.3	%	1,973	7.2	%


		46,928			48,172
Current portion of long-term debt		(1,545)			(2,955)
Unamortized debt discount and issue costs		(251)			(252)
Fair value adjustments2		115			11
		45,247			44,976

Long-Term Debt Issued

The Company issued long-term debt over the three years ended December 31, 2025 as follows:

(millions of Canadian $, unless otherwise noted)

Company

Issue Date

Type

Maturity Date

Amount

Interest Rate

TRANSCANADA PIPELINES LIMITED

November 2025

Medium Term Notes

November 2055

850

5.13

February 2025

Medium Term Notes

February 2035

1,000

4.58

August 2024

Term Loan1

August 2024

US 1,242

Floating

May 2023

Senior Unsecured Term Loan2

May 2026

US 1,024

Floating

March 2023

Senior Unsecured Notes3

March 2026

US 850

6.20

March 2023

Senior Unsecured Notes3

March 2026

US 400

Floating

March 2023

Medium Term Notes

July 2030

1,250

5.28

March 2023

Medium Term Notes3

March 2026

600

5.42

March 2023

Medium Term Notes3

March 2026

400

Floating

COLUMBIA PIPELINES HOLDING COMPANY LLC

November 2025

Senior Unsecured Notes

November 2032

US 750

5.00

September 2024

Senior Unsecured Notes

October 2031

US 400

5.10

January 2024

Senior Unsecured Notes

January 2034

US 500

5.68

August 2023

Senior Unsecured Notes

August 2028

US 700

6.04

August 2023

Senior Unsecured Notes

August 2026

US 300

6.06

GREAT LAKES GAS TRANSMISSION LIMITED PARTNERSHIP

October 2025

Unsecured Term Loan

October 2028

US 205

Floating

ANR PIPELINE COMPANY

September 2025

Senior Unsecured Notes

September 2031

US 250

5.23

September 2025

Senior Unsecured Notes

September 2035

US 350

5.69

COLUMBIA PIPELINES OPERATING COMPANY LLC

March 2025

Senior Unsecured Notes

February 2035

US 550

5.44

March 2025

Senior Unsecured Notes

February 2055

US 450

5.96

September 2024

Senior Unsecured Notes

October 2054

US 400

5.70

August 2023

Senior Unsecured Notes

November 2033

US 1,500

6.04

August 2023

Senior Unsecured Notes

November 2053

US 1,250

6.54

August 2023

Senior Unsecured Notes

August 2030

US 750

5.93

August 2023

Senior Unsecured Notes

August 2043

US 600

6.50

August 2023

Senior Unsecured Notes

August 2063

US 500

6.71

GAS TRANSMISSION NORTHWEST LLC

June 2023

Senior Unsecured Notes

June 2030

US 50

4.92

TC ENERGÍA MEXICANA, S. DE R.L. DE C.V.

January 2023

Senior Unsecured Term Loan

January 2028

US 1,800

Floating

January 2023

Senior Unsecured Revolving Credit Facility

January 2028

US 500

Floating

2Fully repaid and retired in September 2023.

3In October 2024, callable notes were repaid and retired at par.

Long-Term Debt Retired/Repaid

The Company retired/repaid long-term debt over the three years ended December 31, 2025 as follows:

(millions of Canadian $, unless otherwise noted)

Company

Retirement/Repayment Date

Type

Amount

Interest Rate

TRANSCANADA PIPELINES LIMITED

November 2025

Senior Unsecured Notes

US 850

4.88

October 2025

Senior Unsecured Notes

US 92

7.06

July 2025

Medium Term Notes

750

3.30

October 2024

Senior Unsecured Notes

US 1,250

1.00

October 2024

Senior Unsecured Notes1

US 850

6.20

October 2024

Senior Unsecured Notes2

US 739

2.50

October 2024

Senior Unsecured Notes2

US 441

4.88

October 2024

Senior Unsecured Notes1

US 400

Floating

October 2024

Senior Unsecured Notes2

US 313

4.75

October 2024

Senior Unsecured Notes2

US 201

5.00

October 2024

Senior Unsecured Notes2

US 180

5.10

October 2024

Medium Term Notes1

600

5.42

October 2024

Medium Term Notes2

575

4.18

October 2024

Medium Term Notes1

400

Floating

August 2024

Term Loan3

US 1,242

Floating

June 2024

Medium Term Notes

750

Floating

October 2023

Senior Unsecured Notes

US 625

3.75

September 2023

Senior Unsecured Term Loan

US 1,024

Floating

July 2023

Medium Term Notes

750

3.69

ANR PIPELINE COMPANY

June 2025

Senior Unsecured Notes

US 7

7.00

February 2024

Senior Unsecured Notes

US 125

7.38

NOVA GAS TRANSMISSION LTD.

May 2025

Medium Term Notes

8.90

March 2024

Debentures

100

9.90

April 2023

Debentures

US 200

7.88

COLUMBIA PIPELINES OPERATING COMPANY LLC

March 2025

Senior Unsecured Notes

US 1,000

4.50

TC PIPELINES, LP

March 2025

Senior Unsecured Notes

US 350

4.38

TC ENERGÍA MEXICANA, S. DE R.L. DE C.V.

Various 2025

Senior Unsecured Term Loan

US 677

Floating

Various 2024

Senior Unsecured Term Loan

US 430

Floating

Various 2024

Senior Unsecured Revolving Credit Facility

US 185

Floating

Various 2023

Senior Unsecured Revolving Credit Facility

US 315

Floating

TUSCARORA GAS TRANSMISSION COMPANY

November 2023

Unsecured Term Loan

US 32

Floating

1In October 2024, callable notes were repaid and retired at par.

2In October 2024, TCPL purchased and cancelled notes at a 7.73 per cent weighted average discount, as a settlement of cash tender offers.

On February 5, 2026, TCPL retired $241 million of medium term notes bearing interest at a fixed rate of 8.29 per cent.

In October 2024, TCPL commenced and completed its cash tender offers to purchase and cancel certain senior unsecured notes and medium term notes at a 7.73 per cent weighted average discount. In addition, the Company repaid and retired outstanding callable notes at par. These extinguishments of debt resulted in a pre-tax net gain of $228 million, primarily due to the fair value discount and recognition of unamortized debt issue costs related to these notes. The net gain on debt extinguishment was recorded in Interest expense in the Consolidated statement of income.

Principal Repayments

At December 31, 2025, principal repayments for the next five years on the Company's long-term debt are approximately as follows:


(millions of Canadian $)	2026	2027	2028	2029	2030

Principal repayments on long-term debt	1,545	3,122	5,196	1,309	4,573

Interest Expense


year ended December 31	2025	2024	2023
(millions of Canadian $)

Interest on long-term debt	2,537	2,800	2,562
Interest on junior subordinated notes	678	638	617
Interest on short-term debt	95	60	165
Capitalized interest	(10)	(191)	(187)
Amortization and other financial charges1	107	158	106
Gain on debt extinguishment	—	(228)	—
	3,407	3,237	3,263
Interest allocated to discontinued operations (Note 4)	—	(218)	(297)
	3,407	3,019	2,966

The Company made interest payments of $3,284 million in 2025 (2024 – $3,398 million; 2023 – $2,931 million) on long-term debt, junior subordinated notes and short-term debt, net of interest capitalized.

OTHER LONG-TERM ASSETS

12 Months Ended

Dec. 31, 2025

Intangible Assets, Net (Excluding Goodwill) [Abstract]

OTHER LONG-TERM ASSETS


at December 31	2025	2024
(millions of Canadian $)

Employee post-retirement benefits (Note 26)	967	758
Contract assets (Note 6)	627	608
Deferred income tax assets (Note 18)	356	428
Fair value of derivative instruments (Note 27)	161	122
Capital projects in development	81	164


Other	290	330
	2,482	2,410

GOODWILL - Narrative (Details) $ in Millions, $ in Millions	Dec. 31, 2025 CAD ($)	Dec. 31, 2025 USD ($)	Dec. 31, 2024 CAD ($)	Dec. 31, 2024 USD ($)
Goodwill recorded on Company's acquisitions in the U.S.
Goodwill	$ 13,016	$ 9,490	$ 13,670	$ 9,490
Columbia
Goodwill recorded on Company's acquisitions in the U.S.
Goodwill	$ 10,082	$ 7,351	$ 10,588	$ 7,351

- Definition

Amount, after accumulated impairment loss, of asset representing future economic benefit arising from other asset acquired in business combination or from joint venture formation or both, that is not individually identified and separately recognized.

+ References

Reference 1: http://www.xbrl.org/2003/role/exampleRef
-Topic 350
-SubTopic 20
-Name Accounting Standards Codification
-Section 55
-Paragraph 24
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482548/350-20-55-24

Reference 2: http://www.xbrl.org/2003/role/exampleRef
-Topic 805
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 8
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147479328/805-10-50-8

Reference 3: http://www.xbrl.org/2003/role/exampleRef
-Topic 805
-SubTopic 10
-Name Accounting Standards Codification
-Section 55
-Paragraph 41
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147479303/805-10-55-41

Reference 4: http://www.xbrl.org/2003/role/exampleRef
-Topic 805
-SubTopic 740
-Name Accounting Standards Codification
-Section 55
-Paragraph 13
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147478064/805-740-55-13

Reference 5: http://www.xbrl.org/2003/role/exampleRef
-Topic 805
-SubTopic 10
-Name Accounting Standards Codification
-Section 55
-Paragraph 39
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147479303/805-10-55-39

Reference 6: http://www.xbrl.org/2003/role/exampleRef
-Topic 280
-SubTopic 10
-Name Accounting Standards Codification
-Section 55
-Paragraph 49
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482785/280-10-55-49

Reference 7: http://www.xbrl.org/2003/role/exampleRef
-Topic 820
-SubTopic 10
-Name Accounting Standards Codification
-Section 55
-Paragraph 100
-Subparagraph (d)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482078/820-10-55-100

Reference 8: http://www.xbrl.org/2003/role/exampleRef
-Topic 852
-SubTopic 10
-Name Accounting Standards Codification
-Section 55
-Paragraph 10
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147481372/852-10-55-10

Reference 9: http://www.xbrl.org/2003/role/disclosureRef
-Topic 210
-SubTopic 10
-Name Accounting Standards Codification
-Section S99
-Paragraph 1
-Subparagraph (SX 210.5-02(15))
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480566/210-10-S99-1

Reference 10: http://www.xbrl.org/2003/role/disclosureRef
-Topic 350
-SubTopic 20
-Name Accounting Standards Codification
-Section 45
-Paragraph 1
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482598/350-20-45-1

Reference 11: http://www.xbrl.org/2009/role/commonPracticeRef
-Topic 350
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 1
-Subparagraph (a)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482573/350-20-50-1

Reference 12: http://www.xbrl.org/2009/role/commonPracticeRef
-Topic 350
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 1
-Subparagraph (h)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482573/350-20-50-1

Reference 13: http://www.xbrl.org/2003/role/disclosureRef
-Topic 942
-SubTopic 210
-Name Accounting Standards Codification
-Section S99
-Paragraph 1
-Subparagraph (SX 210.9-03(10)(1))
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147478546/942-210-S99-1

Reference 14: http://www.xbrl.org/2009/role/commonPracticeRef
-Topic 805
-SubTopic 30
-Name Accounting Standards Codification
-Section 50
-Paragraph 4
-Subparagraph (b)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147479581/805-30-50-4

+ Details

- Definition

Line items represent financial concepts included in a table. These concepts are used to disclose reportable information associated with domain members defined in one or many axes to the table.

+ References

Reference 1: http://www.xbrl.org/2003/role/exampleRef
-Topic 350
-SubTopic 20
-Name Accounting Standards Codification
-Section 55
-Paragraph 24
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482548/350-20-55-24

Reference 2: http://www.xbrl.org/2003/role/disclosureRef
-Topic 350
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 2
-Subparagraph (b)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482573/350-20-50-2

Reference 3: http://www.xbrl.org/2003/role/disclosureRef
-Topic 350
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 1
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482573/350-20-50-1

Reference 4: http://www.xbrl.org/2003/role/disclosureRef
-Topic 350
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 1
-Subparagraph (a)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482573/350-20-50-1

Reference 5: http://www.xbrl.org/2003/role/disclosureRef
-Topic 350
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 1
-Subparagraph (b)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482573/350-20-50-1

Reference 6: http://www.xbrl.org/2003/role/disclosureRef
-Topic 350
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 1
-Subparagraph (c)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482573/350-20-50-1

Reference 7: http://www.xbrl.org/2003/role/disclosureRef
-Topic 350
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 1
-Subparagraph (d)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482573/350-20-50-1

Reference 8: http://www.xbrl.org/2003/role/disclosureRef
-Topic 350
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 1
-Subparagraph (e)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482573/350-20-50-1

Reference 9: http://www.xbrl.org/2003/role/disclosureRef
-Topic 350
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 1
-Subparagraph (f)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482573/350-20-50-1

Reference 10: http://www.xbrl.org/2003/role/disclosureRef
-Topic 350
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 1
-Subparagraph (g)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482573/350-20-50-1

Reference 11: http://www.xbrl.org/2003/role/disclosureRef
-Topic 350
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 1
-Subparagraph (h)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482573/350-20-50-1

Reference 12: http://www.xbrl.org/2003/role/disclosureRef
-Topic 350
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 1A
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482573/350-20-50-1A

+ Details

LEASES - (Lessee) Narrative (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024
Lessee, Lease, Description [Line Items]
Operating lease termination period	1 year
Right-of-use asset	$ 402	$ 480
Operating Lease, Right-of-Use Asset, Statement of Financial Position [Extensible Enumeration]	Plant, Property and Equipment (Note 8)	Plant, Property and Equipment (Note 8)
Minimum
Lessee, Lease, Description [Line Items]
Operating leases optional renewable terms	1 year
Maximum
Lessee, Lease, Description [Line Items]
Operating leases optional renewable terms	25 years

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - Derivatives Designated as a Net Investment Hedge (Details) $ in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2025 CAD ($)	Dec. 31, 2024 CAD ($)	Dec. 31, 2025 USD ($)	Dec. 31, 2024 USD ($)
Derivative [Line Items]
Fair Value	$ 70	$ (247)
Designated as a net investment hedge
Derivative [Line Items]
Fair Value		(11)
U.S. dollar cross-currency interest rate swaps (maturing 2025) \| Designated as a net investment hedge
Derivative [Line Items]
Fair Value	0	(11)
U.S. dollar cross-currency interest rate swaps (maturing 2025) \| Designated as a net investment hedge \| US$ denominated
Derivative [Line Items]
Notional Amount			$ 0	$ 100
Net realized gains related to the interest component	$ 1	$ 1

EQUITY INVESTMENTS - Summarized Financial Information of Equity Investments (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Income
Revenues	$ 15,239	$ 13,771	$ 13,267
Operating and other expenses	(8,477)	(7,985)	(7,380)
Net income	3,519	4,698	2,922
Income (loss) from equity investments	1,274	1,558	1,310
Balance Sheet
Current assets	6,316	5,733
Current liabilities	(9,959)	(10,511)
Group of Investees
Income
Revenues	7,493	6,962	6,197
Operating and other expenses	(4,412)	(3,783)	(3,343)
Net income	2,405	3,026	$ 2,457
Balance Sheet
Current assets	3,438	3,959
Non-current assets	47,233	44,835
Current liabilities	(1,888)	(2,111)
Non-current liabilities	$ (22,389)	$ (21,729)

LEASES - (Lessee) Operating Lease Cost and Other Information (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024
Operating lease cost
Operating lease cost	$ 112	$ 117
Sublease income	(5)	(6)
Net operating lease cost	107	111
Cash paid for amounts included in the measurement of operating lease liabilities	76	74
ROU assets obtained in exchange for new operating lease liabilities	$ 18	$ 96
Weighted average remaining lease term	11 years	13 years
Weighted average discount rate	3.40%	3.30%

ACCOUNTS PAYABLE AND OTHER

12 Months Ended

Dec. 31, 2025

Payables and Accruals [Abstract]

ACCOUNTS PAYABLE AND OTHER


at December 31	2025	2024
(millions of Canadian $)

Trade payables	3,263	3,699
Regulatory liabilities (Note 12)	532	353
Fair value of derivative instruments (Note 27)	380	507
Factoring arrangement (Note 9)	351	—
Gas transportation and exchange payable	158	118
Emissions expense payable	91	101
Operating lease liabilities (Note 9)	61	60
Contract liabilities (Note 6)	46	30
Income tax liabilities	38	143
Other	354	286
	5,274	5,297

Consolidated balance sheet $ in Millions, $ in Millions	Dec. 31, 2025 CAD ($)	Dec. 31, 2024 CAD ($)
Current Assets
Cash and cash equivalents	$ 168	$ 801
Accounts receivable	2,794	2,611
Inventories	782	747
Other current assets (Note 7)	2,375	1,339
Current assets of discontinued operations (Note 4)	197	235
Total current assets	6,316	5,733
Plant, Property and Equipment (Note 8)	71,054	77,501
Net Investment in Leases (Note 9)	8,110	2,477
Equity Investments (Note 10)	11,358	10,636
Restricted Investments	3,502	2,998
Regulatory Assets (Note 12)	2,913	2,682
Goodwill (Note 13)	13,016	13,670
Other Long-Term Assets (Note 14)	2,482	2,410
Long-Term Assets of Discontinued Operations (Note 4)	0	136
Total assets	118,751	118,243
Current Liabilities
Notes payable (Note 15)	1,200	387
Accounts payable and other (Note 16)	5,274	5,297
Dividends payable	901	874
Accrued interest	858	828
Current portion of long-term debt (Note 19)	1,545	2,955
Current liabilities of discontinued operations (Note 4)	181	170
Total current liabilities	9,959	10,511
Regulatory Liabilities (Note 12)	5,841	5,303
Other Long-Term Liabilities (Note 17)	1,034	1,051
Deferred Income Tax Liabilities (Note 18)	7,677	6,884
Long-Term Debt (Note 19)	45,247	44,976
Junior Subordinated Notes (Note 20)	12,094	11,048
Long-Term Liabilities of Discontinued Operations (Note 4)	0	110
Total liabilities	81,852	79,883
EQUITY
Common shares, no par value (Note 23)	30,218	30,101
Preferred shares (Note 24)	2,255	2,499
Retained earnings (Accumulated deficit)	(5,925)	(5,241)
Accumulated other comprehensive income (loss) (Note 25)	747	233
Controlling Interests	27,295	27,592
Non-Controlling Interests (Note 22)	9,604	10,768
Total Equity	36,899	38,360
Total Liabilities and Equity	$ 118,751	$ 118,243

DISCONTINUED OPERATIONS - Narrative (Details) $ in Millions, $ in Billions			3 Months Ended		12 Months Ended
	Aug. 28, 2024 CAD ($) entity	Aug. 28, 2024 USD ($)	Dec. 31, 2025 CAD ($)	Jun. 30, 2025 CAD ($)	Dec. 31, 2025 CAD ($)	Dec. 31, 2024 CAD ($)	Dec. 31, 2023 CAD ($)
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Asset impairment charge and other						$ 21	$ (4)
Current assets of discontinued operations			$ 197		$ 197	235
Outstanding			46,928		46,928	48,172
Stockholders' equity			36,899		36,899	38,360	39,008
Retained earnings (Accumulated deficit)			(5,925)		(5,925)	(5,241)
Accumulated other comprehensive income (loss) (Note 25)			$ 747		747	233
Reclassification of net investment hedge losses related to the spinoff				$ 542
South Bow Canadian Infrastructure Holdings Ltd
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Number of legal entities (in subsidiaries) \| entity	2
Disposed of by sale
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Pre tax separation, before reclassification					0	197	40
Pre tax separation, before reclassification, after tax						167	$ 34
Amount		$ 1.3
Stockholders' equity						3,691
Retained earnings (Accumulated deficit)						(2,950)
Accumulated other comprehensive income (loss) (Note 25)						$ (741)
Reclassification of net investment hedge losses related to the spinoff					542
Disposed of by sale \| South Bow Canadian Infrastructure Holdings Ltd
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Outstanding	$ 7,900
Net proceeds	$ 6,200
Disposed of by sale \| South Bow Canadian Infrastructure Holdings Ltd
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Transition services agreement, term			2 years
Recognition of the settlement a net loss from discontinued operations					183
Sale consideration			$ 105		105
Current assets of discontinued operations			$ 17		17
Disposed of by sale \| Liquids Pipelines Segment
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Asset impairment charge and other					$ 29

Consolidated statement of income - CAD ($) shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Revenues	$ 15,239	$ 13,771	$ 13,267
Income (Loss) from Equity Investments (Note 10)	1,274	1,558	1,310
Impairment of equity investment (Note 10)	0	0	(2,100)
Operating and Other Expenses
Plant operating costs and other	4,619	4,413	4,073
Commodity purchases resold	208	217	80
Property taxes	881	820	781
Depreciation and amortization	2,769	2,535	2,446
Total operating and other expenses	8,477	7,985	7,380
Net Gain (Loss) on Sale of Assets (Note 29)	0	620	0
Financial Charges
Interest expense (Note 19)	3,407	3,019	2,966
Allowance for funds used during construction	(453)	(784)	(575)
Foreign exchange (gains) losses, net (Note 21)	(157)	147	(320)
Interest income and other	(205)	(324)	(272)
Total financial charges	2,592	2,058	1,799
Income (Loss) from Continuing Operations before Income Taxes	5,444	5,906	3,298
Income Tax Expense (Recovery) from Continuing Operations (Note 18)
Current	367	495	864
Deferred	771	427	(22)
Income Tax Expense	1,138	922	842
Net Income (Loss) from Continuing Operations	4,306	4,984	2,456
Net Income (Loss) from Discontinued Operations, Net of Tax (Note 4)	(212)	395	612
Net Income (Loss)	4,094	5,379	3,068
Net income (loss) attributable to non-controlling interests (Note 22)	575	681	146
Net Income (Loss) Attributable to Controlling Interests	3,519	4,698	2,922
Preferred share dividends	119	104	93
Net income (loss) attributable to controlling interests from continuing operations	3,731	4,303	2,310
Net income (loss) attributable to common shares from continuing operations	3,612	4,199	2,217
Net income (loss) attributable to common shares from continuing operations	$ 3,400	$ 4,594	$ 2,829
Net Income (Loss) per Common Share - Basic and Diluted (Note 23)
Continuing operations, Basic (in dollars per share)	$ 3.47	$ 4.05	$ 2.15
Continuing operations, Diluted (in dollars per share)	3.47	4.05	2.15
Discontinued operations, Basic (in dollars per share)	(0.20)	0.38	0.60
Discontinued operations, Diluted (in dollars per share)	(0.20)	0.38	0.60
Basic (in dollars per share)	3.27	4.43	2.75
Diluted (in dollars per share)	3.27	4.43	2.75
Dividends Declared per Common Share (in dollars per share)	$ 3.40	$ 3.7025	$ 3.72
Weighted Average Number of Common Shares (millions) (Note 23)
Basic (in shares)	1,040	1,038	1,030
Diluted (in shares)	1,040	1,038	1,030
Operating segments
Revenues	$ 15,225	$ 13,763
Corporate
Revenues	14	8	$ 0
Income (Loss) from Equity Investments (Note 10)	0	0	0
Impairment of equity investment (Note 10)			0
Operating and Other Expenses
Depreciation and amortization	0	5	6
Canadian Natural Gas Pipelines
Revenues	5,785	5,600	5,173
Canadian Natural Gas Pipelines \| Operating segments
Revenues	5,785	5,600	5,173
Income (Loss) from Equity Investments (Note 10)	112	34	220
Impairment of equity investment (Note 10)			(2,100)
Operating and Other Expenses
Depreciation and amortization	1,523	1,382	1,325
U.S. Natural Gas Pipelines
Revenues	7,145	6,339	6,229
U.S. Natural Gas Pipelines \| Operating segments
Revenues	7,145	6,339	6,229
Income (Loss) from Equity Investments (Note 10)	301	341	324
Impairment of equity investment (Note 10)			0
Operating and Other Expenses
Depreciation and amortization	1,037	955	934
Mexico Natural Gas Pipelines
Revenues	1,450	870	846
Mexico Natural Gas Pipelines \| Operating segments
Revenues	1,450	870	846
Income (Loss) from Equity Investments (Note 10)	94	283	78
Impairment of equity investment (Note 10)			0
Operating and Other Expenses
Depreciation and amortization	96	92	89
Power and Energy Solutions
Revenues	845	954	1,019
Power and Energy Solutions \| Operating segments
Revenues	845	954	1,019
Income (Loss) from Equity Investments (Note 10)	767	900	688
Impairment of equity investment (Note 10)			0
Operating and Other Expenses
Depreciation and amortization	$ 113	$ 101	$ 92

LOANS WITH AFFILIATES	12 Months Ended
LOANS WITH AFFILIATES	Dec. 31, 2025
Receivables [Abstract]
LOANS WITH AFFILIATES	LOANS WITH AFFILIATES Related party transactions are conducted in the normal course of business and are measured at the exchange amount, which is the amount of consideration established and agreed to by the related parties. Coastal GasLink Pipeline Limited Partnership TC Energy holds a 35 per cent equity interest in Coastal GasLink LP and operates the Coastal GasLink pipeline. Subordinated Loan Agreement TC Energy has a subordinated loan agreement with Coastal GasLink LP under which the Company advances non-revolving loans at floating market-based interest rates to Coastal GasLink LP to fund capital costs associated with the Coastal GasLink Pipeline project. Coastal GasLink LP partners, including TC Energy, are contractually obligated to contribute equity to Coastal GasLink LP to ultimately fund the settlement of amounts outstanding under the subordinated loan agreement, with an expectation that such equity will predominantly be contributed by TC Energy. Because of this expectation, amounts drawn under the subordinated loan agreement have been accounted for as in-substance equity contributions, presented as Contributions to equity investments in the Company’s Consolidated statement of cash flows. Repayments of amounts owed by Coastal GasLink LP to the Company have been accounted for as in-substance equity distributions, presented in Other distributions from equity investments in the Company's Consolidated statement of cash flows. On December 17, 2024, following the declared commercial in-service of the pipeline, Coastal GasLink LP repaid the $3,147 million balance owing to TC Energy under the subordinated loan agreement. The Company's share of equity contributions required to fund Coastal GasLink LP's repayment of the outstanding loan balance amounted to $3,137 million. Unused committed capacity available for use by Coastal GasLink LP at December 31, 2025 was $163 million (December 31, 2024 – $228 million). Subordinated Demand Revolving Credit Facility Agreement The Company has a subordinated demand revolving credit facility agreement with Coastal GasLink LP to provide additional short-term liquidity and funding flexibility to projects under construction. Facilities available through this agreement bear interest at floating market-based rates and have a combined capacity of $120 million at December 31, 2025 and 2024 with no outstanding balances at December 31, 2025 and 2024. Sur de Texas TC Energy holds a 60 per cent equity interest in a joint venture with IEnova Infraestructura Marina Holding B.V. (IEnova) to own the Sur de Texas pipeline, operated by TC Energy. On December 15, 2025, TC Energía Mexicana, S. de R.L. de C.V. (TCEM) entered into a subordinated demand revolving credit facility to borrow funds from the joint venture at a floating interest rate. The facility has a capacity of US$270 million, maturing in December 2028. At December 31, 2025, the unused capacity available for use by TCEM was $259 million (US$189 million) and the outstanding balance of the loan was $111 million (US$81 million), which is presented in Other long-term liabilities on the Company's Consolidated balance sheet.

CHANGES IN OPERATING WORKING CAPITAL (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
CHANGES IN OPERATING WORKING CAPITAL
(Increase) decrease in Accounts receivable	$ (332)	$ (13)	$ (394)
(Increase) decrease in Inventories	(55)	(16)	(56)
(Increase) decrease in Other current assets	(159)	(97)	618
Increase (decrease) in Accounts payable and other	13	365	(206)
Increase (decrease) in Accrued interest	30	(40)	245
(Increase) Decrease in Operating Working Capital	$ (503)	$ 199	$ 207

INCOME TAXES - Reconciliation of Income Tax Expense (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Amount
Income before income taxes	$ 5,444	$ 5,906	$ 3,298
Expected income tax expense	817	886	495
Other	(5)	16	(18)
Income Tax Expense	$ 1,138	$ 922	$ 842
Percentage
Canadian federal statutory income tax rate	15.00%	15.00%	15.00%
Other	(0.10%)	0.30%	(0.50%)
Income Tax Expense	20.90%	15.70%	25.70%
Canada
Amount
Income tax differential related to regulated operations	$ (24)	$ (68)	$ (108)
Non-taxable capital (gain) loss	(20)	12	113
Changes in valuation allowances	0	3	114
Effect of cross-border taxes	(25)	(23)	(27)
Canadian provincial taxes	$ 143	$ 103	$ 22
Percentage
Income tax differential related to regulated operations	(0.40%)	(1.20%)	(3.30%)
Non-taxable capital (gain) loss	(0.40%)	0.20%	3.40%
Changes in valuation allowances	0.00%	0.10%	3.50%
Effect of cross-border taxes	(0.50%)	(0.40%)	(0.80%)
Canadian provincial taxes	2.60%	1.70%	0.70%
United States
Amount
Rate differential	$ 177	$ 168	$ 136
State and local income taxes, net of federal effect	(28)	123	76
Income from non-controlling interests	(125)	(121)	(31)
Other	$ (16)	$ (12)	$ (8)
Percentage
Rate differential	3.30%	2.80%	4.10%
State and local income taxes, net of federal effect	(0.50%)	2.10%	2.30%
Income from non-controlling interests	(2.30%)	(2.00%)	(0.90%)
Other	(0.30%)	(0.20%)	(0.20%)
Mexico
Amount
Income tax differential related to regulated operations	$ (45)	$ (109)	$ (79)
Rate differential	57	234	94
Withholding tax	41	35	12
Other	8	2	2
Mexico foreign exchange exposure	213	(246)	163
Income from equity investments	$ (28)	$ (84)	$ (23)
Percentage
Income tax differential related to regulated operations	(0.80%)	(1.80%)	(2.40%)
Rate differential	1.00%	4.00%	2.90%
Withholding tax	0.80%	0.60%	0.40%
Other	0.10%	0.00%	0.10%
Mexico foreign exchange exposure	3.90%	(4.20%)	4.90%
Income from equity investments	(0.50%)	(1.40%)	(0.70%)
Other foreign jurisdictions
Amount
Rate differential	$ (2)	$ 3	$ (91)
Percentage
Rate differential	0.00%	0.10%	(2.80%)

JUNIOR SUBORDINATED NOTES - Schedule of Junior Subordinated Notes (Details) $ in Millions, $ in Millions	1 Months Ended		12 Months Ended
	Aug. 31, 2025 USD ($)	May 31, 2025 USD ($)	Dec. 31, 2025 CAD ($)	Dec. 31, 2007 USD ($)	Dec. 31, 2025 USD ($)	Oct. 31, 2025 USD ($)	Aug. 01, 2025	Feb. 28, 2025 USD ($)	Dec. 31, 2024 CAD ($)
Debt Instrument [Line Items]
Outstanding			$ 46,928						$ 48,172
Unamortized debt discount and issue costs			(251)						(252)
Junior subordinated debt, due 2056 \| Junior subordinated notes
Debt Instrument [Line Items]
Debt instrument, face amount			$ 1,000
Stated interest rate			5.20%		5.20%
Junior subordinated debt, due 2065 \| Junior subordinated notes
Debt Instrument [Line Items]
Debt instrument, face amount					$ 750
Stated interest rate			7.00%		7.00%
Junior subordinated debt due 2085 \| Junior subordinated notes
Debt Instrument [Line Items]
Debt instrument, face amount					$ 370
Stated interest rate			6.25%		6.25%
TRANSCANADA PIPELINES LIMITED
Debt Instrument [Line Items]
Outstanding			$ 29,123						30,126
TRANSCANADA PIPELINES LIMITED \| Junior subordinated notes
Debt Instrument [Line Items]
Outstanding			12,217						11,146
Unamortized debt discount and issue costs			(123)						(98)
Long-term Debt			$ 12,094						11,048
TRANSCANADA PIPELINES LIMITED \| Junior subordinated debt, due 2075 \| Junior subordinated notes
Debt Instrument [Line Items]
Debt instrument, face amount					$ 750
Stated interest rate		5.88%	5.88%		5.88%
Outstanding			$ 0						$ 1,080
Unamortized debt discount and issue costs		$ (11)
Effective interest rate			0.00%		0.00%				7.50%
Amount		$ 750
TRANSCANADA PIPELINES LIMITED \| Junior subordinated debt, due 2056 \| Junior subordinated notes
Debt Instrument [Line Items]
Debt instrument, face amount	$ 1,000
Stated interest rate	5.20%						2.148%
Outstanding			$ 1,000						$ 0
Effective interest rate			5.30%		5.30%				0.00%
Stated interest rate, period of time	5 years		5 years
Stated interest rate, period of time after first term			5 years
TRANSCANADA PIPELINES LIMITED \| Junior subordinated debt, due 2065 \| Junior subordinated notes
Debt Instrument [Line Items]
Debt instrument, face amount								$ 750
Outstanding			$ 1,028						$ 0
Effective interest rate			7.20%		7.20%				0.00%
Stated interest rate, period of time			5 years
Stated interest rate, period of time after first term			5 years
TRANSCANADA PIPELINES LIMITED \| Junior subordinated debt, due 2067
Debt Instrument [Line Items]
Debt converted				$ 1,000
TRANSCANADA PIPELINES LIMITED \| Junior subordinated debt, due 2067 \| Junior subordinated notes
Debt Instrument [Line Items]
Debt instrument, face amount					$ 1,000
Stated interest rate			6.35%	6.35%	6.35%
Outstanding			$ 1,372						$ 1,440
Effective interest rate			6.00%		6.00%				6.20%
TRANSCANADA PIPELINES LIMITED \| Junior subordinated debt, due 2076 \| Junior subordinated notes
Debt Instrument [Line Items]
Debt instrument, face amount					$ 1,200
Stated interest rate			6.13%		6.13%
Outstanding			$ 1,646						$ 1,729
Effective interest rate			7.60%		7.60%				8.00%
TRANSCANADA PIPELINES LIMITED \| Junior subordinated debt, due 2077 \| Junior subordinated notes
Debt Instrument [Line Items]
Debt instrument, face amount					$ 1,500
Stated interest rate			5.55%		5.55%
Outstanding			$ 2,057						$ 2,161
Effective interest rate			6.70%		6.70%				7.20%
TRANSCANADA PIPELINES LIMITED \| Canadian junior subordinated debt, due 2077 \| Junior subordinated notes
Debt Instrument [Line Items]
Debt instrument, face amount			$ 1,500
Stated interest rate			4.90%		4.90%
Outstanding			$ 1,500						$ 1,500
Effective interest rate			5.60%		5.60%				6.80%
TRANSCANADA PIPELINES LIMITED \| Junior subordinated debt, due 2079 \| Junior subordinated notes
Debt Instrument [Line Items]
Debt instrument, face amount					$ 1,100
Stated interest rate			5.75%		5.75%
Outstanding			$ 1,509						$ 1,584
Effective interest rate			7.30%		7.30%				7.70%
Stated interest rate, period of time			10 years
Stated interest rate, period of time after first term			5 years
TRANSCANADA PIPELINES LIMITED \| $500 notes due 2081 at 4.45% \| Junior subordinated notes
Debt Instrument [Line Items]
Debt instrument, face amount			$ 500
Stated interest rate			4.45%		4.45%
Outstanding			$ 500						$ 500
Effective interest rate			4.50%		4.50%				5.70%
TRANSCANADA PIPELINES LIMITED \| $800 notes due 2082 at 5.85% \| Junior subordinated notes
Debt Instrument [Line Items]
Debt instrument, face amount					$ 800
Stated interest rate			5.85%		5.85%
Outstanding			$ 1,097						$ 1,152
Effective interest rate			7.10%		7.10%				7.30%
TRANSCANADA PIPELINES LIMITED \| Junior subordinated debt due 2085 \| Junior subordinated notes
Debt Instrument [Line Items]
Debt instrument, face amount						$ 370
Stated interest rate						6.25%
Outstanding			$ 508						$ 0
Effective interest rate			6.60%		6.60%				0.00%

EQUITY INVESTMENTS - Schedule of Distribution Received and Contribution Paid (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Equity Investments
Distributions received from equity investments	$ 1,621	$ 5,293	$ 1,181
Contributions to equity investments	1,051	4,683	4,149
Payment to reduce company's funding commitment	1,051	4,683	4,149
Coastal GasLink
Equity Investments
Contributions to equity investments	65	3,964	3,231
Coastal GasLink \| Coastal GasLink \| Subordinated Loan Agreement \| Subordinated debt
Equity Investments
Payment to reduce company's funding commitment	3,137
Equity investments
Equity Investments
Distributions received from equity investments	1,616	1,607	1,158
Contributions to equity investments	986	719	918
Coastal GasLink
Equity Investments
Distributions received from equity investments	0	3,147	0
Other
Equity Investments
Distributions received from equity investments	$ 5	$ 539	$ 23

ACCOUNTS PAYABLE AND OTHER (Details) - CAD ($) $ in Millions	Dec. 31, 2025	Dec. 31, 2024
Payables and Accruals [Abstract]
Trade payables	$ 3,263	$ 3,699
Regulatory liabilities (Note 12)	532	353
Fair value of derivative instruments (Note 27)	380	507
Factoring arrangement (Note 9)	351	0
Gas transportation and exchange payable	158	118
Emissions expense payable	91	101
Operating lease liabilities (Note 9)	61	60
Contract liabilities (Note 6)	46	30
Income tax liabilities	38	143
Other	354	286
Accounts payable and other	$ 5,274	$ 5,297

OTHER CURRENT ASSETS

12 Months Ended

Dec. 31, 2025

Other Assets [Abstract]

OTHER CURRENT ASSETS


at December 31	2025	2024
(millions of Canadian $)

Net investment in leases (Note 9)	1,256	333
Fair value of derivative instruments (Note 27)	438	347
Contract assets (Note 6)	216	165
Cash provided as collateral	93	128
Prepaid expenses	82	86
Emissions credits	67	75
Regulatory assets (Note 12)	58	123
Other	165	82
	2,375	1,339

Audit Information	12 Months Ended
Audit Information	Dec. 31, 2025
Auditor Information [Abstract]
Auditor Name	KPMG LLP
Auditor Location	Calgary, AB, Canada
Auditor Firm ID	85

DISCONTINUED OPERATIONS - Assets and Liabilities of Discontinued Operations (Details) - CAD ($) $ in Millions	Dec. 31, 2025	Dec. 31, 2024
Current Assets
Other current assets	$ 197	$ 235
Current assets of discontinued operations (Note 4)	197	235
Other Long-Term Assets	0	136
Long-Term Assets of Discontinued Operations (Note 4)	197	371
Current Liabilities
Accounts payable and other	181	170
Current liabilities of discontinued operations (Note 4)	181	170
Other Long-Term Liabilities	0	110
Liabilities	$ 181	$ 280

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - Available for Sale and Balance Sheet Presentation (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Total Derivatives
Derivative Assets	$ 599	$ 469
Derivative Liabilities	(529)	(716)
Total Derivatives	70	(247)
Total trading activity
Total Derivatives
Derivative Assets	550	442
Derivative Liabilities	(434)	(564)
Total Derivatives	116	(122)
Cash Flow Hedges
Total Derivatives
Derivative Assets	24	27
Derivative Liabilities	(53)	(2)
Total Derivatives	(29)	25
Net Investment Hedges
Total Derivatives
Derivative Assets		0
Derivative Liabilities		(11)
Total Derivatives		(11)
Fair Value Hedges
Total Derivatives
Derivative Assets	25	0
Derivative Liabilities	(42)	(139)
Total Derivatives	(17)	(139)
Other current assets
Total Derivatives
Derivative Assets	438	347
Other current assets \| Total trading activity
Total Derivatives
Derivative Assets	413	329
Other current assets \| Cash Flow Hedges
Total Derivatives
Derivative Assets	22	18
Other current assets \| Net Investment Hedges
Total Derivatives
Derivative Assets		0
Other current assets \| Fair Value Hedges
Total Derivatives
Derivative Assets	3	0
Other current assets \| Commodities
Total Derivatives
Derivative Assets	384	305
Other current assets \| Commodities \| Commodities
Total Derivatives
Derivative Assets	371	287
Other current assets \| Commodities \| Cash Flow Hedges
Total Derivatives
Derivative Assets	13	18
Other current assets \| Commodities \| Net Investment Hedges
Total Derivatives
Derivative Assets		0
Other current assets \| Commodities \| Fair Value Hedges
Total Derivatives
Derivative Assets	0	0
Other current assets \| Foreign exchange
Total Derivatives
Derivative Assets	51	42
Other current assets \| Foreign exchange \| Foreign exchange
Total Derivatives
Derivative Assets	42	42
Other current assets \| Foreign exchange \| Cash Flow Hedges
Total Derivatives
Derivative Assets	9	0
Other current assets \| Foreign exchange \| Net Investment Hedges
Total Derivatives
Derivative Assets		0
Other current assets \| Foreign exchange \| Fair Value Hedges
Total Derivatives
Derivative Assets	0	0
Other current assets \| Interest rate
Total Derivatives
Derivative Assets	3
Other current assets \| Interest rate \| Interest rate
Total Derivatives
Derivative Assets	0
Other current assets \| Interest rate \| Cash Flow Hedges
Total Derivatives
Derivative Assets	0
Other current assets \| Interest rate \| Fair Value Hedges
Total Derivatives
Derivative Assets	3
Other long-term assets
Total Derivatives
Derivative Assets	161	122
Other long-term assets \| Total trading activity
Total Derivatives
Derivative Assets	137	113
Other long-term assets \| Cash Flow Hedges
Total Derivatives
Derivative Assets	2	9
Other long-term assets \| Net Investment Hedges
Total Derivatives
Derivative Assets		0
Other long-term assets \| Fair Value Hedges
Total Derivatives
Derivative Assets	22	0
Other long-term assets \| Commodities
Total Derivatives
Derivative Assets	124	113
Other long-term assets \| Commodities \| Commodities
Total Derivatives
Derivative Assets	122	104
Other long-term assets \| Commodities \| Cash Flow Hedges
Total Derivatives
Derivative Assets	2	9
Other long-term assets \| Commodities \| Net Investment Hedges
Total Derivatives
Derivative Assets		0
Other long-term assets \| Commodities \| Fair Value Hedges
Total Derivatives
Derivative Assets	0	0
Other long-term assets \| Foreign exchange
Total Derivatives
Derivative Assets	15	9
Other long-term assets \| Foreign exchange \| Foreign exchange
Total Derivatives
Derivative Assets	15	9
Other long-term assets \| Foreign exchange \| Cash Flow Hedges
Total Derivatives
Derivative Assets	0	0
Other long-term assets \| Foreign exchange \| Net Investment Hedges
Total Derivatives
Derivative Assets		0
Other long-term assets \| Foreign exchange \| Fair Value Hedges
Total Derivatives
Derivative Assets	0	0
Other long-term assets \| Interest rate
Total Derivatives
Derivative Assets	22
Other long-term assets \| Interest rate \| Interest rate
Total Derivatives
Derivative Assets	0
Other long-term assets \| Interest rate \| Cash Flow Hedges
Total Derivatives
Derivative Assets	0
Other long-term assets \| Interest rate \| Fair Value Hedges
Total Derivatives
Derivative Assets	22
Accounts payable and other
Total Derivatives
Derivative Liabilities	(380)	(507)
Accounts payable and other \| Total trading activity
Total Derivatives
Derivative Liabilities	(371)	(474)
Accounts payable and other \| Cash Flow Hedges
Total Derivatives
Derivative Liabilities	(1)	(1)
Accounts payable and other \| Net Investment Hedges
Total Derivatives
Derivative Liabilities		(11)
Accounts payable and other \| Fair Value Hedges
Total Derivatives
Derivative Liabilities	(8)	(21)
Accounts payable and other \| Commodities
Total Derivatives
Derivative Liabilities	(342)	(292)
Accounts payable and other \| Commodities \| Commodities
Total Derivatives
Derivative Liabilities	(341)	(291)
Accounts payable and other \| Commodities \| Cash Flow Hedges
Total Derivatives
Derivative Liabilities	(1)	(1)
Accounts payable and other \| Commodities \| Net Investment Hedges
Total Derivatives
Derivative Liabilities		0
Accounts payable and other \| Commodities \| Fair Value Hedges
Total Derivatives
Derivative Liabilities	0	0
Accounts payable and other \| Foreign exchange
Total Derivatives
Derivative Liabilities	(30)	(194)
Accounts payable and other \| Foreign exchange \| Foreign exchange
Total Derivatives
Derivative Liabilities	(30)	(183)
Accounts payable and other \| Foreign exchange \| Cash Flow Hedges
Total Derivatives
Derivative Liabilities	0	0
Accounts payable and other \| Foreign exchange \| Net Investment Hedges
Total Derivatives
Derivative Liabilities		(11)
Accounts payable and other \| Foreign exchange \| Fair Value Hedges
Total Derivatives
Derivative Liabilities	0	0
Accounts payable and other \| Interest rate
Total Derivatives
Derivative Liabilities	(8)	(21)
Accounts payable and other \| Interest rate \| Interest rate
Total Derivatives
Derivative Liabilities	0	0
Accounts payable and other \| Interest rate \| Cash Flow Hedges
Total Derivatives
Derivative Liabilities	0	0
Accounts payable and other \| Interest rate \| Net Investment Hedges
Total Derivatives
Derivative Liabilities		0
Accounts payable and other \| Interest rate \| Fair Value Hedges
Total Derivatives
Derivative Liabilities	(8)	(21)
Other long-term liabilities
Total Derivatives
Derivative Liabilities	(149)	(209)
Other long-term liabilities \| Total trading activity
Total Derivatives
Derivative Liabilities	(63)	(90)
Other long-term liabilities \| Cash Flow Hedges
Total Derivatives
Derivative Liabilities	(52)	(1)
Other long-term liabilities \| Net Investment Hedges
Total Derivatives
Derivative Liabilities		0
Other long-term liabilities \| Fair Value Hedges
Total Derivatives
Derivative Liabilities	(34)	(118)
Other long-term liabilities \| Commodities
Total Derivatives
Derivative Liabilities	(62)	(47)
Other long-term liabilities \| Commodities \| Commodities
Total Derivatives
Derivative Liabilities	(61)	(46)
Other long-term liabilities \| Commodities \| Cash Flow Hedges
Total Derivatives
Derivative Liabilities	(1)	(1)
Other long-term liabilities \| Commodities \| Net Investment Hedges
Total Derivatives
Derivative Liabilities		0
Other long-term liabilities \| Commodities \| Fair Value Hedges
Total Derivatives
Derivative Liabilities	0	0
Other long-term liabilities \| Foreign exchange
Total Derivatives
Derivative Liabilities	(53)	(44)
Other long-term liabilities \| Foreign exchange \| Foreign exchange
Total Derivatives
Derivative Liabilities	(2)	(44)
Other long-term liabilities \| Foreign exchange \| Cash Flow Hedges
Total Derivatives
Derivative Liabilities	(51)	0
Other long-term liabilities \| Foreign exchange \| Net Investment Hedges
Total Derivatives
Derivative Liabilities		0
Other long-term liabilities \| Foreign exchange \| Fair Value Hedges
Total Derivatives
Derivative Liabilities	0	0
Other long-term liabilities \| Interest rate
Total Derivatives
Derivative Liabilities	(34)	(118)
Other long-term liabilities \| Interest rate \| Interest rate
Total Derivatives
Derivative Liabilities	0	0
Other long-term liabilities \| Interest rate \| Cash Flow Hedges
Total Derivatives
Derivative Liabilities	0	0
Other long-term liabilities \| Interest rate \| Net Investment Hedges
Total Derivatives
Derivative Liabilities		0
Other long-term liabilities \| Interest rate \| Fair Value Hedges
Total Derivatives
Derivative Liabilities	(34)	(118)
LMCI Restricted Investments
Fair value
Fair value of equity securities	1,252	1,070
Gain (Loss) on Investments, Realized and Unrealized
Net unrealized gains (losses)	167	218	$ 179
Net realized (losses)/ gains	21	3	(28)
Other Restricted Investments
Fair value
Fair value of equity securities	94	64
Gain (Loss) on Investments, Realized and Unrealized
Net unrealized gains (losses)	(1)	9	13
Net realized (losses)/ gains	22	2	$ 0
Fixed income securities \| LMCI Restricted Investments
Fair value
Maturing within 1 year	0	0
Maturing within 1-5 years	26	3
Maturing within 5-10 years	1,846	1,578
Maturing after 10 years	0	0
Fair value of securities	3,124	2,651
Fixed income securities \| Other Restricted Investments
Fair value
Maturing within 1 year	94	33
Maturing within 1-5 years	251	256
Maturing within 5-10 years	4	0
Maturing after 10 years	16	0
Fair value of securities	$ 459	$ 353

OTHER LONG-TERM ASSETS (Tables)

12 Months Ended

Dec. 31, 2025

Intangible Assets, Net (Excluding Goodwill) [Abstract]

Schedule of Other Long-Term Assets


at December 31	2025	2024
(millions of Canadian $)

Employee post-retirement benefits (Note 26)	967	758
Contract assets (Note 6)	627	608
Deferred income tax assets (Note 18)	356	428
Fair value of derivative instruments (Note 27)	161	122
Capital projects in development	81	164


Other	290	330
	2,482	2,410

JUNIOR SUBORDINATED NOTES (Tables)

12 Months Ended

Dec. 31, 2025

Junior Subordinated Notes [Abstract]

Schedule of Junior Subordinated Notes


at December 31		2025			2024
	Maturity Date	Outstanding	Effective Interest Rate1		Outstanding	Effective Interest Rate1
(millions of Canadian $, unless otherwise noted)

TRANSCANADA PIPELINES LIMITED
US$750 issued 2015 at 5.88%2,3,4	—	—	—		1,080	7.5	%
$1,000 issued 2025 at 5.20%5	2056	1,000	5.3	%	—	—
US$750 issued 2025 at 7.00%6	2065	1,028	7.2	%	—	—
US$1,000 issued 2007 at 6.35%7	2067	1,372	6.0	%	1,440	6.2	%
US$1,200 issued 2016 at 6.13%3,4	2076	1,646	7.6	%	1,729	8.0	%
US$1,500 issued 2017 at 5.55%3,4	2077	2,057	6.7	%	2,161	7.2	%
$1,500 issued 2017 at 4.90%3,4	2077	1,500	5.6	%	1,500	6.8	%
US$1,100 issued 2019 at 5.75%3,4	2079	1,509	7.3	%	1,584	7.7	%
$500 issued 2021 at 4.45%3,8	2081	500	4.5	%	500	5.7	%
US$800 issued 2022 at 5.85%3,8	2082	1,097	7.1	%	1,152	7.3	%
US$370 issued 2025 at 6.25%	2085	508	6.6	%	—	—
		12,217			11,146
Unamortized debt discount and issue costs		(123)			(98)
		12,094			11,048

1The effective interest rate is calculated by discounting the expected future interest payments using the coupon rate and any estimated future rate resets, adjusted for issue costs and discounts.

2In May 2025, TCPL exercised its option to fully repay and retire the US$750 million junior subordinated notes that had a maturity date of 2075.

4The coupon rate is initially a fixed interest rate for the first 10 years and converts to a floating rate thereafter.

5The coupon rate is initially a fixed interest rate for the first five years and resets every five years thereafter, subject to a rate-reset minimum.

6The coupon rate is initially a fixed interest rate for the first five years and resets every five years thereafter.

7Junior subordinated notes of US$1.0 billion were issued in 2007 at a fixed rate of 6.35 per cent and converted in 2017 to bear interest at a floating rate.

8The coupon rate is initially a fixed interest rate for the first 10 years and resets every five years thereafter.

INCOME TAXES - Deferred Assets and Valuation Allowance (Details) - CAD ($) $ in Millions	Dec. 31, 2025	Dec. 31, 2024
Deferred Tax Asset
Deferred tax assets, gross	$ 2,819	$ 3,324
Valuation Allowance
Valuation allowance	789	$ 931
Unused Amounts
Unused Amounts
Operating losses	5,838
Foreign federal and state operating losses	1,746
Capital loss	618
Minimum tax	0
Restricted Interest and Financing Expense	424
Unrealized Foreign Exchange on Long-Term Debt	0
Equity Investments	0
Deferred Tax Asset
Deferred Tax Asset
Operating losses	1,302
Foreign federal and state operating losses	173
Capital loss	74
Minimum tax	179
Deferred tax assets, gross	1,728
Restricted Interest and Financing Expense	100
Unrealized Foreign Exchange on Long-Term Debt	290
Equity Investments	342
Valuation Allowance
Valuation Allowance
Operating losses	0
Foreign federal and state operating losses	41
Capital loss	74
Minimum tax	42
Valuation allowance	157
Restricted Interest and Financing Expense	0
Unrealized Foreign Exchange on Long-Term Debt	290
Equity Investments	342
Deferred tax assets, net of Valuation allowance	$ 789

REVENUES - Disaggregation of Revenues (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Disaggregation of Revenue [Line Items]
Revenues	$ 15,239	$ 13,771	$ 13,267
Operating segments
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	13,963	13,062	12,511
Sales-type lease income	787	308	279
Other revenues	475	393	477
Revenues	15,225	13,763
Capacity arrangements and transportation \| Operating segments
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	11,928	11,406	10,690
Power generation \| Operating segments
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	236	266	427
Natural gas storage and other \| Operating segments
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	1,799	1,390	1,394
Canadian Natural Gas Pipelines
Disaggregation of Revenue [Line Items]
Revenues	5,785	5,600	5,173
Canadian Natural Gas Pipelines \| Operating segments
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	5,785	5,600	5,173
Sales-type lease income	0	0	0
Other revenues	0	0	0
Revenues	5,785	$ 5,600	5,173
Canadian Natural Gas Pipelines \| Coastal GasLink
Disaggregation of Revenue [Line Items]
Ownership interest percentage		35.00%
Canadian Natural Gas Pipelines \| Capacity arrangements and transportation \| Operating segments
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	5,785	$ 5,586	5,141
Canadian Natural Gas Pipelines \| Power generation \| Operating segments
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	0	0	0
Canadian Natural Gas Pipelines \| Natural gas storage and other \| Operating segments
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	0	14	32
Canadian Natural Gas Pipelines \| Coastal GasLink \| Related party
Disaggregation of Revenue [Line Items]
Revenues		14	31
U.S. Natural Gas Pipelines
Disaggregation of Revenue [Line Items]
Revenues	7,145	6,339	6,229
U.S. Natural Gas Pipelines \| Operating segments
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	6,839	6,251	5,981
Sales-type lease income	0	0	0
Other revenues	306	88	248
Revenues	7,145	6,339	6,229
U.S. Natural Gas Pipelines \| Capacity arrangements and transportation \| Operating segments
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	5,698	5,382	5,107
U.S. Natural Gas Pipelines \| Power generation \| Operating segments
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	0	0	0
U.S. Natural Gas Pipelines \| Natural gas storage and other \| Operating segments
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	1,141	869	874
Mexico Natural Gas Pipelines
Disaggregation of Revenue [Line Items]
Revenues	1,450	870	846
Mexico Natural Gas Pipelines \| Operating segments
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	663	562	567
Sales-type lease income	$ 787	$ 308	279
Sales-Type Lease, Lease Income, Statement of Income or Comprehensive Income [Extensible Enumeration]	Revenues	Revenues
Other revenues	$ 0	$ 0	0
Revenues	1,450	870	846
Mexico Natural Gas Pipelines \| Capacity arrangements and transportation \| Operating segments
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	445	438	442
Mexico Natural Gas Pipelines \| Power generation \| Operating segments
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	0	0	0
Mexico Natural Gas Pipelines \| Natural gas storage and other \| Operating segments
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	218	124	125
Power and Energy Solutions
Disaggregation of Revenue [Line Items]
Revenues	845	954	1,019
Power and Energy Solutions \| Operating segments
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	676	649	790
Sales-type lease income	0	0	0
Other revenues	169	305	229
Revenues	845	954	1,019
Power and Energy Solutions \| Capacity arrangements and transportation \| Operating segments
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	0	0	0
Power and Energy Solutions \| Power generation \| Operating segments
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	236	266	427
Power and Energy Solutions \| Natural gas storage and other \| Operating segments
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	440	383	363
Corporate
Disaggregation of Revenue [Line Items]
Other revenues	14	8
Revenues	14	8
Corporate \| South Bow Canadian Infrastructure Holdings Ltd
Disaggregation of Revenue [Line Items]
Other revenues		7
TGNH \| Non-lease components
Disaggregation of Revenue [Line Items]
Revenues	$ 192	$ 98	$ 97

LEASES (Tables)

12 Months Ended

Dec. 31, 2025

Leases [Abstract]

Schedule of Operating Lease Cost

Operating lease cost was as follows:


year ended December 31
(millions of Canadian $)	2025	2024

Operating lease cost1	112	117
Sublease income	(5)	(6)
Net operating lease cost	107	111

1 Includes short-term leases and variable lease costs.

Other information related to operating leases is noted in the following tables:


year ended December 31
(millions of Canadian $)	2025	2024

Cash paid for amounts included in the measurement of operating lease liabilities	76	74
ROU assets obtained in exchange for new operating lease liabilities	18	96


at December 31	2025		2024

Weighted average remaining lease term	11 years		13 years
Weighted average discount rate	3.4	%	3.3	%

The amounts recognized on TC Energy's Consolidated balance sheet for its operating lease liabilities were as follows:


at December 31
(millions of Canadian $)	2025	2024

Accounts payable and other (Note 16)	61	60
Other long-term liabilities (Note 17)	370	451
	431	511

Schedule of Maturities of Operating Lease Liabilities

Maturities of operating lease liabilities are as follows:


at December 31
(millions of Canadian $)	2025	2024

Less than one year	73	73
One to two years	66	73
Two to three years	63	66
Three to four years	63	64
Four to five years	59	63
More than five years	185	275
Total operating lease payments	509	614
Imputed interest	(78)	(103)
Operating lease liabilities	431	511

Schedule of Future Lease Payments to be Received Under Operating Leases

Future lease payments to be received under operating leases are as follows:


at December 31
(millions of Canadian $)	2025	2024

Less than one year	80	107
One to two years	9	76
Two to three years	10	9
Three to four years	10	10
Four to five years	10	10
More than five years	45	55
	164	267

Schedule of Future Lease Payments

Future lease payments to be received under the existing sales-type leases are as follows:


at December 31
(millions of Canadian $)	2025	2024

Less than one year	1,256	333
One to two years	1,000	333
Two to three years	1,000	333
Three to four years	1,000	333
Four to five years	1,000	333
More than five years	24,508	8,499
	29,764	10,164

Schedule of Aggregate Net Investment in Leases

The following table lists the components of the aggregate net investment in leases reflected on the Company's Consolidated balance sheet:


at December 31
(millions of Canadian $)	2025	2024

Net Investment in Leases
Minimum lease payments	29,764	10,164
Unearned lease income	(20,397)	(7,323)
Lease receivable	9,367	2,841
Expected credit loss provision1	(141)	(59)
Present value of unguaranteed residual value	140	28
	9,366	2,810
Current portion included in Other current assets (Note 7)	(1,256)	(333)
	8,110	2,477

1Includes $2 million gain (2024 – $6 million loss) on foreign currency translation.

DISCONTINUED OPERATIONS

12 Months Ended

Dec. 31, 2025

Discontinued Operations and Disposal Groups [Abstract]

DISCONTINUED OPERATIONS

Spinoff of Liquids Pipelines Business

On October 1, 2024, TC Energy completed the spinoff of its Liquids Pipelines business. Pursuant to the Spinoff Transaction, TC Energy and South Bow executed a series of agreements to outline the parameters and guidelines that govern their ongoing relationship, including a Transition Services Agreement, Tax Matters Agreement and a Separation Agreement.

The Transition Services Agreement was established to specify certain services that TC Energy will provide to South Bow for a period of up to two years.

The Tax Matters Agreement governs TC Energy and South Bow's tax rights and obligations after the Spinoff Transaction. The agreement imposes certain restrictions on both TC Energy and South Bow in order to preserve the tax-free status of the spinoff. In the event the Spinoff Transaction is not tax-free, the agreement allocates tax liabilities by generally assigning responsibility to either TC Energy or South Bow to the extent that the failure to qualify is attributable to actions, events or transactions, or a breach of the representations or covenants made by that entity.

The Separation Agreement set forth the terms of the separation of the Liquids Pipelines business from the business of TC Energy, including the transfer of certain assets related to the Liquids Pipelines business from TC Energy to South Bow and the allocation of certain liabilities and obligations related to the Liquids Pipelines business between TC Energy and South Bow.

During 2025, TC Energy reached an agreement with South Bow with respect to liabilities the Company indemnified South Bow for under the Separation Agreement, releasing the Company from those liabilities. Inclusive of the recognition of the settlement, a net loss from discontinued operations of $183 million, net of tax was recognized. Payments related to the settlement commenced in fourth quarter 2025 and will be completed in 2026.

In addition, the Company revised its estimate of future recoveries, resulting in a $29 million impairment, which was included in Net income (loss) from discontinued operations, net of tax in the Consolidated statement of income.

Separation Costs

Liquids Pipelines business separation costs primarily include internal costs related to separation activities, legal, income tax, audit and other consulting fees, insurance provisions and net financial charges related to debt issued and held in escrow. For the years ended December 31, 2024 and 2023, Liquids Pipelines business separation costs of $197 million ($167 million after tax) and $40 million ($34 million after tax), respectively, were included in Net income (loss) from discontinued operations, net of tax in the Consolidated statement of income. There were no separation costs recognized for the year ended December 31, 2025.

Pensions

As part of the Spinoff Transaction, certain TC Energy employees became employees of South Bow. Prior to the Spinoff Transaction, these employees in Canada and the U.S. participated in DB Plans, DC Plans and savings plans, as applicable. Effective October 1, 2024, the benefit obligations under the DB Plans in respect of the employees moving from TC Energy to South Bow were transferred to South Bow. An asset transfer application related to the Canadian DB Plan outlining the proposed transfer of assets from TC Energy to South Bow has received regulatory approval. During the year ended December 31, 2025, $105 million was transferred to South Bow. As at December 31, 2025, $17 million of assets in the Canadian DB Plan remain in the TC Energy DB Plan trust and are reflected as Current assets of discontinued operations with a corresponding obligation to South Bow reflected as Current liabilities of discontinued operations on the Consolidated balance sheet. The Company expects the remaining assets to be fully transferred mid-2026. As at December 31, 2024, the assets related to the U.S. DB Plan were fully transferred to South Bow.

South Bow Debt

On August 28, 2024, South Bow Canadian Infrastructure Holdings Ltd. and 6297782 LLC, two wholly-owned subsidiaries of the Company at the time, completed an offering of approximately $7.9 billion Canadian-dollar equivalent of senior unsecured notes and junior subordinated notes. Approximately $6.2 billion Canadian-dollar equivalent of the net proceeds was placed in escrow pending the completion of the Spinoff Transaction on October 1, 2024 and US$1.3 billion of senior unsecured notes were used to repay a TransCanada PipeLines Limited (TCPL) term loan. Upon completion of the Spinoff Transaction, the escrowed funds were released to South Bow and used to repay indebtedness owed by South Bow and its subsidiaries to TC Energy and its subsidiaries.

Presentation of Discontinued Operations

As described in Note 2, Accounting policies, upon completion of the Spinoff Transaction, the Liquids Pipelines business was accounted for as discontinued operations. The Company's presentation of discontinued operations includes revenues and expenses directly attributable to the Liquids Pipelines business.

Prior year comparatives present the Liquids Pipelines business as discontinued operations.

Income from Discontinued Operations


year ended December 31
(millions of Canadian $)	2025	2024	2023

Revenues	—	2,217	2,667
Income (Loss) from Equity Investments	—	50	67
Operating and Other Expenses
Plant operating costs and other	216	806	814
Commodity purchases resold	—	387	437
Property taxes	—	84	116
Depreciation and amortization	—	253	332
Asset impairment charge and other	29	21	(4)
	245	1,551	1,695
Segmented Earnings (Losses) from Discontinued Operations	(245)	716	1,039
Financial Charges
Interest expense	—	218	297
Interest income and other	(28)	(21)	30
	(28)	197	327
Income (Loss) from Discontinued Operations before Income Taxes	(217)	519	712
Income tax expense (recovery)	(5)	124	100
Net Income (Loss) from Discontinued Operations, Net of Tax	(212)	395	612

Assets and Liabilities of Discontinued Operations


at December 31
(millions of Canadian $)	2025	2024

ASSETS
Current Assets
Other current assets	197	235
	197	235
Other Long-Term Assets	—	136
	197	371
LIABILITIES
Current Liabilities
Accounts payable and other	181	170
	181	170
Other Long-Term Liabilities	—	110
	181	280

The Spinoff Transaction resulted in derecognition of the net assets of the Liquids Pipelines segment in the amount of $3,691 million. The reduction in net assets was reflected as a $2,950 million decrease in Retained earnings (Accumulated deficit) and a $741 million decrease in AOCI for the year ended December 31, 2024.

For the year ended December 31, 2025, the Company recorded $542 million related to the Spinoff Transaction as an out-of-period adjustment to reclassify a pro rata portion of its net investment hedge losses recorded in AOCI to Retained earnings (Accumulated deficit). Refer to Note 2, Accounting policies, for additional information.

Cash Flows from Discontinued Operations


year ended December 31
(millions of Canadian $)	2025	2024	2023

Net cash (used in) provided by operations	(185)	670	1,026
Net cash (used in) provided by investing activities	24	(89)	87

DESCRIPTION OF TC ENERGY'S BUSINESS	12 Months Ended
DESCRIPTION OF TC ENERGY'S BUSINESS	Dec. 31, 2025
Organization, Consolidation and Presentation of Financial Statements [Abstract]
DESCRIPTION OF TC ENERGY'S BUSINESS	DESCRIPTION OF TC ENERGY'S BUSINESS TC Energy Corporation (TC Energy or the Company) is a leading North American energy infrastructure company which operates in four business segments: Canadian Natural Gas Pipelines, U.S. Natural Gas Pipelines, Mexico Natural Gas Pipelines and Power and Energy Solutions. These segments offer different products and services, including certain natural gas and electricity marketing and storage services. The Company also has a Corporate segment, consisting of corporate and administrative functions that provide governance, financing and other support to the Company's business segments. Canadian Natural Gas Pipelines The Canadian Natural Gas Pipelines segment primarily consists of the Company's investments in 40,984 km (25,467 miles) of regulated natural gas pipelines currently in operation. U.S. Natural Gas Pipelines The U.S. Natural Gas Pipelines segment primarily consists of the Company's investments in 49,587 km (30,811 miles) of regulated natural gas pipelines, 532 Bcf of regulated natural gas storage facilities and other assets currently in operation. Mexico Natural Gas Pipelines The Mexico Natural Gas Pipelines segment primarily consists of the Company's investments in 3,600 km (2,235 miles) of regulated natural gas pipelines currently in operation. Power and Energy Solutions The Power and Energy Solutions segment primarily consists of the Company's investments in approximately 4,650 MW of power generation facilities and 118 Bcf of non-regulated natural gas storage facilities. These assets are located in Alberta, Ontario, Québec, New Brunswick and Texas. In addition, TC Energy has physical and virtual power purchase agreements (PPAs) in Canada and the U.S. to buy and/or sell power from wind and solar facilities. These PPAs have the potential to be leases, derivatives or revenue arrangements depending on the contractual terms of the agreement. Spinoff of Liquids Pipelines Business On October 1, 2024, TC Energy completed the spinoff of its Liquids Pipelines business into the new public company, South Bow Corporation (South Bow) (the Spinoff Transaction). Refer to Note 4, Discontinued operations, for additional information.

SEGMENTED INFORMATION - Schedule of Long-Lived Assets by Country (Details) - CAD ($) $ in Millions	Dec. 31, 2025	Dec. 31, 2024
Segment Reporting Information [Line Items]
Plant, Property and Equipment	$ 71,054	$ 77,501
Canada
Segment Reporting Information [Line Items]
Plant, Property and Equipment	26,078	26,354
United States
Segment Reporting Information [Line Items]
Plant, Property and Equipment	40,976	40,580
Mexico
Segment Reporting Information [Line Items]
Plant, Property and Equipment	$ 4,000	$ 10,567

COMMITMENTS, CONTINGENCIES AND GUARANTEES - Guarantees (Details) - Contingent financial obligation - CAD ($) $ in Millions	Dec. 31, 2025	Dec. 31, 2024
Guarantees
Potential Exposure	$ 220	$ 240
Carrying Value	1	1
Bruce Power
Guarantees
Potential Exposure	88	88
Carrying Value	0	0
Sur de Texas
Guarantees
Potential Exposure	78	93
Carrying Value	0	0
Other jointly-owned entities
Guarantees
Potential Exposure	54	59
Carrying Value	$ 1	$ 1

GOODWILL

12 Months Ended

Dec. 31, 2025

Goodwill and Intangible Assets Disclosure [Abstract]

GOODWILL

The Company's Goodwill balance on the Consolidated balance sheet is comprised of the following amounts:


at December 31	2025		2024
(millions)	Canadian dollars	U.S. dollars1	Canadian dollars	U.S. dollars1

Columbia	10,082	7,351	10,588	7,351
ANR	2,669	1,946	2,803	1,946
Great Lakes	167	122	176	122
North Baja	66	48	70	48
Tuscarora	32	23	33	23
	13,016	9,490	13,670	9,490

1Represents gross amounts of goodwill as at December 31, 2025 and 2024 of US$10,828 million, net of accumulated impairment of US$1,338 million.

Changes in Goodwill were as follows:


(millions of Canadian $)			U.S. Natural Gas Pipelines

Balance at January 1, 2024			12,532

Foreign exchange rate changes			1,138
Balance at December 31, 2024			13,670

Foreign exchange rate changes			(654)
Balance at December 31, 2025			13,016

As part of the annual goodwill impairment assessment at December 31, 2025, the Company evaluated qualitative factors impacting the fair value of the underlying reporting units for all reporting units other than the Columbia reporting unit. It was determined that it was more likely than not that the fair value of all reporting units exceeded their carrying amounts, including goodwill.

Columbia

The Company elected to proceed directly to a quantitative annual impairment test at December 31, 2025 for the $10,082 million (US$7,351 million) of goodwill related to the Columbia reporting unit subsequent to the 2025 Columbia Gas Settlement. To determine fair value, the Company used a discounted cash flow model incorporating projections of future cash flows as well as a valuation multiple and applied a risk-adjusted discount rate which involved significant estimates and judgments. The fair value measurement is classified as Level III in the fair value hierarchy. It was determined that the fair value of the Columbia reporting unit exceeded its carrying value, including goodwill, at December 31, 2025.

Great Lakes

The estimated fair value of the Great Lakes reporting unit in excess of its carrying value was less than 10 per cent at the date of the last quantitative goodwill impairment test in 2022. Any future reductions in cash flow forecasts or adverse changes in other key assumptions could result in a future impairment of the goodwill balance.

- Definition

The entire disclosure for goodwill.

+ References + Details

OTHER CURRENT ASSETS (Tables)

12 Months Ended

Dec. 31, 2025

Other Assets [Abstract]

Schedule of Other Current Assets


at December 31	2025	2024
(millions of Canadian $)

Net investment in leases (Note 9)	1,256	333
Fair value of derivative instruments (Note 27)	438	347
Contract assets (Note 6)	216	165
Cash provided as collateral	93	128
Prepaid expenses	82	86
Emissions credits	67	75
Regulatory assets (Note 12)	58	123
Other	165	82
	2,375	1,339

VARIABLE INTEREST ENTITIES - Assets and Liabilities of Variable Interest Entities (Details) $ in Millions, $ in Millions	Dec. 31, 2025 CAD ($)	Dec. 31, 2025 USD ($)	Dec. 31, 2024 CAD ($)	Dec. 31, 2024 USD ($)
Current Assets
Cash and cash equivalents	$ 168		$ 801
Accounts receivable	2,794		2,611
Inventories	782		747
Other current assets	2,375		1,339
Total current assets	6,316		5,733
Plant, Property and Equipment	71,054		77,501
Equity Investments	11,358		10,636
Regulatory Assets	2,913		2,682
Goodwill	13,016	$ 9,490	13,670	$ 9,490
Other Long-Term Assets	2,482		2,410
Total assets	118,751		118,243
Current Liabilities
Accounts payable and other	5,274		5,297
Accrued interest	858		828
Current portion of long-term debt	1,545		2,955
Total current liabilities	9,959		10,511
Regulatory Liabilities	5,841		5,303
Deferred Income Tax Liabilities	7,677		6,884
Total liabilities	81,852		79,883
VIE, Primary Beneficiary
Current Assets
Cash and cash equivalents	167		311
Accounts receivable	989		839
Inventories	211		205
Other current assets	65		121
Total current assets	1,432		1,476
Plant, Property and Equipment	49,445		49,904
Equity Investments	979		865
Restricted Investments	1,150		950
Regulatory Assets	109		53
Goodwill	456		479
Other Long-Term Assets	93		59
Total assets	53,664		53,786
Current Liabilities
Notes payable	535		0
Accounts payable and other	1,703		1,866
Accrued interest	216		202
Current portion of long-term debt	575		2,062
Total current liabilities	3,029		4,130
Regulatory Liabilities	1,458		1,232
Other Long-Term Liabilities	51		70
Deferred Income Tax Liabilities	7		7
Long-Term Debt	13,904		12,387
Total liabilities	$ 18,449		$ 17,826

EQUITY INVESTMENTS (Tables)

12 Months Ended

Dec. 31, 2025

Equity Method Investments and Joint Ventures [Abstract]

Schedule of Equity Investments


(millions of Canadian $)	Ownership Interest at December 31, 2025		Income (Loss) from Equity Investments			Equity Investments
			year ended December 31			at December 31
			2025	2024	2023	2025	2024

Canadian Natural Gas Pipelines
TQM1	50	%	17	17	17	158	160
Coastal GasLink1	35	%	95	17	203	896	1,006
U.S. Natural Gas Pipelines
Northern Border	50	%	145	130	101	766	647
Millennium	47.5	%	70	95	109	(22)	(21)
Iroquois	50	%	70	100	98	216	221
Other	Various		16	16	16	137	135
Mexico Natural Gas Pipelines
Sur de Texas	60	%	94	283	78	1,427	1,403





Power and Energy Solutions
Bruce Power1	48.3	%	767	900	690	7,780	7,043
Other	Various		—	—	(2)	—	42
			1,274	1,558	1,310	11,358	10,636

1Classified as a VIE. Refer to Note 31, Variable interest entities, for additional information.

Summarized Financial Information of Equity Investments


year ended December 31	2025	2024	2023
(millions of Canadian $)

Income
Revenues	7,493	6,962	6,197
Operating and other expenses	(4,412)	(3,783)	(3,343)
Net income	2,405	3,026	2,457
Net income attributable to TC Energy	1,274	1,558	1,310


at December 31	2025	2024
(millions of Canadian $)

Balance Sheet
Current assets	3,438	3,959
Non-current assets	47,233	44,835
Current liabilities	(1,888)	(2,111)
Non-current liabilities	(22,389)	(21,729)

Schedule of Distribution Received and Contribution made to Equity Investments

Distributions received from equity investments and contributions made to equity investments for the years ended December 31, 2025, 2024 and 2023 were as follows:


year ended December 31	2025	2024	2023
(millions of Canadian $)

Distributions
Distributions received from operating activities of equity investments	1,616	1,607	1,158
Coastal GasLink LP subordinated loan repayment1,2	—	3,147	—
Other1	5	539	23

	1,621	5,293	1,181
Contributions1
Contributions made to other equity investments	986	719	918
Contributions to Coastal GasLink LP2	65	3,964	3,231
	1,051	4,683	4,149

1Included in Investing activities in the Consolidated statement of cash flows.

DISCONTINUED OPERATIONS - Cash Flows from Discontinued Operations (Details) - Disposed of by sale - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Summarized cash flows information for Discontinued operations [Abstract]
Net cash (used in) provided by operations	$ (185)	$ 670	$ 1,026
Net cash (used in) provided by investing activities	$ 24	$ (89)	$ 87

LOANS WITH AFFILIATES (Details) $ in Millions	12 Months Ended
LOANS WITH AFFILIATES (Details) $ in Millions	Dec. 31, 2025 CAD ($)	Dec. 31, 2024 CAD ($)	Dec. 31, 2023 CAD ($)	Dec. 31, 2025 USD ($)	Dec. 17, 2024 CAD ($)
Loans and Leases Receivable Disclosure [Line Items]
Payment to reduce company's funding commitment	$ 1,051,000,000	$ 4,683,000,000	$ 4,149,000,000
Subordinated debt \| Subordinated Loan Agreement
Loans and Leases Receivable Disclosure [Line Items]
Unused borrowing capacity, amount	163,000,000	$ 228,000,000
Line of credit \| Revolving credit facility \| Joint venture \| Sur de Texas
Loans and Leases Receivable Disclosure [Line Items]
Revolving credit facility, borrowing capacity				$ 270
Unused capacity	259,000,000			189
Long-term debt	111,000,000			$ 81
Coastal GasLink \| Canadian Natural Gas Pipelines
Loans and Leases Receivable Disclosure [Line Items]
Ownership interest percentage		35.00%
Coastal GasLink \| Subordinated debt \| Subordinated Loan Agreement \| Coastal GasLink
Loans and Leases Receivable Disclosure [Line Items]
Line of credit facility, outstanding amount					$ 3,147,000,000
Payment to reduce company's funding commitment	3,137,000,000
Coastal GasLink \| Subordinated debt \| Subordinated Demand Revolving Credit Facility Agreement \| Coastal GasLink
Loans and Leases Receivable Disclosure [Line Items]
Revolving credit facility, borrowing capacity	120,000,000	$ 120,000,000
Long-term debt	$ 0	$ 0
Sur de Texas \| Mexico Natural Gas Pipelines
Loans and Leases Receivable Disclosure [Line Items]
Ownership interest percentage	60.00%			60.00%

Consolidated balance sheet (Parenthetical) - shares shares in Millions	Dec. 31, 2025	Dec. 31, 2024
Statement of Financial Position [Abstract]
Common stock, shares authorized (in shares)	1,041	1,039
Common shares issued (in shares)	1,041	1,039
Common shares outstanding (in shares)	1,041	1,039

NOTES PAYABLE - Schedule of Notes Payable (Details) $ in Millions, $ in Millions	Dec. 31, 2025 CAD ($)	Dec. 31, 2025 USD ($)	Dec. 31, 2024 CAD ($)	Dec. 31, 2024 USD ($)
Notes payable
Outstanding	$ 1,200		$ 387
Notes payable
Notes payable
Denominated value	68	$ 348	0	$ 214
Notes payable \| TCPL
Notes payable
Outstanding	$ 584		$ 308
Weighted average interest rate per annum	3.90%	3.90%	4.70%	4.70%
Notes payable \| USA
Notes payable
Outstanding	$ 616	$ 449	$ 79	$ 55
Weighted average interest rate per annum	4.10%	4.10%	4.70%	4.70%

COMMON SHARES

12 Months Ended

Dec. 31, 2025

Common Stock, Number of Shares, Par Value and Other Disclosure [Abstract]

COMMON SHARES


	Number of Shares	Amount
	(thousands)	(millions of Canadian $)

Outstanding at January 1, 2023	1,017,962	28,995
Dividend reinvestment and share purchase plan	19,464	1,003
Exercise of options	62	4
Outstanding at December 31, 2023	1,037,488	30,002

Exercise of options	1,607	99
Outstanding at December 31, 2024	1,039,095	30,101




Exercise of options	1,740	117
Outstanding at December 31, 2025	1,040,835	30,218

Common Shares Issued and Outstanding

The Company is authorized to issue an unlimited number of common shares without par value.

Common Shares After Spinoff Transaction

On October 1, 2024, as part of the Spinoff Transaction, TC Energy shareholders received one new TC Energy common share and 0.2 of a South Bow common share in exchange for each TC Energy common share held.

Dividend Reinvestment and Share Purchase Plan

Under the Company's Dividend Reinvestment and Share Purchase Plan (DRP), eligible holders of common and preferred shares of TC Energy can reinvest their dividends and make optional cash payments to obtain additional TC Energy common shares. From August 31, 2022 to July 31, 2023, common shares were issued from treasury at a discount of two per cent to market prices over a specified period.

After July 31, 2023, common shares purchased with reinvested cash dividends under TC Energy's DRP are acquired on the open market at 100 per cent of the weighted average purchase price.

Basic and Diluted Net Income (Loss) per Common Share

Net income (loss) from continuing operations per common share is calculated by dividing Net income (loss) from continuing operations attributable to common shares by the weighted average number of common shares outstanding. Net income (loss) from discontinued operations is calculated by dividing Net income (loss) from discontinued operations by the weighted average number of common shares outstanding. The weighted average number of shares for the diluted earnings per share calculation includes options exercisable under TC Energy's Stock Option Plan and, from August 31, 2022 to July 31, 2023, common shares issuable from treasury under the DRP.


Weighted Average Common Shares Outstanding
at December 31
(millions)	2025	2024	2023

Basic	1,040	1,038	1,030
Diluted	1,040	1,038	1,030

Stock Options


	Number of Options	Weighted Average Exercise Prices1	Weighted Average Remaining Contractual Life
	(thousands)		(years)

Options outstanding at January 1, 2025	4,474	$60.69

Options exercised	(1,740)	$59.34
Options forfeited/expired	(373)	$62.77
Options Outstanding at December 31, 2025	2,361	$61.37	2.8
Options Exercisable at December 31, 2025	1,898	$63.22	2.4

1 Exercise prices of TC Energy stock options were adjusted in 2024 for the change in value of the TC Energy common shares following the Spinoff Transaction.

At December 31, 2025, an additional 3,994,688 common shares were reserved for future issuance from treasury under TC Energy's Stock Option Plan. The contractual life of options granted is seven years. Options may be exercised at a price determined at the time the option is awarded and vest equally on the anniversary date in each of the three years following the award. Forfeiture of stock options results from their expiration and, if not previously vested, upon resignation or termination of the option holder's employment. Commencing in 2024, the Company no longer issues stock options to employees or officers. The Company used a binomial model for determining the fair value of options granted and applied the following weighted average assumptions:


year ended December 31	2023

Weighted average fair value	$7.88
Expected life (years)1	5.1
Interest rate	2.9	%
Volatility2	24	%
Dividend yield	6.3	%

1Expected life is based on historical exercise activity.

2Volatility is derived based on the average of both the historical and implied volatility of the Company's common shares.

The amount expensed for stock options, with a corresponding increase in Additional paid-in capital, was $7 million in 2025 (2024 – $6 million; 2023 – $9 million). At December 31, 2025, unrecognized compensation costs related to non-vested stock options were $0.8 million and are expected to be fully recognized over a period of 0.1 years.

The following table summarizes additional stock option information:


year ended December 31	2025	2024	2023
(millions of Canadian $, unless otherwise noted)

Total intrinsic value of options exercised	20	17	—
Total fair value of options that have vested	62	99	76
Total options vested	0.8 million	1.5 million	1.5 million

As at December 31, 2025, the aggregate intrinsic values of the total options exercisable and the total options outstanding were $23 million and $34 million, respectively (2024 - $20 million and $34 million, respectively).

Shareholder Rights Plan

TC Energy's Shareholder Rights Plan is designed to provide the Board of Directors with sufficient time to explore and develop alternatives for maximizing shareholder value in the event of a takeover offer for the Company and to encourage the fair treatment of shareholders in connection with any such offer. Attached to each common share is one right that, under certain circumstances, entitles certain holders to purchase an additional common share of the Company.

COMMON SHARES - Summary of Additional Stock Options Information (Details) - CAD ($) shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Common Stock, Number of Shares, Par Value and Other Disclosure [Abstract]
Total intrinsic value of options exercised	$ 20	$ 17	$ 0
Total fair value of options that have vested	$ 62	$ 99	$ 76
Total options vested (in shares)	0.8	1.5	1.5

INCOME TAXES - Income Tax Payments (Refunds) (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Effective Income Tax Rate Reconciliation [Line Items]
Canada - federal	$ 73	$ 53	$ 61
Canada - provincial	17	6	(1)
Income tax payments (refunds)	543	387	791
United States
Effective Income Tax Rate Reconciliation [Line Items]
Foreign	368	302	692
Mexico
Effective Income Tax Rate Reconciliation [Line Items]
Foreign	84	34	26
Other foreign jurisdictions
Effective Income Tax Rate Reconciliation [Line Items]
Foreign	$ 1	$ (8)	$ 13

OTHER COMPREHENSIVE INCOME(LOSS) AND ACCUMULATED OTHER COMPREHENSIVE INCOME(LOSS) (Tables)

12 Months Ended

Dec. 31, 2025

Equity [Abstract]

Schedule of Components of Other Comprehensive Income (Loss)

Components of other comprehensive income (loss), including the portion attributable to non-controlling interests and related tax effects, were as follows:


year ended December 31, 2025	Before Tax Amount	Income Tax (Expense) Recovery	Net of Tax Amount
(millions of Canadian $)

Foreign currency translation gains and losses on net investment in foreign operations	(970)	(8)	(978)

Change in fair value of net investment hedges	1	—	1
Change in fair value of cash flow hedges (Note 27)	(31)	9	(22)
Reclassification to net income of (gains) losses on cash flow hedges	43	(12)	31
Unrealized actuarial gains (losses) on pension and other post-retirement benefit plans	104	(25)	79

Other comprehensive income (loss) on equity investments	2	—	2
Other Comprehensive Income (Loss)	(851)	(36)	(887)


year ended December 31, 2024	Before Tax Amount	Income Tax (Expense) Recovery	Net of Tax Amount
(millions of Canadian $)

Foreign currency translation gains and losses on net investment in foreign operations	1,582	20	1,602
Reclassification of foreign currency translation (gains) losses on net investment on disposal of foreign operations1	(25)	—	(25)
Change in fair value of net investment hedges	(23)	5	(18)
Change in fair value of cash flow hedges (Note 27)	46	(11)	35
Reclassification to net income of (gains) losses on cash flow hedges	(20)	4	(16)
Unrealized actuarial gains (losses) on pension and other post-retirement benefit plans	107	(24)	83
Reclassification to net income of actuarial (gains) losses on pension and other post-retirement benefit plans	(6)	—	(6)
Other comprehensive income (loss) on equity investments	230	(57)	173
Other Comprehensive Income (Loss)	1,891	(63)	1,828

1 Represents the controlling and non-controlling currency translation adjustment gains related to PNGTS. Refer to Note 29, Acquisitions and dispositions, for additional information.


year ended December 31, 2023	Before Tax Amount	Income Tax (Expense) Recovery	Net of Tax Amount
(millions of Canadian $)

Foreign currency translation gains and losses on net investment in foreign operations	(1,148)	7	(1,141)

Change in fair value of net investment hedges	23	(6)	17

Reclassification to net income of (gains) losses on cash flow hedges	97	(23)	74
Unrealized actuarial gains (losses) on pension and other post-retirement benefit plans	(15)	4	(11)

Other comprehensive income (loss) on equity investments	(283)	72	(211)
Other Comprehensive Income (Loss)	(1,326)	54	(1,272)

Schedule of Changes in Accumulated Other Comprehensive Income

The changes in AOCI by component, net of tax, are as follows:


(millions of Canadian $)	Currency Translation Adjustments	Cash Flow Hedges	Pension and Other Post-Retirement Benefit Plan Adjustments	Equity Investments	Total

AOCI balance at January 1, 2023	441	(109)	(44)	667	955
Other comprehensive income (loss) before reclassifications1	(231)	—	(11)	(195)	(437)
Amounts reclassified from AOCI	—	74	—	(16)	58
Net current period other comprehensive income (loss)	(231)	74	(11)	(211)	(379)
Impact of non-controlling interest2	(527)	—	—	—	(527)
AOCI balance at December 31, 2023	(317)	(35)	(55)	456	49
Other comprehensive income (loss) before reclassifications1	692	35	83	188	998
Amounts reclassified from AOCI3	(15)	(16)	(6)	(15)	(52)
Net current period other comprehensive income (loss)	677	19	77	173	946
Impact of non-controlling interest4	(21)	—	—	—	(21)
Impact of spinoff of Liquids Pipelines business5	(741)	—	—	—	(741)
AOCI balance at December 31, 2024	(402)	(16)	22	629	233
Other comprehensive income (loss) before reclassifications1	(466)	(22)	79	3	(406)
Amounts reclassified from AOCI6	—	31	—	(1)	30
Net current period other comprehensive income (loss)	(466)	9	79	2	(376)
Impact of non-controlling interest2	348	—	—	—	348
Impact of spinoff of Liquids Pipelines business5	542	—	—	—	542
AOCI balance at December 31, 2025	22	(7)	101	631	747

4Represents the AOCI attributable to the CFE's 13.01 per cent non-controlling equity interest in TGNH. Refer to Note 29, Acquisitions and dispositions, for additional information.

5Represents the AOCI and adjustment attributable to the Spinoff Transaction. Refer to Note 4, Discontinued operations and Note 2, Accounting policies, for additional information.

Schedule of Reclassifications out of Accumulated Other Comprehensive Income

Details about reclassifications out of AOCI into the Consolidated statement of income were as follows:


year ended December 31	Amounts reclassified from AOCI			Affected line item in the Consolidated statement of income
(millions of Canadian $)	2025	2024	2023

Cash flow hedges
Commodities	19	32	(85)	Revenues (Power and Energy Solutions)
Foreign Exchange	(50)	—	—	Interest expense and Foreign exchange gains (losses), net
Interest rate	(12)	(12)	(12)	Interest expense
	(43)	20	(97)	Total before tax
	12	(4)	23	Income tax (expense) recovery
	(31)	16	(74)	Net of tax
Pension and other post-retirement benefit plan adjustments
Amortization of actuarial gains (losses)	—	6	—	Plant operating costs and other1

	—	6	—	Total before tax
	—	—	—	Income tax (expense) recovery
	—	6	—	Net of tax
Equity investments
Equity income (loss)	3	19	22	Income (loss) from equity investments
	(2)	(4)	(6)	Income tax (expense) recovery
	1	15	16	Net of tax
Currency translation adjustments
Foreign currency translation gains on disposal of foreign operations	—	15	—	Net gain (loss) on sale of assets
	—	—	—	Income tax (expense) recovery
	—	15	—	Net of tax

1These AOCI components are included in the computation of net benefit cost (recovery). Refer to Note 26, Employee post-retirement benefits, for additional information.

NOTES PAYABLE - Schedule of Credit Facilities (Details) $ in Billions, $ in Billions	Dec. 31, 2025 CAD ($)	Dec. 31, 2025 USD ($)	Dec. 31, 2024 CAD ($)	Dec. 31, 2024 USD ($)
TCPL / TCPL USA \| TC Energy
Notes payable
Noncontrolling interests ownership			40.00%	40.00%
Revolving credit facility \| TCPL / TCPL USA
Notes payable
Revolving credit facility, borrowing capacity	$ 2.0		$ 2.0
Unused capacity	1.3
Revolving credit facility \| Maturing December 2030 \| TCPL
Notes payable
Revolving credit facility, borrowing capacity	3.0		$ 3.0
Unused capacity	$ 2.9
Revolving credit facility \| Maturing December 2026 \| TCPL / TCPL USA
Notes payable
Revolving credit facility, borrowing capacity		$ 1.0		$ 1.0
Unused capacity		0.8
Revolving credit facility \| Maturing December 2028 \| TCPL / TCPL USA
Notes payable
Revolving credit facility, borrowing capacity		2.5		2.5
Unused capacity		2.3
Revolving credit facility \| Maturing December 2028 \| COLUMBIA PIPELINES HOLDING COMPANY LLC
Notes payable
Revolving credit facility, borrowing capacity		1.5		$ 1.5
Unused capacity		$ 1.1

COMMITMENTS, CONTINGENCIES AND GUARANTEES - Narrative (Details) $ in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2025 CAD ($) Megawatt	Dec. 31, 2025 USD ($)	Dec. 31, 2024 CAD ($)	Dec. 31, 2023 CAD ($)
Other Commitments
Purchase commitment	$ 340		$ 347	$ 335
Capital expenditure commitment	800
Contingencies
Amount accrued related to operating facilities for the estimated expenses to remediate the sites	$ 6		$ 8
Columbia Pipeline Group shareholders \| Columbia Pipelines Group
Contingencies
Damages sought		$ 350
Capital expenditures
Other Commitments
Power purchase agreement, planned capacity (in megawatts) \| Megawatt	750
Capital expenditures \| U.S. Natural Gas Pipelines
Other Commitments
Purchase commitment	$ 600

NON-CONTROLLING INTERESTS (Tables)

12 Months Ended

Dec. 31, 2025

Noncontrolling Interest [Abstract]

Schedule of Non-controlling Interests


(millions of Canadian $)	Non-Controlling Interests Ownership at December 31, 2025			Income (Loss) Attributable to Non-Controlling Interests			Non-Controlling Interests
				year ended December 31			at December 31
				2025	2024	2023	2025	2024

Columbia Gas and Columbia Gulf	40	%	1	631	571	143	8,779	9,844
Portland Natural Gas Transmission System	nil		1	—	30	41	—	—
Texas Wind Farms	100	%	1,2	(38)	(29)	(38)	123	168
TGNH	13.01	%	1	(18)	109	—	702	756
				575	681	146	9,604	10,768

1 Refer to Note 29, Acquisitions and dispositions, for additional information.

RATE-REGULATED BUSINESSES

12 Months Ended

Dec. 31, 2025

Regulated Operations [Abstract]

RATE-REGULATED BUSINESSES

TC Energy's businesses that apply RRA currently include almost all of the Canadian, U.S. and Mexico natural gas pipelines and certain U.S. natural gas storage operations. Rate-regulated businesses account for and report assets and liabilities consistent with the resulting economic impact of the established rates, provided the rates are designed to recover the costs of providing the service and the competitive environment makes it probable that such rates can be charged and collected. Certain revenues and expenses subject to utility regulation or rate determination that would otherwise be reflected in the statement of income are deferred on the balance sheet and are expected to be recovered from or refunded to customers in future service rates.

Canadian Regulated Operations

The majority of TC Energy's Canadian natural gas pipelines are regulated by the CER under the Canadian Energy Regulator Act. The CER regulates the construction and operation of facilities and the terms and conditions of services, including rates, for the Company's Canadian regulated natural gas transmission systems under federal jurisdiction. The Impact Assessment Agency of Canada continues to assess designated projects.

TC Energy's Canadian natural gas transmission services are supplied under natural gas transportation tariffs that provide for cost recovery, including return of and on capital as approved by the CER. Subject to the terms of any settlement, rates charged for these services are typically set through a process that involves filing an application with the regulator wherein forecasted operating costs, including a return of and on capital, determine the revenue requirement for the upcoming year or multiple years. To the extent actual costs and revenues are more or less than forecasted costs and revenues, the regulator generally allows the difference to be deferred to a future period and recovered or refunded in rates at that time. Differences between actual and forecasted costs that the regulator does not allow to be deferred are included in the determination of net income in the year they occur. The Company's most significant regulated Canadian natural gas pipelines, based on total operated pipe length, are described below.

NGTL System

The NGTL System currently operates under the terms of the 2025-2029 Revenue Requirement Settlement, which was approved by the CER in September 2024 (the 2025-2029 NGTL Settlement). The 2025-2029 NGTL Settlement enables an investment framework that supports the approval by the Company's Board of Directors (Board) to allocate up to $3.3 billion of capital towards progression of the Multi-Year Growth Plan for expansion facilities to meet commitments on the NGTL System. It is comprised of multiple distinct projects with various targeted in-service dates, beginning in 2026, subject to final Company and regulatory approvals.

The 2025-2029 NGTL Settlement maintains an ROE of 10.1 per cent on 40 per cent deemed common equity while increasing NGTL System depreciation rates, with an incentive that allows the NGTL System the opportunity to further increase depreciation rates if tolls fall below specified levels or if growth projects are undertaken. The 2025-2029 NGTL Settlement introduces a new incentive mechanism to reduce both physical emissions and emission compliance costs, which builds on the incentive mechanism for certain operating costs where variances from projected amounts and emissions savings are shared with customers. A provision for review exists in the 2025-2029 NGTL Settlement if tolls exceed a pre-determined level or if final Company approvals of the multi-year growth plan are not obtained.

NGTL System's 2023 and 2024 results reflected the terms of the 2020-2024 Revenue Requirement Settlement which included an approved ROE of 10.1 per cent on 40 per cent deemed common equity, provided the NGTL System the opportunity to increase depreciation rates if tolls fell below specified levels and provided an incentive mechanism for certain operating costs where variances from projected amounts were shared with its customers.

Canadian Mainline

In April 2020, the CER approved the six-year unanimous negotiated settlement (the 2021-2026 Mainline Settlement) effective January 1, 2021. Similar to the previous settlement, the 2021-2026 Mainline Settlement maintains a base equity return of 10.1 per cent on 40 per cent deemed common equity and includes an incentive to either achieve cost efficiencies and/or increase revenues on the pipeline with a beneficial sharing mechanism to both customers and TC Energy.

Toll stabilization is achieved using deferral accounts, including the toll-stabilization account and the short-term adjustment accounts (STAA), which capture the surplus or shortfall between system revenues and cost of service each year under the 2021-2026 Mainline Settlement. A portion of the STAA commenced amortization in 2023 and the remainder commenced amortization in 2024, according to the terms outlined in the 2021-2026 Mainline Settlement as predetermined thresholds per the settlement agreement were met.

U.S. Regulated Operations

TC Energy's U.S. regulated natural gas pipelines operate under the provisions of the Natural Gas Act of 1938 (NGA), the Natural Gas Policy Act of 1978 and the Energy Policy Act of 2005, and are subject to the jurisdiction of FERC. The NGA grants FERC authority over the construction, acquisition and operation of pipelines and related facilities, including the regulation of tariffs which incorporates maximum and minimum rates for services and allows U.S. regulated natural gas pipelines to discount or negotiate rates on a non-discriminatory basis. The Company's most significant regulated U.S. natural gas pipelines, based on effective ownership and total operated pipe length, are described below.

Columbia Gas

Columbia Gas' natural gas transportation and storage services are provided under a tariff at rates subject to FERC approval. Columbia Gas operates under a settlement approved by FERC in October 2025 (the 2025 Columbia Gas Settlement). As part of the settlement, there is a moratorium on any further rate changes until April 1, 2028, and Columbia Gas must file for new rates with an effective date no later than April 1, 2031. The settlement also included additional rate step ups in April 2026 and April 2027 to reflect anticipated modernization-related spend.

ANR Pipeline

ANR Pipeline operates under rates established through a 2022 FERC-approved rate settlement (the 2022 ANR Settlement). In 2023, previously accrued rate refund liabilities, including interest, were refunded to customers. The 2022 ANR Settlement included a moratorium on rate changes until November 1, 2025, and required ANR to file for new rates with an effective date no later than August 1, 2028. The settlement also provided for a rate step up effective August 2024 related to certain modernization projects and an additional rate step up effective no later than August 1, 2028. In April 2025, ANR filed a Section 4 Rate Case with FERC requesting an increase to maximum transportation rates effective November 1, 2025, subject to refund. As of December 31, 2025, ANR is pursuing a collaborative process to find a mutually beneficial outcome with customers.

Columbia Gulf

Columbia Gulf operates under a settlement approved by FERC in August 2023, effective March 1, 2024 (the 2023 Columbia Gulf Settlement). The 2023 Columbia Gulf Settlement includes a moratorium on further rate changes through February 28, 2027, and Columbia Gulf must file for new rates no later than March 1, 2029.

Great Lakes

Great Lakes operates under a rate settlement approved by FERC in April 2022 (the 2022 Great Lakes Settlement), which maintains Great Lakes’ existing maximum transportation rates through October 31, 2025. The 2022 Great Lakes Settlement contained a moratorium until October 31, 2025. In April 2025, Great Lakes filed a Section 4 Rate Case with FERC requesting an increase to maximum transportation rates effective November 1, 2025, subject to refund. As of December 31, 2025, Great Lakes is pursuing a collaborative process to find a mutually beneficial outcome with customers.

Tuscarora

Tuscarora operates under rates established as part of the FERC-approved rate settlement in September 2023 (the 2023 Tuscarora Settlement). The 2023 Tuscarora Settlement provided for phased rate reductions as of February 1, 2023, and additionally as of February 1, 2025. The 2023 Tuscarora Settlement contains a moratorium that expires December 1, 2028. Tuscarora is required to file new rates by December 1, 2028.

Gas Transmission Northwest

Gas Transmission Northwest (GTN) operates under rates established as part of the FERC-approved rate settlement in October 2024 (the 2024 GTN Settlement). The 2024 GTN Settlement maintains the currently effective rates (the pre-filed rates) from April 1, 2024, through March 31, 2026. GTN will then reduce its pre-filed rates starting on April 1, 2026, through March 31, 2027. The 2024 GTN Settlement contains a moratorium that expires March 31, 2027. GTN is required to file new rates by April 1, 2027.

Mexico Regulated Operations

TC Energy’s natural gas pipelines in Mexico are regulated by the CNE. While the majority of the Company's capacity is subscribed under a long-term contractual rate, the CNE sets rates for interruptible services. The rates in effect on TC Energy's Mexico natural gas pipelines provide for cost recovery, including a return of and on invested capital.

Regulatory Assets and Liabilities


at December 31	Remaining Recovery/ Settlement Period (years)	2025	2024
(millions of Canadian $)

Regulatory Assets
Deferred income taxes1	n/a	2,760	2,593
Operating and debt-service regulatory assets2	1	—	56

Foreign exchange on long-term debt1,3	1-4	23	39
Other	n/a	188	117
		2,971	2,805
Less: Current portion included in Other current assets (Note 7)		58	123
		2,913	2,682
Regulatory Liabilities

Pipeline abandonment trust balances4	n/a	3,143	2,686
Deferred income taxes – U.S. Tax Reform5	n/a	1,098	1,197
Canadian Mainline short-term adjustment and toll-stabilization accounts6,7	n/a	705	553
Cost of removal8	n/a	407	376
Canadian Mainline bridging amortization account6	5	268	322
Pensions and other post-retirement benefits9	n/a	266	122
Deferred income taxes1	n/a	195	188
Operating and debt-service regulatory liabilities2	1	134	50
ANR post-employment and retirement benefits other than pension10	n/a	43	45
Canadian Mainline long-term adjustment account6,11	1	37	74

Other	n/a	77	43
		6,373	5,656
Less: Current portion included in Accounts payable and other (Note 16)		532	353
		5,841	5,303

2Operating and debt-service regulatory assets and liabilities represent the accumulation of cost and revenue variances to be included in determination of rates in the following year.

6These regulatory accounts are used to capture revenue and cost variances plus toll-stabilization adjustments during the 2015-2030 settlement term.

11Under the terms of the 2021-2026 Mainline Settlement, $223 million is amortized over the six-year settlement term.

FOREIGN EXCHANGE (GAINS) LOSSES, NET (Tables)

12 Months Ended

Dec. 31, 2025

Foreign Currency [Abstract]

Schedule of Foreign Exchange Contracts


year ended December 31	2025	2024	2023
(millions of Canadian $)

Derivative instruments held for trading (Note 27)	(352)	418	(401)
Other	195	(271)	81
	(157)	147	(320)

COMMITMENTS, CONTINGENCIES AND GUARANTEES

12 Months Ended

Dec. 31, 2025

Commitments and Contingencies Disclosure [Abstract]

COMMITMENTS, CONTINGENCIES AND GUARANTEES

Commitments

TC Energy and its affiliates have long-term natural gas transportation and natural gas purchase arrangements as well as other purchase obligations, all of which are transacted at market prices and in the normal course of business. Purchases under these contracts in 2025 were $340 million (2024 – $347 million; 2023 – $335 million).

The Company has entered into PPAs with solar and wind-power generating facilities with terms extending to 2038 that require the purchase of generated energy and associated environmental attributes. At December 31, 2025, the total planned capacity secured under the PPAs is approximately 750 MW with the generation subject to operating availability and capacity factors. These PPAs do not meet the definition of a lease or derivative. Future payments and their timing cannot be reasonably estimated as they are dependent on when certain underlying facilities are placed into service and the amount of energy generated. Certain of these purchase commitments have offsetting sale PPAs for all or a portion of the related output from the facility.

Capital expenditure commitments include obligations related to the construction of growth projects and are based on the projects proceeding as planned. Changes to these projects, including cancellation, would reduce or possibly eliminate these commitments as a result of cost mitigation efforts. At December 31, 2025, TC Energy had approximately $0.8 billion of capital expenditure commitments, primarily consisting of $0.6 billion for its U.S. natural gas pipelines, primarily related to construction costs associated with ANR and other pipeline projects.

Contingencies

TC Energy is subject to laws and regulations governing environmental quality and pollution control. At December 31, 2025, the Company had accrued approximately $6 million (2024 – $8 million) related to operating facilities, which represents the present value of the estimated future amount it expects to spend to remediate the sites. However, additional liabilities may be incurred as assessments take place and remediation efforts continue.

TC Energy and its subsidiaries are subject to various legal proceedings, arbitrations and actions arising in the normal course of business. The Company assesses all legal matters on an ongoing basis, including those of its equity investments, to determine if they meet the requirements for disclosure or accrual of a contingent loss.

The following contingencies were concluded during the year ended December 31, 2025:

2016 Columbia Pipeline Acquisition Lawsuit

In 2018, former shareholders of Columbia Pipeline Group Inc. (CPG) commenced a class action lawsuit related to the acquisition of CPG by TC Energy in 2016. In 2023, the Delaware Chancery Court (the Court) found that the former CPG executives breached their fiduciary duties, that the former CPG Board breached its duty of care in overseeing the sale process and that TC Energy aided and abetted those breaches. TC Energy's allocated share of damages was an estimated US$350 million, plus post-judgment interest. TC Energy appealed the decision to the Delaware Supreme Court and on June 17, 2025, the Supreme Court issued its decision reversing the Court’s finding of liability against TC Energy. On July 10, 2025, the Court granted the final order vacating its prior judgment and dismissing plaintiffs’ claims against TC Energy. As a result, this matter is now concluded in TC Energy’s favour with no liability. There is no further right of appeal.

Pacific Atlantic Pipeline Construction Ltd.

Coastal GasLink LP and Pacific Atlantic Pipeline Construction Ltd., one of the prime contractors on the Coastal GasLink pipeline, and their parent company Bonatti S.p.A, have reached a mutually acceptable resolution to their disputes. The settlement is not an admission of liability by either party and the parties have mutually released their respective claims in the arbitration. Details of the arbitration and the settlement are confidential, but it does include the retention by Coastal GasLink LP of the letter of credit funds drawn in 2024 and the settlement did not have a material impact on TC Energy's financial statements.

Macro Spiecapag Coastal GasLink Joint Venture

Coastal GasLink LP and Macro Spiecapag Coastal GasLink Joint Venture have reached a mutually acceptable resolution to their disputes. The settlement is not an admission of liability by either party and the parties have mutually released their respective claims in the arbitration. Details of the arbitration and the settlement are confidential and the settlement did not have a material impact on TC Energy’s financial statements.

Guarantees

TC Energy and its partner on the Sur de Texas pipeline, IEnova, have jointly guaranteed the financial performance of the entity which owns the pipeline. Such agreements include a guarantee and a letter of credit which are primarily related to the delivery of natural gas.

TC Energy and its joint venture partner on Bruce Power, BPC Generation Infrastructure Trust, have each severally guaranteed certain contingent financial obligations of Bruce Power related to a lease agreement and contractor and supplier services.

The Company and its partners in certain other jointly-owned entities have either: i) jointly and severally; ii) jointly; or iii) severally guaranteed the financial performance of these entities. Such agreements include guarantees and letters of credit which are primarily related to delivery of natural gas. For certain of these entities, any payments made by TC Energy under these guarantees in excess of its ownership interest are to be reimbursed by its partners.

The carrying value of these guarantees has been recorded in Other long-term liabilities on the Consolidated balance sheet. Information regarding the Company’s guarantees were as follows:


at December 31		2025		2024
	Term	Potential Exposure1	Carrying Value	Potential Exposure1	Carrying Value
(millions of Canadian $)

Bruce Power	Renewable to 2065	88	—	88	—
Sur de Texas	Renewable to 2053	78	—	93	—
Other jointly-owned entities	to 2032	54	1	59	1
		220	1	240	1

1TC Energy's share of the potential estimated current or contingent exposure.

EMPLOYEE POST-RETIREMENT BENEFITS (Tables)

12 Months Ended

Dec. 31, 2025

Retirement Benefits [Abstract]

Schedule of Contributions for Defined Benefit Plans

Total cash contributions by the Company for employee post-retirement benefits were as follows:


year ended December 31	2025	2024	2023
(millions of Canadian $)

DB Plans	—	—	28
Other post-retirement benefit plans	8	8	9
Savings and DC Plans	72	71	64
	80	79	101

Schedule of Change in Benefit Obligations, Change in Plan Assets, and Funded Status

The Company's funded status was comprised of the following:


at December 31	Pension Benefit Plans		Other Post-Retirement Benefit Plans
(millions of Canadian $)	2025	2024	2025	2024

Change in Benefit Obligation1
Benefit obligation – beginning of year	3,342	3,356	288	285
Service cost	101	108	1	1
Interest cost	162	160	15	14
Employee contributions	11	11	2	2
Benefits paid	(228)	(194)	(22)	(24)
Actuarial (gain) loss2	(80)	(39)	(26)	(5)
South Bow - transition of benefit obligation3	—	(118)	—	(1)

Foreign exchange rate changes	(35)	58	(9)	16
Benefit obligation – end of year	3,273	3,342	249	288
Change in Plan Assets
Plan assets at fair value – beginning of year	3,948	3,697	339	358
Actual return on plan assets	390	485	22	17
Employer contributions4,5	—	—	8	(41)
Employee contributions	11	11	2	2
Benefits paid	(228)	(194)	(22)	(25)

South Bow - transition of plan assets3	—	(119)	—	—
Foreign exchange rate changes	(40)	68	(16)	28
Plan assets at fair value – end of year	4,081	3,948	333	339
Funded Status – Plan Surplus	808	606	84	51

1The benefit obligation for the Company’s pension benefit plans represents the projected benefit obligation. The benefit obligation for the Company’s other post-retirement benefit plans represents the accumulated post-retirement benefit obligation.

2The increase in the actuarial (gain) loss on the defined benefit plan obligation is primarily attributable to an increase in the weighted discount rate from 4.90 per cent in 2024 to 5.10 per cent in 2025 and an increase in the rate of return. The actuarial (gain) loss on the OPEB Plan obligation is primarily due to changes in demographic assumptions.

3Reflects the impact of the Spinoff Transaction of the Liquids Pipelines business on October 1, 2024.

4The Company reduced letters of credit by $111 million in the Canadian DB Plan (2024 – $133 million) for funding purposes.

5OPEB surplus of nil (2024 - $49 million) was transferred to pay future active employee medical expenses.

Additional pension benefit plan assets were as follows:


at December 31	Pension Benefit Plans
(millions of Canadian $)	2025	2024

TC Energy plan assets at fair value	4,081	3,948
South Bow plan assets held in trust1	17	110
Plan assets at fair value – end of year	4,098	4,058

1 Related to the transfer of pension assets to South Bow. The remaining South Bow pension assets will be adjusted to fair value on the date of the transfer. At December 31, 2025, $17 million is reflected in Other current assets of discontinued operations (2024 - $110 million reflected in Other long-term assets of discontinued operations).

Schedule of Amounts Recognized in the Balance Sheet for its DB Plans and Other Post-Retirement Benefits Plans

The amounts recognized on the Company's Consolidated balance sheet for its DB Plans and other post-retirement benefits plans were as follows:


at December 31	Pension Benefit Plans		Other Post-Retirement Benefit Plans
(millions of Canadian $)	2025	2024	2025	2024

Other long-term assets (Note 14)	808	606	159	152
Accounts payable and other	—	—	(6)	(7)
Other long-term liabilities (Note 17)	—	—	(69)	(94)
	808	606	84	51

Schedule of Benefit Obligations in Excess of Fair Value of Plan Assets

Included in the above benefit obligation and fair value of plan assets were the following amounts for plans that were not fully funded:


at December 31	Pension Benefit Plans		Other Post-Retirement Benefit Plans
(millions of Canadian $)	2025	2024	2025	2024

Projected benefit obligation1	—	—	(76)	(101)
Plan assets at fair value	—	—	—	—
Funded Status – Plan Deficit	—	—	(76)	(101)

1The projected benefit obligation for the pension benefit plans differs from the accumulated benefit obligation in that it includes an assumption with respect to future compensation levels.

Schedule of Accumulated Benefit Obligations in Excess of Fair Value of Plan Assets for All DB Plans

The funded status based on the accumulated benefit obligation for all DB Plans was as follows:


at December 31	2025	2024
(millions of Canadian $)

Accumulated benefit obligation	(3,086)	(3,097)
Plan assets at fair value1	4,098	4,058
Funded Status – Plan Surplus	1,012	961

1 Includes an estimated $17 million (2024 - $110 million) for future transfer to South Bow. The remaining South Bow pension assets will be adjusted to fair value on the date of the transfer.

Schedule of Weighted Average Asset Allocations and Target Allocations by Asset Category

The Company pension plans' weighted average asset allocations and target allocations by asset category were as follows:


at December 31	Percentage of Plan Assets				Target Allocations
	2025		2024		2025

Fixed income securities	45	%	37	%	30% to 55%
Equity securities	40	%	49	%	20% to 55%
Other investments	15	%	14	%	10% to 35%
	100	%	100	%

Schedule of Allocation of Plan Assets, Employer and Related Party Securities

Fixed income and equity securities include the Company's and its related parties debt and common shares as follows:


at December 31			Percentage of Plan Assets
(millions of Canadian $)	2025	2024	2025		2024

Fixed income securities	26	44	0.6	%	1.1	%
Equity securities	2	3	0.1	%	0.1	%

Schedule of Plan Assets for DB Plans and Other Post-Retirement Benefits Measured at Fair Value

The following table presents plan assets for DB Plans and OPEB Plans measured at fair value, which have been categorized into the three categories based on a fair value hierarchy. Refer to Note 27, Risk management and financial instruments, for additional information.


at December 31	Quoted Prices in Active Markets (Level I)		Significant Other Observable Inputs (Level II)		Significant Unobservable Inputs (Level III)		Total		Percentage of Total Portfolio
(millions of Canadian $, unless otherwise noted)
	2025	2024	2025	2024	2025	2024	2025	2024	2025		2024

Asset Category1
Cash and Cash Equivalents	130	138	—	—	—	—	130	138	3	%	3	%
Equity Securities:
Canadian	129	128	—	—	—	—	129	128	3	%	3	%
U.S.	969	1,234	—	—	—	—	969	1,234	22	%	28	%
International	107	182	220	209	—	—	327	391	7	%	9	%
Global	—	—	104	100	—	—	104	100	2	%	2	%
Emerging	33	66	132	150	—	—	165	216	4	%	5	%
Fixed Income Securities:
Canadian Bonds:
Federal	—	—	16	55	—	—	16	55	—		1	%
Provincial	—	—	514	312	—	—	514	312	12	%	7	%
Municipal	—	—	19	14	—	—	19	14	—		—
Corporate	—	—	483	323	—	—	483	323	11	%	7	%
U.S. Bonds:
Federal	147	151	260	255	—	—	407	406	9	%	9	%

Municipal	—	—	1	1	—	—	1	1	—		—
Corporate	185	246	193	158	—	—	378	404	9	%	9	%
International:
Government	3	4	19	17	—	—	22	21	1	%	1	%
Corporate	—	—	96	66	—	—	96	66	2	%	2	%
Mortgage backed	40	37	20	23	—	—	60	60	1	%	1	%
Net forward contracts	—	—	(184)	(201)	—	—	(184)	(201)	(4	%)	(4	%)

Other Investments:
Real estate	—	—	—	—	292	276	292	276	7	%	6	%
Infrastructure	—	—	—	—	315	282	315	282	7	%	7	%
Private equity funds	—	—	—	—	55	32	55	32	1	%	1	%
Funds held on deposit	130	138	—	—	—	—	130	138	3	%	3	%
Derivatives	—	—	3	1	—	—	3	1	—		—
	1,873	2,324	1,896	1,483	662	590	4,431	4,397	100	%	100	%

1 Includes $17 million (2024 - $110 million) for future transfer to South Bow.

Schedule of the Net Change in the Level III Fair Value Category

The following table presents the net change in the Level III fair value category:


(millions of Canadian $, pre-tax)

Balance at December 31, 2023			562
Purchases and sales			(15)
Realized and unrealized gains (losses)			43
Balance at December 31, 2024			590
Purchases and sales			59
Realized and unrealized gains (losses)			13
Balance at December 31, 2025			662

Schedule of Estimated Future Benefit Payments

The following are estimated future benefit payments, which reflect expected future service:


at December 31		Other Post-Retirement Benefits
(millions of Canadian $)	Pension Benefits

2026	223	22
2027	224	22
2028	226	22
2029	228	21
2030	230	21
2031 to 2035	1,158	98

Schedule of Weighted Average Assumptions Used in Calculating Benefit Obligation

The significant weighted average actuarial assumptions adopted in measuring the Company's benefit obligations were as follows:


at December 31	Pension Benefit Plans				Other Post-Retirement Benefit Plans
	2025		2024		2025		2024

Discount rate	5.10	%	4.90	%	5.45	%	5.45	%
Rate of compensation increase	3.05	%	3.05	%	—		—

Schedule of Significant Weighted Average Actuarial Assumptions Adopted in Measuring Net Benefit Plan Costs

The significant weighted average actuarial assumptions adopted in measuring the Company's net benefit plan costs were as follows:


year ended December 31	Pension Benefit Plans						Other Post-Retirement Benefit Plans
	2025		2024		2023		2025		2024		2023

Discount rate	4.90	%	4.75	%	5.15	%	5.45	%	5.15	%	5.45	%
Expected long-term rate of return on plan assets	6.75	%	6.60	%	6.45	%	4.75	%	4.50	%	4.50	%
Rate of compensation increase	3.05	%	3.15	%	3.25	%	—		—		—

Schedule of Net Benefit Costs

The net benefit cost recognized for the Company’s pension benefit plans and other post-retirement benefit plans was as follows:


year ended December 31	Pension Benefit Plans			Other Post-Retirement Benefit Plans
(millions of Canadian $)	2025	2024	2023	2025	2024	2023

Service cost1	101	108	93	1	1	3
Other components of net benefit cost1
Interest cost	162	160	158	15	14	16
Expected return on plan assets	(250)	(248)	(234)	(16)	(14)	(16)
Amortization of past service cost	—	—	—	(2)	—	—
Amortization of regulatory asset	—	—	—	—	(2)	—
	(88)	(88)	(76)	(3)	(2)	—
Net Benefit Cost Recognized	13	20	17	(2)	(1)	3

1 Service cost and other components of net benefit cost are included in Plant operating costs and other in the Consolidated statement of income.

Schedule of the Pre-Tax Amounts Recognized in AOCI

Pre-tax amounts recognized in AOCI were as follows:


at December 31	2025		2024		2023
	Pension Benefits	Other Post- Retirement Benefits	Pension Benefits	Other Post- Retirement Benefits	Pension Benefits	Other Post- Retirement Benefits
(millions of Canadian $)




Net loss (gain)	(114)	(13)	(24)	—	71	6

Schedule of the Pre-Tax Amounts Recognized in OCI

Pre-tax amounts recognized in OCI were as follows:


year ended December 31	2025		2024		2023
	Pension Benefits	Other Post- Retirement Benefits	Pension Benefits	Other Post- Retirement Benefits	Pension Benefits	Other Post- Retirement Benefits
(millions of Canadian $)

Amortization of net gain (loss) from AOCI to net income	—	—	6	—	—	—



Funded status adjustment	(91)	(13)	(101)	(6)	33	(18)
	(91)	(13)	(95)	(6)	33	(18)

DESCRIPTION OF TC ENERGY'S BUSINESS (Details)	12 Months Ended
DESCRIPTION OF TC ENERGY'S BUSINESS (Details)	Dec. 31, 2025 segment plant km mi Bcf
Segment Reporting Information [Line Items]
Number of business segments in which the entity operates (in segments) \| segment	4
Number of reportable segments (in segments) \| segment	4
Canadian Natural Gas Pipelines
Segment Reporting Information [Line Items]
Investments of regulated natural gas pipelines (in kilometers) \| km	40,984
Investments of regulated natural gas pipelines (in miles) \| mi	25,467
U.S. Natural Gas Pipelines
Segment Reporting Information [Line Items]
Investments of regulated natural gas pipelines (in kilometers) \| km	49,587
Investments of regulated natural gas pipelines (in miles) \| mi	30,811
Investments of regulated natural gas storage facilities (in billion cubic feet) \| Bcf	532
Mexico Natural Gas Pipelines
Segment Reporting Information [Line Items]
Investments of regulated natural gas pipelines (in kilometers) \| km	3,600
Investments of regulated natural gas pipelines (in miles) \| mi	2,235
Power and Energy Solutions
Segment Reporting Information [Line Items]
Number of electrical power generation plants (in plants) \| plant	4,650
Non-regulated natural gas storage facilities (in billion cubic feet) \| Bcf	118

CHANGES IN OPERATING WORKING CAPITAL

12 Months Ended

Dec. 31, 2025

CHANGES IN OPERATING WORKING CAPITAL

CHANGES IN OPERATING WORKING CAPITAL


year ended December 31	2025¹	2024¹	2023¹
(millions of Canadian $)

(Increase) decrease in Accounts receivable	(332)	(13)	(394)
(Increase) decrease in Inventories	(55)	(16)	(56)

(Increase) decrease in Other current assets	(159)	(97)	618
Increase (decrease) in Accounts payable and other	13	365	(206)
Increase (decrease) in Accrued interest	30	(40)	245

(Increase) Decrease in Operating Working Capital	(503)	199	207

1 Includes continuing and discontinued operations.

GOODWILL - Acquisitions (Details) $ in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2025 CAD ($)	Dec. 31, 2025 USD ($)	Dec. 31, 2024 CAD ($)	Dec. 31, 2024 USD ($)
Goodwill
Balance at the beginning of the period	$ 13,670	$ 9,490
Balance at the end of the period	13,016	9,490	$ 13,670	$ 9,490
U.S. Natural Gas Pipelines
Goodwill
Balance at the beginning of the period	13,670		12,532
Foreign exchange rate changes	(654)		1,138
Balance at the end of the period	13,016		13,670
Goodwill, gross		10,828		10,828
Goodwill, net		1,338		1,338
Columbia
Goodwill
Balance at the beginning of the period	10,588	7,351
Balance at the end of the period	10,082	7,351	10,588	7,351
ANR
Goodwill
Balance at the beginning of the period	2,803	1,946
Balance at the end of the period	2,669	1,946	2,803	1,946
Great Lakes
Goodwill
Balance at the beginning of the period	176	122
Balance at the end of the period	167	122	176	122
North Baja
Goodwill
Balance at the beginning of the period	70	48
Balance at the end of the period	66	48	70	48
Tuscarora
Goodwill
Balance at the beginning of the period	33	23
Balance at the end of the period	$ 32	$ 23	$ 33	$ 23

DISCONTINUED OPERATIONS - Income from Discontinued Operations (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Asset impairment charge and other		$ 21	$ (4)
Net Income (Loss) from Discontinued Operations, Net of Tax	$ (212)	395	612
Liquids Pipelines Segment
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Revenues	0	2,217	2,667
Income (Loss) from Equity Investments	0	50	67
Plant operating costs and other	216	806	814
Commodity purchases resold	0	387	437
Property taxes	0	84	116
Depreciation and amortization	0	253	332
Operating and other expenses	245	1,551	1,695
Segmented Earnings (Losses) from Discontinued Operations	(245)	716	1,039
Interest expense	0	218	297
Interest income and other	(28)	(21)	30
Financial charges	(28)	197	327
Income (Loss) from Discontinued Operations before Income Taxes	(217)	519	712
Income tax expense (recovery)	(5)	124	100
Net Income (Loss) from Discontinued Operations, Net of Tax	$ (212)	$ 395	$ 612

SEGMENTED INFORMATION - Revenue from External Customers by Geographic Areas (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Segment Reporting Information [Line Items]
Revenues	$ 15,239	$ 13,771	$ 13,267
Canada – domestic
Segment Reporting Information [Line Items]
Revenues	5,617	5,579	5,337
Canada – export
Segment Reporting Information [Line Items]
Revenues	968	953	821
United States
Segment Reporting Information [Line Items]
Revenues	7,204	6,369	6,263
Mexico
Segment Reporting Information [Line Items]
Revenues	$ 1,450	$ 870	$ 846

- Definition

Amount of revenue recognized from goods sold, services rendered, insurance premiums, or other activities that constitute an earning process. Includes, but is not limited to, investment and interest income before deduction of interest expense when recognized as a component of revenue, and sales and trading gain (loss).

+ References

Reference 1: http://www.xbrl.org/2003/role/exampleRef
-Topic 815
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 4A
-Subparagraph (c)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480434/815-10-50-4A

Reference 2: http://www.xbrl.org/2003/role/disclosureRef
-Topic 942
-SubTopic 235
-Name Accounting Standards Codification
-Section S50
-Paragraph 1
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147478671/942-235-S50-1

Reference 3: http://www.xbrl.org/2003/role/disclosureRef
-Topic 942
-SubTopic 235
-Name Accounting Standards Codification
-Section S99
-Paragraph 1
-Subparagraph (SX 210.9-05(b)(2))
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147477314/942-235-S99-1

Reference 4: http://www.xbrl.org/2003/role/disclosureRef
-Topic 280
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 41
-Subparagraph (a)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482810/280-10-50-41

Reference 5: http://www.xbrl.org/2003/role/disclosureRef
-Topic 280
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 42
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482810/280-10-50-42

Reference 6: http://www.xbrl.org/2003/role/disclosureRef
-Topic 235
-SubTopic 10
-Name Accounting Standards Codification
-Section S50
-Paragraph 1
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480738/235-10-S50-1

Reference 7: http://www.xbrl.org/2003/role/disclosureRef
-Topic 235
-SubTopic 10
-Name Accounting Standards Codification
-Section S99
-Paragraph 1
-Subparagraph (SX 210.4-08(g)(1)(i))
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480678/235-10-S99-1

Reference 8: http://www.xbrl.org/2003/role/disclosureRef
-Topic 825
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 28
-Subparagraph (f)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482907/825-10-50-28

Reference 9: http://www.xbrl.org/2003/role/exampleRef
-Topic 944
-SubTopic 605
-Name Accounting Standards Codification
-Section 55
-Paragraph 14
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147477548/944-605-55-14

Reference 10: http://www.xbrl.org/2003/role/exampleRef
-Topic 944
-SubTopic 605
-Name Accounting Standards Codification
-Section 55
-Paragraph 11
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147477548/944-605-55-11

Reference 11: http://www.xbrl.org/2003/role/exampleRef
-Topic 280
-SubTopic 10
-Name Accounting Standards Codification
-Section 55
-Paragraph 48
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482785/280-10-55-48

Reference 12: http://www.xbrl.org/2003/role/disclosureRef
-Topic 270
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 1
-Subparagraph (i)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482964/270-10-50-1

Reference 13: http://www.xbrl.org/2003/role/disclosureRef
-Topic 280
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 32
-Subparagraph (ee)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482810/280-10-50-32

Reference 14: http://fasb.org/us-gaap/role/ref/otherTransitionRef
-Topic 280
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 32
-Subparagraph (b)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482810/280-10-50-32

Reference 15: http://fasb.org/us-gaap/role/ref/otherTransitionRef
-Topic 280
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 32
-Subparagraph (a)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482810/280-10-50-32

Reference 16: http://www.xbrl.org/2003/role/disclosureRef
-Topic 235
-SubTopic 10
-Name Accounting Standards Codification
-Section S99
-Paragraph 1
-Subparagraph (SX 210.4-08(g)(1)(ii))
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480678/235-10-S99-1

Reference 17: http://www.xbrl.org/2003/role/disclosureRef
-Topic 323
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 3
-Subparagraph (c)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147481687/323-10-50-3

Reference 18: http://www.xbrl.org/2003/role/disclosureRef
-Topic 470
-SubTopic 10
-Name Accounting Standards Codification
-Section S99
-Paragraph 1A
-Subparagraph (SX 210.13-01(a)(4)(i))
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480097/470-10-S99-1A

Reference 19: http://www.xbrl.org/2009/role/commonPracticeRef
-Topic 470
-SubTopic 10
-Name Accounting Standards Codification
-Section S99
-Paragraph 1A
-Subparagraph (SX 210.13-01(a)(4)(ii))
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480097/470-10-S99-1A

Reference 20: http://www.xbrl.org/2003/role/disclosureRef
-Topic 470
-SubTopic 10
-Name Accounting Standards Codification
-Section S99
-Paragraph 1A
-Subparagraph (SX 210.13-01(a)(4)(iii)(A))
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480097/470-10-S99-1A

Reference 21: http://www.xbrl.org/2003/role/disclosureRef
-Topic 470
-SubTopic 10
-Name Accounting Standards Codification
-Section S99
-Paragraph 1A
-Subparagraph (SX 210.13-01(a)(4)(iv))
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480097/470-10-S99-1A

Reference 22: http://www.xbrl.org/2003/role/disclosureRef
-Topic 470
-SubTopic 10
-Name Accounting Standards Codification
-Section S99
-Paragraph 1A
-Subparagraph (SX 210.13-01(a)(5))
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480097/470-10-S99-1A

Reference 23: http://www.xbrl.org/2003/role/disclosureRef
-Topic 470
-SubTopic 10
-Name Accounting Standards Codification
-Section S99
-Paragraph 1B
-Subparagraph (SX 210.13-02(a)(4)(i))
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480097/470-10-S99-1B

Reference 24: http://www.xbrl.org/2003/role/disclosureRef
-Topic 470
-SubTopic 10
-Name Accounting Standards Codification
-Section S99
-Paragraph 1B
-Subparagraph (SX 210.13-02(a)(4)(iii)(A))
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480097/470-10-S99-1B

Reference 25: http://www.xbrl.org/2003/role/disclosureRef
-Topic 470
-SubTopic 10
-Name Accounting Standards Codification
-Section S99
-Paragraph 1B
-Subparagraph (SX 210.13-02(a)(4)(iii)(B))
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480097/470-10-S99-1B

Reference 26: http://www.xbrl.org/2003/role/disclosureRef
-Topic 470
-SubTopic 10
-Name Accounting Standards Codification
-Section S99
-Paragraph 1B
-Subparagraph (SX 210.13-02(a)(4)(iv))
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480097/470-10-S99-1B

Reference 27: http://www.xbrl.org/2003/role/disclosureRef
-Topic 470
-SubTopic 10
-Name Accounting Standards Codification
-Section S99
-Paragraph 1B
-Subparagraph (SX 210.13-02(a)(5))
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480097/470-10-S99-1B

Reference 28: http://www.xbrl.org/2003/role/disclosureRef
-Topic 280
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 30
-Subparagraph (a)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482810/280-10-50-30

Reference 29: http://www.xbrl.org/2003/role/disclosureRef
-Topic 280
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 22
-Subparagraph (b)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482810/280-10-50-22

Reference 30: http://www.xbrl.org/2003/role/disclosureRef
-Topic 280
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 40
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482810/280-10-50-40

Reference 31: http://www.xbrl.org/2003/role/disclosureRef
-Topic 280
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 22
-Subparagraph (a)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482810/280-10-50-22

Reference 32: http://www.xbrl.org/2003/role/disclosureRef
-Topic 220
-SubTopic 10
-Name Accounting Standards Codification
-Section S99
-Paragraph 2
-Subparagraph (SX 210.5-03(1))
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147483621/220-10-S99-2

+ Details

OTHER COMPREHENSIVE INCOME(LOSS) AND ACCUMULATED OTHER COMPREHENSIVE INCOME(LOSS) - Reconciliation (Details) - CAD ($) $ in Millions			1 Months Ended	12 Months Ended
	May 29, 2024	Oct. 04, 2023	Oct. 31, 2023	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Balance at beginning of year				$ 38,360	$ 39,008
Other comprehensive income (loss) (Note 25)				(887)	1,828	$ (1,272)
Balance at end of year				36,899	38,360	39,008
Cash flow hedge gain reclassified within twelve months				9
Gain to be reclassified within twelve months				7
Columbia Gas and Columbia Gulf
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Equity interest percentage		40.00%	40.00%
Transportadora de Gas Natural de la Huasteca
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Equity interest percentage	13.01%	13.01%
Total
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Balance at beginning of year				233	49	955
Other comprehensive income (loss) before reclassifications				(406)	998	(437)
Amounts reclassified from AOCI				30	(52)	58
Other comprehensive income (loss) (Note 25)				(376)	946	(379)
Impact of non-controlling interest				348	(21)	(527)
Impact of spinoff of Liquids Pipelines business				542	(741)
Balance at end of year				747	233	49
Currency translation adjustments
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Balance at beginning of year				(402)	(317)	441
Other comprehensive income (loss) before reclassifications				(466)	692	(231)
Amounts reclassified from AOCI				0	(15)	0
Other comprehensive income (loss) (Note 25)				(466)	677	(231)
Impact of non-controlling interest				348	(21)	(527)
Impact of spinoff of Liquids Pipelines business				542	(741)
Balance at end of year				22	(402)	(317)
Cash flow hedges
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Balance at beginning of year				(16)	(35)	(109)
Other comprehensive income (loss) before reclassifications				(22)	35	0
Amounts reclassified from AOCI				31	(16)	74
Other comprehensive income (loss) (Note 25)				9	19	74
Impact of non-controlling interest				0	0	0
Impact of spinoff of Liquids Pipelines business				0	0
Balance at end of year				(7)	(16)	(35)
Pension and Other Post-Retirement Benefit Plan Adjustments
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Balance at beginning of year				22	(55)	(44)
Other comprehensive income (loss) before reclassifications				79	83	(11)
Amounts reclassified from AOCI				0	(6)	0
Other comprehensive income (loss) (Note 25)				79	77	(11)
Impact of non-controlling interest				0	0	0
Impact of spinoff of Liquids Pipelines business				0	0
Balance at end of year				101	22	(55)
Equity investments
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Balance at beginning of year				629	456	667
Other comprehensive income (loss) before reclassifications				3	188	(195)
Amounts reclassified from AOCI				(1)	(15)	(16)
Other comprehensive income (loss) (Note 25)				2	173	(211)
Impact of non-controlling interest				0	0	0
Impact of spinoff of Liquids Pipelines business				0	0
Balance at end of year				631	629	456
Accumulated foreign currency adjustment attributable to noncontrolling interest
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Other comprehensive income (loss) before reclassifications				$ (511)	$ 903	$ (366)

COMMON SHARES - Weighted Average Common Shares Outstanding (Details) - shares shares in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Common Stock, Number of Shares, Par Value and Other Disclosure [Abstract]
Basic (in shares)	1,040	1,038	1,030
Diluted (in shares)	1,040	1,038	1,030

INCOME TAXES - Deferred Assets and Liabilities (Details) - CAD ($) $ in Millions	Dec. 31, 2025	Dec. 31, 2024
Deferred Income Tax Assets
Tax loss and credit carryforwards	$ 1,728	$ 1,987
Disallowed interest carryforward	100	115
Regulatory and other deferred amounts	644	612
Unrealized foreign exchange losses on long-term debt	290	467
Other	57	143
Deferred tax assets, gross	2,819	3,324
Less: Valuation allowance	789	931
Deferred tax assets, net of Valuation allowance	2,030	2,393
Deferred Income Tax Liabilities
Difference in accounting and tax bases of plant, property and equipment	6,792	6,488
Equity investments	1,478	1,280
Taxes on future revenue requirement	654	612
Financial instruments	176	168
Other	251	301
Deferred tax liabilities, gross	9,351	8,849
Net Deferred Income Tax Liabilities	$ 7,321	$ 6,456

OTHER LONG-TERM LIABILITIES (Tables)

12 Months Ended

Dec. 31, 2025

Deferred Costs, Noncurrent [Abstract]

Schedule of Other Long-Term Liabilities


at December 31	2025	2024
(millions of Canadian $)

Operating lease liabilities (Note 9)	370	451
Fair value of derivative instruments (Note 27)	149	209
Asset retirement obligations	119	108
Loan from affiliate (Note 11)	111	—
Employee post-retirement benefits (Note 26)	69	94

Other	216	189
	1,034	1,051

EMPLOYEE POST-RETIREMENT BENEFITS

12 Months Ended

Dec. 31, 2025

Retirement Benefits [Abstract]

EMPLOYEE POST-RETIREMENT BENEFITS

The Company sponsors DB Plans for certain employees. Pension benefits provided under the DB Plans are generally based on years of service and highest average earnings over three to five consecutive years of employment. Effective January 1, 2019, there were certain amendments made to the Canadian DB Plan for new members. Subsequent to that date, benefits provided for new members were based on years of service and highest average earnings over five consecutive years of employment. Upon commencement of retirement, pension benefits in the Canadian DB Plan increase annually by a portion of the increase in the Consumer Price Index for employees hired prior to January 1, 2019. On January 1, 2024 the Canadian DB Plans were closed to new entrants. Employees hired on and after January 1, 2024 will participate in the Canadian DC Plan.

On January 1, 2025, there was an amendment to the Canadian OPEB Plan which closed the plan for any eligible active employees that did not retire by December 31, 2024. All active employees who no longer meet the eligibility for the OPEB Plan will be eligible for a new plan that provides an annual health spending account to retirees and their dependents from retirement to age 65.

The Company's U.S. DB Plan is closed to non-union new entrants and all non-union hires participate in the DC Plan. Net actuarial gains or losses are amortized out of AOCI over the EARSL of Plan participants, which was approximately eight years at December 31, 2025 (2024 – nine years; 2023 – nine years).

The Company also provides its employees with DC Plans and savings plans in Canada, DC Plans in Mexico, DC Plans consisting of a 401(k) Plan in the U.S. and post-employment benefits other than pensions, including termination benefits and life insurance and medical benefits beyond those provided by government-sponsored plans. Net actuarial gains or losses for the plans are amortized out of AOCI over the EARSL of employees, which was approximately 11 years at December 31, 2025 (2024 – 12 years and 2023 – 12 years). In 2025, the Company expensed $72 million (2024 – $71 million and 2023 – $64 million) for the savings and DC Plans.

Total cash contributions by the Company for employee post-retirement benefits were as follows:


year ended December 31	2025	2024	2023
(millions of Canadian $)

DB Plans	—	—	28
Other post-retirement benefit plans	8	8	9
Savings and DC Plans	72	71	64
	80	79	101

Current Canadian pension legislation allows for partial funding of solvency requirements over a number of years through letters of credit in lieu of cash contributions, up to certain limits. Total letters of credit provided to the Canadian DB plan at December 31, 2025 was nil (2024 – $111 million; 2023 – $244 million).

The most recent actuarial valuation of the pension plans for funding purposes was as at January 1, 2025 and the next required valuation is at January 1, 2026.

The Company's funded status was comprised of the following:


at December 31	Pension Benefit Plans		Other Post-Retirement Benefit Plans
(millions of Canadian $)	2025	2024	2025	2024

Change in Benefit Obligation1
Benefit obligation – beginning of year	3,342	3,356	288	285
Service cost	101	108	1	1
Interest cost	162	160	15	14
Employee contributions	11	11	2	2
Benefits paid	(228)	(194)	(22)	(24)
Actuarial (gain) loss2	(80)	(39)	(26)	(5)
South Bow - transition of benefit obligation3	—	(118)	—	(1)

Foreign exchange rate changes	(35)	58	(9)	16
Benefit obligation – end of year	3,273	3,342	249	288
Change in Plan Assets
Plan assets at fair value – beginning of year	3,948	3,697	339	358
Actual return on plan assets	390	485	22	17
Employer contributions4,5	—	—	8	(41)
Employee contributions	11	11	2	2
Benefits paid	(228)	(194)	(22)	(25)

South Bow - transition of plan assets3	—	(119)	—	—
Foreign exchange rate changes	(40)	68	(16)	28
Plan assets at fair value – end of year	4,081	3,948	333	339
Funded Status – Plan Surplus	808	606	84	51

3Reflects the impact of the Spinoff Transaction of the Liquids Pipelines business on October 1, 2024.

4The Company reduced letters of credit by $111 million in the Canadian DB Plan (2024 – $133 million) for funding purposes.

5OPEB surplus of nil (2024 - $49 million) was transferred to pay future active employee medical expenses.

Additional pension benefit plan assets were as follows:


at December 31	Pension Benefit Plans
(millions of Canadian $)	2025	2024

TC Energy plan assets at fair value	4,081	3,948
South Bow plan assets held in trust1	17	110
Plan assets at fair value – end of year	4,098	4,058

The amounts recognized on the Company's Consolidated balance sheet for its DB Plans and other post-retirement benefits plans were as follows:


at December 31	Pension Benefit Plans		Other Post-Retirement Benefit Plans
(millions of Canadian $)	2025	2024	2025	2024

Other long-term assets (Note 14)	808	606	159	152
Accounts payable and other	—	—	(6)	(7)
Other long-term liabilities (Note 17)	—	—	(69)	(94)
	808	606	84	51

Included in the above benefit obligation and fair value of plan assets were the following amounts for plans that were not fully funded:


at December 31	Pension Benefit Plans		Other Post-Retirement Benefit Plans
(millions of Canadian $)	2025	2024	2025	2024

Projected benefit obligation1	—	—	(76)	(101)
Plan assets at fair value	—	—	—	—
Funded Status – Plan Deficit	—	—	(76)	(101)

1The projected benefit obligation for the pension benefit plans differs from the accumulated benefit obligation in that it includes an assumption with respect to future compensation levels.

The funded status based on the accumulated benefit obligation for all DB Plans was as follows:


at December 31	2025	2024
(millions of Canadian $)

Accumulated benefit obligation	(3,086)	(3,097)
Plan assets at fair value1	4,098	4,058
Funded Status – Plan Surplus	1,012	961

1 Includes an estimated $17 million (2024 - $110 million) for future transfer to South Bow. The remaining South Bow pension assets will be adjusted to fair value on the date of the transfer.

The Company's DB Plans with respect to accumulated benefit obligations and the fair value of plan assets were fully funded as at December 31, 2025 and December 31, 2024.

The Company pension plans' weighted average asset allocations and target allocations by asset category were as follows:


at December 31	Percentage of Plan Assets				Target Allocations
	2025		2024		2025

Fixed income securities	45	%	37	%	30% to 55%
Equity securities	40	%	49	%	20% to 55%
Other investments	15	%	14	%	10% to 35%
	100	%	100	%

Fixed income and equity securities include the Company's and its related parties debt and common shares as follows:


at December 31			Percentage of Plan Assets
(millions of Canadian $)	2025	2024	2025		2024

Fixed income securities	26	44	0.6	%	1.1	%
Equity securities	2	3	0.1	%	0.1	%

Pension plan assets are managed on a going concern basis, subject to legislative restrictions, and are diversified across asset classes to maximize returns at an acceptable level of risk. Asset mix strategies consider plan demographics and may include traditional equity and debt securities as well as alternative assets such as infrastructure, private equity, real estate and derivatives to diversify risk. Derivatives are not used for speculative purposes and may be used to hedge certain liabilities.

All investments are measured at fair value using market prices. Where the fair value cannot be readily determined by
reference to generally available price quotations, the fair value is determined by considering the discounted cash flows on
a risk-adjusted basis and by comparison to similar assets which are publicly traded. In Level I, the fair value of assets is determined by reference to quoted prices in active markets for identical assets that the Company has the ability to access at
the measurement date. In Level II, the fair value of assets is determined using valuation techniques such as option pricing
models and extrapolation using significant inputs which are observable directly or indirectly. In Level III, the fair value of
assets is determined using a market approach based on inputs that are unobservable and significant to the overall fair
value measurement.


at December 31	Quoted Prices in Active Markets (Level I)		Significant Other Observable Inputs (Level II)		Significant Unobservable Inputs (Level III)		Total		Percentage of Total Portfolio
(millions of Canadian $, unless otherwise noted)
	2025	2024	2025	2024	2025	2024	2025	2024	2025		2024

Asset Category1
Cash and Cash Equivalents	130	138	—	—	—	—	130	138	3	%	3	%
Equity Securities:
Canadian	129	128	—	—	—	—	129	128	3	%	3	%
U.S.	969	1,234	—	—	—	—	969	1,234	22	%	28	%
International	107	182	220	209	—	—	327	391	7	%	9	%
Global	—	—	104	100	—	—	104	100	2	%	2	%
Emerging	33	66	132	150	—	—	165	216	4	%	5	%
Fixed Income Securities:
Canadian Bonds:
Federal	—	—	16	55	—	—	16	55	—		1	%
Provincial	—	—	514	312	—	—	514	312	12	%	7	%
Municipal	—	—	19	14	—	—	19	14	—		—
Corporate	—	—	483	323	—	—	483	323	11	%	7	%
U.S. Bonds:
Federal	147	151	260	255	—	—	407	406	9	%	9	%

Municipal	—	—	1	1	—	—	1	1	—		—
Corporate	185	246	193	158	—	—	378	404	9	%	9	%
International:
Government	3	4	19	17	—	—	22	21	1	%	1	%
Corporate	—	—	96	66	—	—	96	66	2	%	2	%
Mortgage backed	40	37	20	23	—	—	60	60	1	%	1	%
Net forward contracts	—	—	(184)	(201)	—	—	(184)	(201)	(4	%)	(4	%)

Other Investments:
Real estate	—	—	—	—	292	276	292	276	7	%	6	%
Infrastructure	—	—	—	—	315	282	315	282	7	%	7	%
Private equity funds	—	—	—	—	55	32	55	32	1	%	1	%
Funds held on deposit	130	138	—	—	—	—	130	138	3	%	3	%
Derivatives	—	—	3	1	—	—	3	1	—		—
	1,873	2,324	1,896	1,483	662	590	4,431	4,397	100	%	100	%

1 Includes $17 million (2024 - $110 million) for future transfer to South Bow.

The following table presents the net change in the Level III fair value category:


(millions of Canadian $, pre-tax)

Balance at December 31, 2023			562
Purchases and sales			(15)
Realized and unrealized gains (losses)			43
Balance at December 31, 2024			590
Purchases and sales			59
Realized and unrealized gains (losses)			13
Balance at December 31, 2025			662

In 2026, the Company expects to make funding contributions of $8 million for the other post-retirement benefit plans, approximately $76 million for the savings plans and DC Plans and no contributions for the DB Plans. The Company is not expecting to issue any additional letters of credit for the funding of solvency requirements to the Canadian DB plan in 2026.

The following are estimated future benefit payments, which reflect expected future service:


at December 31		Other Post-Retirement Benefits
(millions of Canadian $)	Pension Benefits

2026	223	22
2027	224	22
2028	226	22
2029	228	21
2030	230	21
2031 to 2035	1,158	98

The rate used to discount pension and other post-retirement benefit plan obligations was developed based on a yield curve of primarily corporate AA bond yields at December 31, 2025. This yield curve is used to develop spot rates that vary based on the duration of the obligations. The estimated future cash flows for the pension and other post-retirement benefit obligations were matched to the corresponding rates on the spot rate curve to derive a weighted average discount rate.

The significant weighted average actuarial assumptions adopted in measuring the Company's benefit obligations were as follows:


at December 31	Pension Benefit Plans				Other Post-Retirement Benefit Plans
	2025		2024		2025		2024

Discount rate	5.10	%	4.90	%	5.45	%	5.45	%
Rate of compensation increase	3.05	%	3.05	%	—		—

The significant weighted average actuarial assumptions adopted in measuring the Company's net benefit plan costs were as follows:


year ended December 31	Pension Benefit Plans						Other Post-Retirement Benefit Plans
	2025		2024		2023		2025		2024		2023

Discount rate	4.90	%	4.75	%	5.15	%	5.45	%	5.15	%	5.45	%
Expected long-term rate of return on plan assets	6.75	%	6.60	%	6.45	%	4.75	%	4.50	%	4.50	%
Rate of compensation increase	3.05	%	3.15	%	3.25	%	—		—		—

The overall expected long-term rate of return on plan assets is based on historical and projected rates of return for the portfolio in aggregate and for each asset class in the portfolio. Assumed projected rates of return are selected after analyzing historical experience and estimating future levels and volatility of returns. Asset class benchmark returns and asset mix are also considered in determining the overall expected rate of return. The discount rate is based on market interest rates of high-quality bonds that match the timing and benefits expected to be paid under each plan.

A 6.70 per cent weighted-average annual rate of increase in the per capita cost of covered health care benefits was assumed for 2026 measurement purposes. The rate was assumed to decrease gradually to 4.85 per cent by 2036 and remain at this level thereafter.

The net benefit cost recognized for the Company’s pension benefit plans and other post-retirement benefit plans was as follows:


year ended December 31	Pension Benefit Plans			Other Post-Retirement Benefit Plans
(millions of Canadian $)	2025	2024	2023	2025	2024	2023

Service cost1	101	108	93	1	1	3
Other components of net benefit cost1
Interest cost	162	160	158	15	14	16
Expected return on plan assets	(250)	(248)	(234)	(16)	(14)	(16)
Amortization of past service cost	—	—	—	(2)	—	—
Amortization of regulatory asset	—	—	—	—	(2)	—
	(88)	(88)	(76)	(3)	(2)	—
Net Benefit Cost Recognized	13	20	17	(2)	(1)	3

1 Service cost and other components of net benefit cost are included in Plant operating costs and other in the Consolidated statement of income.

Pre-tax amounts recognized in AOCI were as follows:


at December 31	2025		2024		2023
	Pension Benefits	Other Post- Retirement Benefits	Pension Benefits	Other Post- Retirement Benefits	Pension Benefits	Other Post- Retirement Benefits
(millions of Canadian $)




Net loss (gain)	(114)	(13)	(24)	—	71	6

Pre-tax amounts recognized in OCI were as follows:


year ended December 31	2025		2024		2023
	Pension Benefits	Other Post- Retirement Benefits	Pension Benefits	Other Post- Retirement Benefits	Pension Benefits	Other Post- Retirement Benefits
(millions of Canadian $)

Amortization of net gain (loss) from AOCI to net income	—	—	6	—	—	—



Funded status adjustment	(91)	(13)	(101)	(6)	33	(18)
	(91)	(13)	(95)	(6)	33	(18)

- Definition

The entire disclosure for retirement benefits.

+ References

Reference 1: http://www.xbrl.org/2003/role/disclosureRef
-Topic 715
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 1
-Subparagraph (o)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480506/715-20-50-1

Reference 2: http://www.xbrl.org/2003/role/disclosureRef
-Topic 715
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 1
-Subparagraph (p)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480506/715-20-50-1

Reference 3: http://www.xbrl.org/2003/role/disclosureRef
-Topic 715
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 1
-Subparagraph (q)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480506/715-20-50-1

Reference 4: http://www.xbrl.org/2003/role/disclosureRef
-Topic 715
-SubTopic 60
-Name Accounting Standards Codification
-Section 50
-Paragraph 3
-Subparagraph (c)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480266/715-60-50-3

Reference 5: http://www.xbrl.org/2003/role/disclosureRef
-Topic 715
-SubTopic 20
-Name Accounting Standards Codification
-Section S99
-Paragraph 2
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480126/715-20-S99-2

Reference 6: http://www.xbrl.org/2003/role/disclosureRef
-Topic 715
-SubTopic 70
-Name Accounting Standards Codification
-Section 50
-Paragraph 1
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480794/715-70-50-1

Reference 7: http://www.xbrl.org/2003/role/exampleRef
-Topic 715
-SubTopic 20
-Name Accounting Standards Codification
-Section 55
-Paragraph 17
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480482/715-20-55-17

Reference 8: http://www.xbrl.org/2003/role/disclosureRef
-Topic 715
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 1
-Subparagraph (d)(iv)(03)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480506/715-20-50-1

Reference 9: http://www.xbrl.org/2003/role/disclosureRef
-Topic 715
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 1
-Subparagraph (d)(i)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480506/715-20-50-1

Reference 10: http://www.xbrl.org/2003/role/disclosureRef
-Topic 715
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 1
-Subparagraph (l)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480506/715-20-50-1

Reference 11: http://www.xbrl.org/2003/role/disclosureRef
-Topic 715
-Name Accounting Standards Codification
-Publisher FASB
-URI https://asc.fasb.org/715/tableOfContent

Reference 12: http://www.xbrl.org/2003/role/disclosureRef
-Topic 715
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 1
-Subparagraph (d)(iii)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480506/715-20-50-1

Reference 13: http://www.xbrl.org/2003/role/disclosureRef
-Topic 715
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 1
-Subparagraph (r)(1)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480506/715-20-50-1

Reference 14: http://www.xbrl.org/2003/role/disclosureRef
-Topic 715
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 1
-Subparagraph (r)(2)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480506/715-20-50-1

+ Details

PLANT, PROPERTY AND EQUIPMENT (Tables)

12 Months Ended

Dec. 31, 2025

Property, Plant and Equipment [Abstract]

Schedule of Plant, Property and Equipment


at December 31	2025			2024
	Cost	Accumulated Depreciation	Net Book Value	Cost	Accumulated Depreciation	Net Book Value
(millions of Canadian $)

Canadian Natural Gas Pipelines
NGTL System
Pipeline	20,806	8,037	12,769	20,497	7,413	13,084
Compression	7,277	2,732	4,545	7,146	2,497	4,649
Metering and other	1,685	903	782	1,668	883	785
	29,768	11,672	18,096	29,311	10,793	18,518
Under construction	663	—	663	503	—	503
	30,431	11,672	18,759	29,814	10,793	19,021
Canadian Mainline
Pipeline	11,126	8,355	2,771	10,907	8,165	2,742
Compression	4,661	3,500	1,161	4,540	3,448	1,092
Metering and other	797	344	453	749	331	418
	16,584	12,199	4,385	16,196	11,944	4,252
Under construction	121	—	121	163	—	163
	16,705	12,199	4,506	16,359	11,944	4,415
Other Canadian Natural Gas Pipelines1
Other	2,947	1,777	1,170	2,927	1,742	1,185
Under construction	19	—	19	31	—	31
	2,966	1,777	1,189	2,958	1,742	1,216
	50,102	25,648	24,454	49,131	24,479	24,652
U.S. Natural Gas Pipelines
Columbia Gas
Pipeline	14,996	1,610	13,386	14,826	1,472	13,354
Compression	6,169	741	5,428	6,153	677	5,476
Metering and other	4,529	502	4,027	4,570	455	4,115
	25,694	2,853	22,841	25,549	2,604	22,945
Under construction	675	—	675	891	—	891
	26,369	2,853	23,516	26,440	2,604	23,836
ANR
Pipeline	3,092	744	2,348	2,477	745	1,732
Compression	4,933	948	3,985	4,446	938	3,508
Metering and other	1,867	509	1,358	1,832	521	1,311
	9,892	2,201	7,691	8,755	2,204	6,551
Under construction	362	—	362	853	—	853
	10,254	2,201	8,053	9,608	2,204	7,404


at December 31	2025			2024
	Cost	Accumulated Depreciation	Net Book Value	Cost	Accumulated Depreciation	Net Book Value
(millions of Canadian $)	Cost	Accumulated Depreciation	Net Book Value	Cost	Accumulated Depreciation	Net Book Value

Other U.S. Natural Gas Pipelines
Columbia Gulf	4,427	274	4,153	4,127	304	3,823
GTN	3,325	1,476	1,849	3,405	1,467	1,938
Great Lakes	2,577	1,509	1,068	2,602	1,537	1,065

Other2	1,646	655	991	1,695	628	1,067
	11,975	3,914	8,061	11,829	3,936	7,893
Under construction	643	—	643	694	—	694
	12,618	3,914	8,704	12,523	3,936	8,587
	49,241	8,968	40,273	48,571	8,744	39,827
Mexico Natural Gas Pipelines3
Pipeline	2,468	545	1,923	2,590	523	2,067
Compression	449	113	336	476	107	369
Metering and other	394	107	287	398	99	299
	3,311	765	2,546	3,464	729	2,735
Under construction	1,454	—	1,454	7,807	—	7,807
	4,765	765	4,000	11,271	729	10,542


















Power and Energy Solutions

Natural Gas Power Generation	1,322	719	603	1,273	671	602

Natural Gas Storage and Other	887	308	579	873	281	592
Renewable Power Generation	737	83	654	779	54	725
	2,946	1,110	1,836	2,925	1,006	1,919
Under construction	56	—	56	56	—	56
	3,002	1,110	1,892	2,981	1,006	1,975
Corporate	895	460	435	944	439	505
	108,005	36,951	71,054	112,898	35,397	77,501

1Includes Foothills, Ventures LP and Great Lakes Canada.

2Includes North Baja, Tuscarora, Louisiana Intrastate, Crossroads, U.S. Energy Marketing and mineral rights business.