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U.S. Securities and Exchange Commission

Washington, D.C. 20549

Form 40-F

☐			REGISTRATION STATEMENT PURSUANT TO SECTION 12 OF THE SECURITIES EXCHANGE ACT OF 1934
OR
☒			ANNUAL REPORT PURSUANT TO SECTION 13(a) OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2025

TC ENERGY CORPORATION

(Commission File Number 1-31690)

TRANSCANADA PIPELINES LIMITED

(Commission File Number 1-8887)

(Exact name of Registrant as specified in its charter)

Canada

(Province or other jurisdiction of incorporation or organization)

4922, 4923, 4924, 5172

(Primary Standard Industrial Classification Code Number (if applicable))

Not Applicable

(TC Energy Corporation)

(I.R.S. Employer Identification Number (if applicable))

52-2179728

(TransCanada PipeLines Limited)

(I.R.S. Employer Identification Number (if applicable))

TC Energy Tower, 450 - 1 Street S.W.

Calgary, Alberta, Canada, T2P 5H1

(403) 920-2000

(Address and telephone number of Registrant's principal executive offices)

TransCanada PipeLine USA Ltd., 700 Louisiana Street, Suite 700

Houston, Texas, 77002-2700; (832) 320-5201

(Name, address (including zip code) and telephone number (including area code)

of agent for service in the United States)

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

Title of each class			Trading Symbol(s)			Name of each exchange on which registered
Common Shares (including Rights under Shareholder Rights Plan) of TC Energy Corporation			TRP			New York Stock Exchange

Securities registered or to be registered pursuant to Section 12(g) of the Act: None

Securities for which there is a reporting obligation pursuant to Section 15(d) of the Act:

Debt Securities of TransCanada PipeLines Limited

For annual reports, indicate by check mark the information filed with this Form:

☒			Annual information form			☒			Audited annual financial statements

Indicate the number of outstanding shares of each of the issuer's classes of capital or common stock as of the close of the period covered by the Annual Report.

At December 31, 2025, 1,040,835,168 common shares;

18,424,004 Cumulative Redeemable First Preferred Shares, Series 1;

3,575,996 Cumulative Redeemable First Preferred Shares, Series 2;

11,715,228 Cumulative Redeemable First Preferred Shares, Series 3;

2,284,772 Cumulative Redeemable First Preferred Shares, Series 4;

12,070,593 Cumulative Redeemable First Preferred Shares, Series 5;

1,929,407 Cumulative Redeemable First Preferred Shares Series 6;

24,000,000 Cumulative Redeemable First Preferred Shares Series 7;

16,702,797 Cumulative Redeemable First Preferred Shares Series 9; and

1,297,203 Cumulative Redeemable First Preferred Shares Series 10

of TC Energy Corporation were issued and outstanding.

At December 31, 2025, 992,720,977 common shares of TransCanada PipeLines Limited,

which were all owned by TC Energy Corporation, were issued and outstanding.

Indicate by check mark whether the Registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Exchange Act during the preceding 12 months (or such shorter period that the Registrant was required to file such reports) and (2) has been subject to such filing requirements for the past 90 days. Yes ☒    No ☐

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the Registrant was required to submit such files). Yes ☒    No ☐

Indicate by check mark whether the Registrant is an emerging growth company as defined in Rule 12b-2 of the Exchange Act.

Emerging growth company ☐

If an emerging growth company that prepares its financial statements in accordance with U.S. GAAP, indicate by check mark if the Registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards† provided pursuant to Section 13(a) of the Exchange Act.

†The term "new or revised financial accounting standard" refers to any update issued by the Financial Accounting Standards Board to its Accounting Standards Codification after April 5, 2012.

Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☒

If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect the correction of an error to previously issued financial statements. ☐

Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any of the registrant’s executive officers during the relevant recovery period pursuant to §240.10D-1(b). ☐

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The documents (or portions thereof) forming part of this Form 40-F are incorporated by reference into the following registration statements under the Securities Act of 1933, as amended:

Form			Registration No.
TC Energy Corporation
S-8			333-5916
S-8			333-8470
S-8			333-9130
S-8			333-151736
S-8			333-184074
S-8			333-227114
S-8			333-237979
F-3			33-13564
F-3			333-6132
F-10			333-252123
TransCanada PipeLines Limited
F-10			333-267323
F-10			333-283633

EXPLANATORY NOTE

TransCanada PipeLines Limited (“TransCanada PipeLines”) is a wholly owned subsidiary of TC Energy Corporation (“TC Energy”). As of the date of filing of this Form 40-F, TransCanada PipeLines is relying on the continuous disclosure documents filed by TC Energy pursuant to an exemption from the requirements of National Instrument 51-102 - Continuous Disclosure Obligations and as provided in the decision of the Alberta Securities Commission and the Ontario Securities Commission in Re TransCanada Corporation, 2019 ABASC 1, issued on January 3, 2019. Consistent with the exemptive relief, information contained in this Form 40-F is that provided by TC Energy except as indicated below.

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AUDITED CONSOLIDATED FINANCIAL STATEMENTS AND

MANAGEMENT'S DISCUSSION & ANALYSIS

Except sections specifically referenced below which shall be deemed incorporated by reference herein and filed, no other portion of the TC Energy 2025 Management's discussion and analysis and audited consolidated financial statements to shareholders, except as otherwise specifically incorporated by reference in the TC Energy Annual information form, shall be deemed filed with the U.S. Securities and Exchange Commission (the "Commission") as part of this report under the Exchange Act.

A.    Audited Consolidated Financial Statements

For audited consolidated financial statements, including the auditors' report, see pages 129 through 215 of the TC Energy 2025 Management's discussion and analysis and audited consolidated financial statements included herein.

B.    Management's Discussion and Analysis

For management's discussion and analysis, see pages 9 through 128 of the TC Energy 2025 Management's discussion and analysis and audited consolidated financial statements included herein under the heading "Management's Discussion and Analysis".

C.    Management's Report on Internal Control over Financial Reporting

For management's report on internal control over financial reporting, see "Management's Report on Internal Control over Financial Reporting" that accompanies the audited consolidated financial statements on page 129 of the TC Energy 2025 Management's discussion and analysis and audited consolidated financial statements included herein.

UNDERTAKING

Each Registrant undertakes to make available, in person or by telephone, representatives to respond to inquiries made by the Commission staff, and to furnish promptly, when requested to do so by the Commission staff, information relating to: the securities registered pursuant to Form 40-F; the securities in relation to which the obligation to file an annual report on Form 40-F arises; or transactions in said securities.

DISCLOSURE CONTROLS AND PROCEDURES AND INTERNAL CONTROL OVER FINANCIAL REPORTING

For information on disclosure controls and procedures and management's annual report on internal control over financial reporting, see "Other information - Controls and Procedures" on page 109 of the TC Energy 2025 Management's discussion and analysis and audited consolidated financial statements.

AUDIT COMMITTEE FINANCIAL EXPERT

Each Registrant's Board of Directors has determined that it has at least one audit committee financial expert serving on its Audit committee. Ms. Una Power has been designated as an audit committee financial expert and is independent, as that term is defined by the New York Stock Exchange's listing standards applicable to each Registrant. The Commission has indicated that the designation of Ms. Power as an audit committee financial expert does not make Ms. Power an "expert" for any purpose, impose any duties, obligations or liability on Ms. Power that is greater than those imposed on members of the Audit committee and Board of Directors who do not carry this designation or affect the duties, obligations or liability of any other member of the Audit committee.

CODE OF ETHICS

The Registrants have adopted a code of business ethics ("Code") for their directors, officers, employees and contractors. In 2025, the Code was reviewed and amended to incorporate certain non-material and administrative changes. These changes did not alter the substantive principles or requirements of the Code.

The Registrants' Code is available on TC Energy's website at www.tcenergy.com and any person can obtain the Code without charge upon request from the Corporate Secretary of TC Energy. No waivers have been granted from any provision of the Code during the 2025 fiscal year.

PRINCIPAL ACCOUNTANT FEES AND SERVICES

Our independent registered public accounting firm is KPMG LLP, Calgary, AB, Canada, Auditor Firm ID: 85. For information on principal accountant fees and services, see "Audit committee - Pre-approval Policies and Procedures" and "Audit committee - External Auditor Service Fees" on page 32 of the TC Energy 2025 Annual information form.

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OFF-BALANCE SHEET ARRANGEMENTS

The Registrants have no off-balance sheet arrangements, as defined in this Form, other than the guarantees and commitments described in Note 30 of the Notes to the audited consolidated financial statements attached to this Form 40-F and incorporated herein by reference.

DISCLOSURE OF CONTRACTUAL OBLIGATIONS

For information on disclosure of contractual obligations, see "Financial Condition - Contractual obligations" in Management's discussion and analysis on page 85 of the TC Energy 2025 Management's discussion and analysis and audited consolidated financial statements.

IDENTIFICATION OF THE AUDIT COMMITTEE

Each Registrant has a separately-designated standing Audit committee. The members of the Audit committee as of February 12, 2026 (unless otherwise indicated) are:

Chair: Members:			U. Power S. Bonham C.F. Campbell M.R. Culbert S.C. Jones D. Madahbee Leach

DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS

Not Applicable.

FORWARD-LOOKING INFORMATION

We disclose forward-looking information to help the reader understand management's assessment of our future plans and financial outlook and our future prospects overall.

Statements that are forward looking are based on certain assumptions and on what we know and expect today and generally include words like anticipate, expect, believe, may, will, should, estimate or other similar words.

Forward-looking statements included or incorporated by reference in this document include information about the following, among other things:

•our financial and operational performance, including the performance of our subsidiaries

•expectations about strategies and goals for growth and expansion, including acquisitions

•expected cash flows and future financing options available along with portfolio management

•expectations regarding the size, structure, timing, conditions and outcome of ongoing and future transactions

•expected dividend growth

•expected access to and cost of capital

•expected energy demand levels

•expected costs and schedules for planned projects, including projects under construction and in development

•expected capital expenditures, contractual obligations, commitments and contingent liabilities, including environmental remediation costs

•expected regulatory processes and outcomes

•expected outcomes with respect to legal proceedings, including arbitration and insurance claims

•expected impact of future tax and accounting changes

•commitments and targets contained in our Report on Sustainability, including statements related to our GHG emissions reduction targets, such as our methane emissions intensity target

•expected industry, market and economic conditions, and ongoing trade negotiations, including their impact on our customers and suppliers.

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Forward-looking statements do not guarantee future performance. Actual events and results could be significantly different because of assumptions, risks or uncertainties related to our business or events that happen after the date of this document.

Our forward-looking information is based on the following key assumptions and subject to the following risks and uncertainties:

Assumptions

•realization of expected impacts from acquisitions and divestitures

•regulatory decisions and outcomes

•planned and unplanned outages and the utilization of our pipelines, power and storage assets

•integrity and reliability of our assets

•anticipated construction costs, schedules and completion dates

•access to capital markets, including portfolio management

•expected industry, market and economic conditions, including the impact of these on our customers and suppliers

•inflation rates, commodity and labour prices

•interest, tax and foreign exchange rates

•nature and scope of hedging.

Risks and uncertainties

•realization of expected impacts from acquisitions and divestitures

•our ability to successfully implement our strategic priorities, and whether they will yield the expected benefits

•our ability to implement a capital allocation strategy aligned with maximizing shareholder value

•operating performance of our pipelines, power generation and storage assets

•amount of capacity sold and rates achieved in our pipeline businesses

•amount of capacity payments and revenues from power generation assets due to plant availability

•production levels within supply basins

•construction and completion of capital projects

•cost, availability of, and inflationary pressures on, labour, equipment and materials

•availability and market prices of commodities

•access to capital markets on competitive terms

•interest, tax and foreign exchange rates

•performance and credit risk of our counterparties

•regulatory decisions and outcomes of legal proceedings, including arbitration and insurance claims

•our ability to effectively anticipate and assess changes to government policies and regulations, including those related to the environment

•our ability to realize the value of tangible assets and contractual recoveries

•competition in the businesses in which we operate

•unexpected or unusual weather

•acts of civil disobedience

•cybersecurity and technological developments

•sustainability-related risks including climate-related risks and the impact of energy transition on our business

•economic and political conditions, and ongoing trade negotiations in North America, as well as globally

•global health crises, such as pandemics and epidemics, and the impacts related thereto.

You can read more about these factors and others in reports we have filed with Canadian securities regulators and the Commission.

As actual results could vary significantly from the forward-looking information, you should not put undue reliance on forward-looking information and should not use future-oriented information or financial outlooks for anything other than their intended purpose. We do not update our forward-looking statements due to new information or future events unless we are required to by law.

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DOCUMENTS FILED AS PART OF THIS REPORT

EXHIBITS
13.1			TC Energy Corporation Annual Information Form for the year ended December 31, 2025.
13.2			Management's discussion and analysis (included on pages 9 through 128 of the TC Energy Corporation 2025 Management's discussion and analysis and audited consolidated financial statements to shareholders).
13.3			2025 Audited consolidated financial statements (included on pages 129 through 215 of the TC Energy Corporation 2025 Management's discussion and analysis and audited consolidated financial statements to shareholders), including the Report of Independent Registered Public Accounting Firm on the Consolidated Financial Statements and the Report of Independent Registered Public Accounting Firm on the effectiveness of TC Energy's internal control over financial reporting as of December 31, 2025.
23.1			Consent of KPMG LLP, Chartered Professional Accountants, Independent Registered Public Accounting Firm.
31.1			Certification of Chief Executive Officer regarding Periodic Report containing Financial Statements.
31.2			Certification of Chief Financial Officer regarding Periodic Report containing Financial Statements.
32.1			Certification of Chief Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2			Certification of Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
97.1			TC Energy Corporation's Policy Relating to Recovery of Erroneously Awarded Incentive-Based Compensation.
99.1			TC Energy Corporation's Code of Business Ethics Policy, as amended and filed with the Securities and Exchange Commission as part of a Form 6-K report on October 29, 2025, and incorporated by reference herein.
101.SCH			Inline XBRL Taxonomy Extension Schema Document.
101.CAL			Inline XBRL Taxonomy Extension Calculation Linkbase Document.
101.DEF			Inline XBRL Taxonomy Definition Linkbase Document.
101.LAB			Inline XBRL Taxonomy Extension Label Linkbase Document.
101.PRE			Inline XBRL Taxonomy Extension Presentation Linkbase Document.
104			Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101).

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SIGNATURES

Pursuant to the requirements of the Exchange Act, each Registrant certifies that it meets all of the requirements for filing on Form 40-F and has duly caused this annual report to be signed on its behalf by the undersigned, thereto duly authorized, in the City of Calgary, Province of Alberta, Canada.

			TC ENERGY CORPORATION
			TRANSCANADA PIPELINES LIMITED
			(Registrants)
			By:			/s/ SEAN P. O'DONNELL
						SEAN P. O'DONNELL Executive Vice-President, Strategy and Corporate Development and Chief Financial Officer
						Date: February 13, 2026

EXHIBIT 13.1

TC Energy Corporation

2025 Annual Information Form

February 12, 2026

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Contents

PRESENTATION OF INFORMATION			2
FORWARD-LOOKING INFORMATION			3
TC ENERGY CORPORATION			5
Corporate structure			5
Intercorporate relationships			5
BUSINESS OF TC ENERGY			6
GENERAL DEVELOPMENT OF THE BUSINESS			6
Natural Gas Pipelines			7
Power and Energy Solutions			13
Discontinued Operations			14
GENERAL			15
Employees			15
Health, safety, sustainability and environmental protection governance and social policies			15
RISK FACTORS			16
DIVIDENDS			16
DESCRIPTION OF CAPITAL STRUCTURE			17
Share capital			17
CREDIT RATINGS			20
Moody's			20
S&P			21
Fitch			21
DBRS			22
MARKET FOR SECURITIES			22
Common shares			23
Preferred shares			24
DIRECTORS AND OFFICERS			25
Directors			25
Board committees			27
Officers			28
Conflicts of interest			29
CORPORATE GOVERNANCE			30
AUDIT COMMITTEE			31
Relevant education and experience of members			31
Pre-approval policies and procedures			32
External auditor service fees			32
LEGAL PROCEEDINGS AND REGULATORY ACTIONS			33
TRANSFER AGENT AND REGISTRAR			34
MATERIAL CONTRACTS			34
INTEREST OF EXPERTS			34
ADDITIONAL INFORMATION			34
GLOSSARY			35
SCHEDULE A			36
SCHEDULE B			37

TC Energy Annual Information Form 2025 | 1

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Presentation of information

Throughout this Annual Information Form (AIF), the terms, we, us, our, the Company and TC Energy mean TC Energy Corporation and its subsidiaries. In particular, TC Energy includes references to TransCanada PipeLines Limited (TCPL). The term subsidiary, when referred to in this AIF, with reference to TC Energy means direct and indirect wholly-owned subsidiaries of, and legal entities controlled by, TC Energy or TCPL, as applicable.

Unless otherwise noted, the information contained in this AIF is given at or for the year ended December 31, 2025 (Year End). Amounts are expressed in Canadian dollars, unless otherwise indicated. Information in relation to metric conversion can
be found at Schedule A to this AIF. The Glossary found at the end of this AIF contains certain terms defined throughout this
AIF and abbreviations and acronyms that may not otherwise be defined in this document.

Certain portions of TC Energy's Management's Discussion and Analysis dated February 12, 2026 (MD&A) are incorporated by reference into this AIF as stated below and noted elsewhere in this AIF. The MD&A can be found on SEDAR+ (www.sedarplus.ca) under TC Energy's profile.

Financial information is presented in accordance with United States (U.S.) generally accepted accounting principles (GAAP).

2 | TC Energy Annual Information Form 2025

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Forward-looking information

This AIF, including the MD&A disclosure incorporated by reference herein, contains certain information that is forward-looking and is subject to important risks and uncertainties. We disclose forward-looking information to help the reader understand management’s assessment of our future plans and financial outlook and our future prospects overall.

Statements that are forward looking are based on certain assumptions and on what we know and expect today and generally include words like anticipate, expect, believe, may, will, should, estimate or other similar words.

Forward-looking statements included or incorporated by reference in this AIF include information about the following,
among other things:

•our financial and operational performance, including the performance of our subsidiaries

•expectations about strategies and goals for growth and expansion, including acquisitions

•expected cash flows and future financing options available along with portfolio management

•expectations regarding the size, structure, timing, conditions and outcome of ongoing and future transactions

•expected dividend growth

•expected access to and cost of capital

•expected energy demand levels

•expected costs and schedules for planned projects, including projects under construction and in development

•expected capital expenditures, contractual obligations, commitments and contingent liabilities, including
environmental remediation costs

•expected regulatory processes and outcomes

•expected outcomes with respect to legal proceedings, including arbitration and insurance claims

•expected impact of future tax and accounting changes

•commitments and targets contained in our Report on Sustainability, including statements related to our GHG emissions reduction targets, such as our methane emissions intensity target

•expected industry, market and economic conditions, and ongoing trade negotiations, including their impact
on our customers and suppliers.

Forward-looking statements do not guarantee future performance. Actual events and results could be significantly different because of assumptions, risks or uncertainties related to our business or events that happen after the date of this AIF.

Our forward-looking information is based on the following key assumptions and subject to the following risks and uncertainties:

Assumptions

•realization of expected impacts from acquisitions and divestitures

•regulatory decisions and outcomes

•planned and unplanned outages and the utilization of our pipelines, power and storage assets

•integrity and reliability of our assets

•anticipated construction costs, schedules and completion dates

•access to capital markets, including portfolio management

•expected industry, market and economic conditions, including the impact of these on our
customers and suppliers

•inflation rates, commodity and labour prices

•interest, tax and foreign exchange rates

•nature and scope of hedging.

TC Energy Annual Information Form 2025 | 3

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Risks and uncertainties

•realization of expected impacts from acquisitions and divestitures

•our ability to successfully implement our strategic priorities, and whether they will yield the expected benefits

•our ability to implement a capital allocation strategy aligned with maximizing shareholder value

•operating performance of our pipelines, power generation and storage assets

•amount of capacity sold and rates achieved in our pipeline businesses

•amount of capacity payments and revenues from power generation assets due to plant availability

•production levels within supply basins

•construction and completion of capital projects

•cost, availability of, and inflationary pressures on, labour, equipment and materials

•availability and market prices of commodities

•access to capital markets on competitive terms

•interest, tax and foreign exchange rates

•performance and credit risk of our counterparties

•regulatory decisions and outcomes of legal proceedings, including arbitration and insurance claims

•our ability to effectively anticipate and assess changes to government policies and regulations,
including those related to the environment

•our ability to realize the value of tangible assets and contractual recoveries

•competition in the businesses in which we operate

•unexpected or unusual weather

•acts of civil disobedience

•cybersecurity and technological developments

•sustainability-related risks including climate-related risks and the impact of energy transition on our business

•economic and political conditions, and ongoing trade negotiations in North America, as well as globally

•global health crises, such as pandemics and epidemics, and the impacts related thereto.

You can read more about these factors and others in the MD&A and in other reports we have filed with Canadian securities regulators and the SEC.

As actual results could vary significantly from the forward-looking information, you should not put undue reliance
on forward-looking information and should not use future-oriented information or financial outlooks for anything other
than their intended purpose. We do not update our forward-looking statements due to new information or future events
unless we are required to by law.

4 | TC Energy Annual Information Form 2025

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TC Energy Corporation

CORPORATE STRUCTURE

Our head office and registered office are located at 450 – 1 Street S.W., Calgary, Alberta, T2P 5H1. TC Energy was incorporated pursuant to the provisions of the Canada Business Corporations Act (CBCA) on February 25, 2003 in connection with a plan of arrangement with TCPL (Arrangement), which established TC Energy as the parent company of TCPL. The Arrangement was approved by TCPL common shareholders on April 25, 2003 and, following court approval and the filing of Articles of Arrangement, the Arrangement became effective on May 15, 2003. TCPL continues to carry on business as the principal operating subsidiary of TC Energy. TC Energy does not hold any material assets directly other than the common shares of TCPL and receivables from certain of TC Energy's subsidiaries.

On October 1, 2024, TC Energy separated into two independent, publicly listed companies through the spinoff of its Liquids Pipelines business into South Bow Corporation (South Bow) by way of a plan of arrangement under the CBCA (the Spinoff Transaction). In connection with the Spinoff Transaction, TC Energy restated its Articles of Incorporation on October 1, 2024 to effectively consolidate previous amendments made to its articles which provided for the issuance of various series of preferred shares.

INTERCORPORATE RELATIONSHIPS

The following diagram presents the name and jurisdiction of incorporation, continuance or formation of TC Energy’s principal subsidiaries as at Year End. Each of the subsidiaries shown has total assets that exceeded 10 per cent of the consolidated assets
of TC Energy as at Year End or revenues that exceeded 10 per cent of the consolidated revenues of TC Energy as at Year End. Except as otherwise indicated below, TC Energy beneficially owns, controls or directs, directly or indirectly, 100 per cent of the voting shares or units in each of these subsidiaries.

TC Energy Corporation Canada TransCanada PipeLines Limited Canada TransCanada PipeLine USA Ltd. Nevada TransCanada American Investments Ltd. Delaware Columbia Pipeline Group, Inc. Delaware Columbia Pipelines Holding Company, LLC2 Delaware Columbia Pipelines Operating Company, LLC2 Delaware Columbia Gas Transmission, LLC2 Delaware 15142083 Canada Ltd. Canada 6297782 LLC Delaware TransCanada Oil Pipelines Inc. Delaware 701671 Alberta Ltd.1 Alberta TransCanada Mexican Investments Ltd.1 Alberta

The above diagram does not include all of the subsidiaries of TC Energy. The total assets and revenues of excluded subsidiaries
in the aggregate did not exceed 20 per cent of the consolidated assets of TC Energy as at Year End or consolidated revenues
of TC Energy as at Year End.

1 701671 Alberta Ltd. assets and revenues do not exceed 10 per cent of the total consolidated assets or revenues of TC Energy but have been included to meet the total consolidated revenues and assets criteria of excluded subsidiaries threshold of less than 20 per cent.
2 TC Energy beneficially owns, controls or directs, directly or indirectly, 60 per cent of the voting shares or units in each of these subsidiaries.

TC Energy Annual Information Form 2025 | 5

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Business of TC Energy

We operate in two core businesses – Natural Gas Pipelines and Power and Energy Solutions. In order to provide information that is aligned with how management decisions about our businesses are made and how performance of our businesses is assessed, our results are reflected in four operating segments: Canadian Natural Gas Pipelines, U.S. Natural Gas Pipelines, Mexico Natural Gas Pipelines and Power and Energy Solutions. We also have a Corporate segment consisting of corporate and administrative functions that provide governance, financing and other support to TC Energy's business segments.

For information regarding our Natural Gas Pipelines business, including pipeline holdings, developments, opportunities, regulation and competitive position refer to the Natural Gas Pipelines Business, Canadian Natural Gas Pipelines, U.S. Natural Gas Pipelines and Mexico Natural Gas Pipelines sections of the MD&A, which sections are incorporated by reference herein.

For information regarding our Power and Energy Solutions business, including holdings, developments, opportunities, regulation and competitive position refer to the Power and Energy Solutions section of the MD&A, which section is incorporated by reference herein.

Refer to the About our business – 2025 Financial highlights - Consolidated results section of the MD&A for our revenues from operations by segment, for the years ended December 31, 2025, 2024 and 2023, which section is incorporated by reference herein.

General development of the business

Summarized below are significant developments that have occurred in our Natural Gas Pipelines, Liquids Pipelines and
Power and Energy Solutions businesses, respectively, and certain acquisitions, dispositions, events or conditions which have
had an influence on those developments, during the last three financial years and year to date in 2026. Further information about developments in our business, including changes that we expect will occur in 2026, can be found in the Natural Gas Pipelines Business, Canadian Natural Gas Pipelines, U.S. Natural Gas Pipelines, Mexico Natural Gas Pipelines, Power and Energy Solutions, About our business - Capital program - Secured projects, and Discontinued operations sections of the MD&A, which sections are incorporated by reference herein.

6 | TC Energy Annual Information Form 2025

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NATURAL GAS PIPELINES

Developments in the Canadian Natural Gas Pipelines Segment

CANADIAN REGULATED PIPELINES
2021 NGTL System Expansion Program
The 2021 NGTL System Expansion Program was completed in 2024 and consists of 344 km (214 miles) of new pipeline, three new compressor units and associated facilities and added approximately 1.59 PJ/d (1.45 Bcf/d) of incremental capacity to the NGTL System. The capital cost of the program was $3.6 billion.
2022 NGTL System Expansion Program
The 2022 NGTL System Expansion Program was completed in 2023 and consists of approximately 166 km (103 miles) of new pipeline, one compressor unit and associated facilities and provides incremental capacity of approximately 773 TJ/d (722 MMcf/d) to meet firm-receipt and intra-basin delivery requirements with eight-year minimum terms. The capital cost of the program was $1.4 billion.
2023 NGTL System Intra-Basin Expansion
The NGTL System Intra-Basin Expansion was completed in 2024 and consists of 23 km (14 miles) of new pipeline and two new compressor stations and is underpinned by approximately 255 TJ/d (238 MMcf/d) of new firm-service contracts with 15-year terms. The capital cost of the expansion was $0.5 billion.
NGTL System/Foothills West Path Delivery Program
The NGTL System/Foothills West Path Delivery Program was completed in 2023 and consisted of a multi-year expansion of the NGTL System and Foothills system to facilitate incremental contracted export capacity connecting to the GTN pipeline system. The combined NGTL System and Foothills program consists of approximately 107 km (66 miles) of pipeline and associated facilities and is underpinned by 275 TJ/d (258 MMcf/d) of new firm-service contracts with terms that exceed 30 years. The capital cost of the program was $1.6 billion.
Valhalla North and Berland River Project
In November 2022, we sanctioned the Valhalla North and Berland River (VNBR) Project to serve aggregate system requirements and connect migrating supply to key demand markets, designed to provide incremental capacity on the NGTL System of approximately 428 TJ/d (400 MMcf/d). On December 21, 2023, we received approval from the CER to construct, own and operate the VNBR Project. The Valhalla section, which consists of approximately 33 km (21 miles) of new pipeline, was placed in-service in third quarter 2025, with a capital cost of approximately $0.2 billion. The Berland River section, which includes a new non-emitting electric compressor unit and associated facilities, has a target in-service date in the second half of 2026 and an estimated capital cost of $0.3 billion.
NGTL Ownership Transfer
On April 1, 2024, ownership of the NGTL System was transferred from Nova Gas Transmission Ltd. to NGTL GP Ltd. on behalf of NGTL Limited Partnership as part of an ordinary course corporate reorganization to support business optimization.
NGTL System - Revenue Requirement Settlement and Multi-Year Growth Plan
On September 26, 2024, the CER approved a five-year negotiated revenue requirement settlement commencing on January 1, 2025. The settlement enables an investment framework that supports our Board of Directors' approval to allocate up to $3.3 billion of capital towards progression of the Multi-Year Growth Plan (MYGP) for expansion facilities to meet commitments on the NGTL System. It is comprised of multiple distinct projects with various targeted in-service dates, subject to final company and regulatory approvals. To date, approximately $1.1 billion of MYGP expansion facilities have received FID, with various in-service dates starting in 2026. Completion of the MYGP is expected to enable approximately 1.0 Bcf/d of incremental system throughput. The 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 settlement introduces a new incentive mechanism to reduce both physical emissions and emissions compliance costs, which builds on the incentive mechanism for certain operating costs where variances from projected amounts and emissions savings are shared with our customers. A provision for review by customers exists in the settlement if tolls exceed a pre-determined level or if final company approvals of the multi-year growth plan are not obtained.

TC Energy Annual Information Form 2025 | 7

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LNG PIPELINE PROJECTS
Coastal GasLink Pipeline
The Coastal GasLink pipeline is a 671 km (417 mile) pipeline that transports natural gas from a receipt point in the Dawson Creek area of British Columbia to LNG Canada's (LNGC) natural gas liquefaction facility near Kitimat, British Columbia. Transportation service on the pipeline is underpinned by 25-year TSAs (with renewal provisions) with each of the five LNGC joint venture participants (LNGC Participants). We hold a 35 per cent ownership interest in Coastal GasLink Limited Partnership (CGL LP), the entity that owns the Coastal GasLink pipeline. Additionally, we hold a 100 percent ownership interest in the general partner of CGL LP, the entity that operates the pipeline. Throughout construction, the project faced material cost pressures driven by the pandemic, labour, contractor and weather challenges, which ultimately increased the estimated cost of the project to approximately $14.5 billion, excluding potential cost recoveries and after accounting for certain factors that may be outside the control of CGL LP. In connection with the revised cost estimate, we announced our expectation that additional equity contributions required to fund the incremental project costs would be predominantly funded by us, with our share of total equity contributions expected to be up to $5.5 billion and no anticipated change to our 35 per cent ownership interest. This expectation resulted in the recording of cumulative pre-tax impairment charges of $5,148 million ($4,586 million after tax) between December 2022 and September 2023. No further impairment charges have been recorded since September 2023. In 2023, the Coastal GasLink pipeline project achieved mechanical completion, completed pipeline commissioning activities and was ready to deliver gas to the LNGC facility. These milestones entitled CGL LP to receive a $200 million readiness incentive payment from LNGC. The payment, which accrued entirely to TC Energy under the contractual terms between the CGL LP partners, was recognized as revenue by TC Energy in December 2023 and was received in February 2024. In June 2024, CGL LP successfully completed a $7.15 billion refinancing of its existing construction credit facility through a private placement bond offering of senior secured notes to Canadian and U.S. investors. Proceeds from the offering were used to repay the majority of the outstanding $8.0 billion balance on CGL LP's construction credit facility. The remaining balance on the construction credit facility was settled through the use of proceeds from the unwinding of certain hedging arrangements associated with the construction credit facility. In November 2024, CGL LP executed a commercial agreement with LNGC and each of the five LNGC Participants that retroactively declared commercial in-service for the Coastal GasLink pipeline effective October 1, 2024, and provided for a one-time payment of $199 million from LNGC Participants to TC Energy in recognition of completed work and final cost settlement. The payment, which accrued entirely to TC Energy under the contractual arrangements between the CGL LP partners, was recognized as an in-substance distribution from CGL LP in 2024 and was received in October 2025. In December 2024, following the commercial in-service of the Coastal GasLink pipeline, CGL LP repaid the $3,147 million balance owing under its subordinated loan agreement with TC Energy. Our share of equity contributions required by CGL LP to fund repayment of the subordinated loan amounted to $3,137 million. At December 31, 2025, our share of total partner equity contributions to fund the capital cost of the project was $5.3 billion. Reclamation activities associated with post-construction work were completed in 2025. In addition, CGL LP has resolved all material claims with a net positive recovery overall to CGL LP. Unused capacity of $163 million remains available under the subordinated loan agreement with TC Energy, though it is not anticipated that CGL LP will draw on a significant portion of the remaining availability.
Coastal GasLink - Cedar Link Expansion
In June 2024, CGL LP sanctioned the Cedar Link project following a positive FID for the construction of the Cedar LNG facility by the Cedar LNG joint venture partners, Haisla Nation and Pembina Pipeline Corporation. The Cedar LNG facility is a proposed floating liquefied natural gas facility to be constructed in Kitimat, British Columbia. The Cedar Link project is an expansion of the Coastal GasLink pipeline that is expected to enable delivery of up to 0.4 Bcf/d of natural gas to the Cedar LNG facility. With an estimated cost of $1.2 billion at FID, the expansion project includes the addition of a new compressor station, connector pipeline and meter station to the existing Coastal GasLink pipeline infrastructure. Funding for the expansion will be provided through project-level credit facilities of up to $1.4 billion secured by CGL LP in June 2024, equity funding to be provided by the CGL LP partners, including us, and the recovery of construction carrying costs from LNGC Participants who have elected to make payments on a quarterly basis throughout construction. The incremental funds available through the project-level credit facilities and cash AFUDC payments provide additional contingency to mitigate future funding requirements for CGL LP should costs exceed initial estimates of $1.2 billion. TC Energy has entered into an equity contribution agreement to fund up to a maximum of $37 million for its proportionate share of the equity requirements related to the Cedar Link project. All major regulatory permits have been received and construction began in July 2024. The planned in-service date for the Cedar Link project is 2028, subject to the completion of plant commissioning activities at the Cedar LNG facility.
Coastal GasLink - Indigenous Equity Option
In March 2022, we announced the signing of option agreements to sell up to a 10 per cent equity interest in CGL LP, to Indigenous communities across the project corridor, from our current 35 per cent equity ownership. In January 2026, prospective investors entered into a binding window for these options, which is expected to remain in effect through the end of 2026. Closing of the equity sale is subject to customary regulatory approvals and consents, including the consent of LNGC.

8 | TC Energy Annual Information Form 2025

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Developments in the U.S. Natural Gas Pipelines Segment

U.S. NATURAL GAS PIPELINES - COLUMBIA PIPELINE GROUP
Columbia Gas and Columbia Gulf Monetization
On October 4, 2023, we completed the sale of a 40 per cent equity interest in Columbia Gas and Columbia Gulf to Global Infrastructure Partners (GIP) for proceeds of $5.3 billion (US$3.9 billion). Columbia Gas and Columbia Gulf are held by a newly formed entity with GIP. Preceding the close of the equity sale, on August 8, 2023, Columbia Pipelines Operating Company LLC and Columbia Pipelines Holding Company LLC issued US$4.6 billion and US$1.0 billion of long-term, senior unsecured debt, respectively. The net proceeds from the offerings were used to repay existing intercompany indebtedness with TC Energy entities and were directed towards reducing leverage. We continue to have a controlling interest in Columbia Gas and Columbia Gulf and we remain the operator of these pipelines. TC Energy and GIP 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.
Columbia Gas Rate Case Settlement
Columbia Gas reached a settlement with its customers effective April 2025 and received FERC approval in October 2025. As part of the settlement, there is a moratorium on any further rate changes until March 31, 2028. 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. In fourth quarter 2025, previously accrued rate refund liabilities, including interest, were refunded to customers.
Columbia Gas - VR Project
In November 2025, the VR Project, a delivery market project on Columbia Gas designed to replace and upgrade certain facilities while improving reliability and reducing emissions, was placed in-service with a total project cost of approximately US$0.5 billion.
Columbia Gas - KO Transmission Enhancement Acquisition
On April 28, 2022, we approved the approximately US$80 million acquisition of KO Transmission assets to be integrated into our Columbia Gas pipeline to provide additional last-mile connectivity of Columbia Gas into northern Kentucky and southern Ohio to growing LDC markets and a platform for future capital investments including future conversions of coal-fueled power plants in the region. FERC approval for the acquisition was received in November 2022 and the transaction closed in February 2023.
Columbia Gas - Virginia Electrification Project
In February 2024, the Virginia Electrification Project, an expansion project that replaced and upgraded certain facilities through conversion to electric compression, was placed in-service.
Columbia Gas - TCO Connector
In October 2025, we approved the US$0.3 billion TCO Connector on our Columbia Gas system. This project is designed to provide capacity to serve new natural gas-fired power generation supporting forecasted electric generation growth, including expected data centre growth across our system. The TCO Connector project has an anticipated in-service date of 2030.
Columbia Gulf Rate Settlement
On July 7, 2023, Columbia Gulf filed an uncontested rate settlement, which set new recourse rates for Columbia Gulf effective March 1, 2024 and instituted a rate moratorium through February 28, 2027. Columbia Gulf must file for new rates no later than March 1, 2029.
Columbia Gulf - Pulaski and Maysville Projects
In November 2024, we approved two projects on our Columbia Gulf System: the Pulaski and Maysville Projects. These mainline extension projects off Columbia Gulf will facilitate full coal-to-gas conversion at two existing power plants and are expected to provide 0.2 Bcf/d of capacity for incremental gas-fired generation. The projects have anticipated in-service dates in 2029 and total estimated costs of US$0.8 billion.
Columbia Gulf - Southeast Virginia Energy Storage Project
In November 2024, we approved the US$0.3 billion Southeast Virginia Energy Storage Project. This is an LNG peaking facility in southeast Virginia that will serve an existing LDC's growing winter peak day load and mitigate its peak day pricing exposure, as well as increase operational flexibility on the Columbia Gas system. The project has an anticipated in-service date of 2030.
Columbia Gulf - East Lateral XPress
The East Lateral XPress Project, an expansion project on the Columbia Gulf system that connects supply to U.S. Gulf Coast LNG export markets, was placed in-service in May 2025, with a total project cost of approximately US$0.3 billion.

TC Energy Annual Information Form 2025 | 9

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OTHER U.S. NATURAL GAS PIPELINES
ANR Section 4 Rate Case 2022
ANR reached a settlement with its customers effective August 2022 and received FERC approval in April 2023. As part of the settlement, there was a moratorium on any further rate changes until November 1, 2025. ANR was required to file for new rates with an effective date no later than August 1, 2028, which was filed in April 2025. The settlement also included an additional rate step up which became effective in August 2024 related to certain modernization projects. In second quarter 2023, previously accrued rate refund liabilities, including interest, were refunded to customers.
ANR Section 4 Rate Case 2025
In April 2025, ANR filed a Section 4 Rate Case with FERC requesting an increase to its respective maximum transportation rates effective November 1, 2025, subject to refund. We intend to pursue a collaborative process to find a mutually beneficial outcome with our customers through settlement.
ANR Pipeline - Alberta XPress Project
The Alberta XPress Project, an expansion project on ANR which utilizes existing capacity on the Great Lakes and Canadian Mainline systems to connect growing supply from the WCSB to U.S. Gulf Coast LNG export markets, was placed in-service January 2023.
ANR Pipeline - WR Project
In November 2025, the WR Project, a delivery market project on ANR designed to replace and upgrade certain facilities while improving reliability and reducing emissions along portions of the ANR pipeline system in principal delivery markets, was placed in-service with a total project cost of US$0.7 billion.
ANR Pipeline - Ventura XPress Project
The Ventura XPress Project, a set of ANR projects designed to improve base system reliability and allow for additional long-term contracted transportation services to a point of delivery on the Northern Border pipeline at Ventura, Iowa, was placed in-service in October 2025 with a total project cost of approximately US$0.2 billion.
ANR Pipeline - Heartland Project
In February 2024, we approved the US$0.9 billion Heartland Project, an expansion project on our ANR system that is expected to increase capacity and improve system reliability. The Heartland Project involves pipeline looping, compressor facility additions as well as upgrades and is expected to increase ANR’s overall market share in the Midwest region. The anticipated in-service date is late 2027.
ANR Pipeline - Northwoods Project
In April 2025, we approved the Northwoods Project, an expansion project on our ANR system designed to provide 0.4 Bcf/d of capacity to serve natural gas-fired electric generation demand in the U.S. Midwest, including expected data centres and overall economic growth. The project involves pipeline looping, compressor facility additions as well as other system updates, with an anticipated in-service date of late 2029 and an estimated project cost of approximately US$0.9 billion.
Gas Transmission Northwest LLC (GTN) - GTN XPress
In December 2024, the GTN XPress Project, an expansion of the GTN system that will provide for the transport of incremental contracted export capacity facilitated by the NGTL System/Foothills West Path Delivery Program, was placed in-service. The capital cost of this project was approximately US$0.1 billion.
Great Lakes (GLGT) Rate Settlement
In April 2025, GLGT filed a Section 4 Rate Case with FERC requesting an increase to its respective maximum transportation rates effective November 1, 2025, subject to refund. We intend to pursue a collaborative process to find a mutually beneficial outcome with our customers through settlement.
Gillis Access Project
In March 2024, the Gillis Access Project, a 68 km (42 mile) greenfield pipeline system that connects gas production sourced from the Gillis hub to downstream markets in southeast Louisiana, was placed in-service. The capital cost of this project was approximately US$0.3 billion.
Gillis Access Project - Extension
In February 2023, we approved a 63 km (39 mile), 1.4 Bcf/d extension of the Gillis Access Project to further connect supplies from the Haynesville basin at Gillis. Effective September 1, 2024, all remaining shipper conditions expired and the project was expanded to 1.9 Bcf/d. The project has anticipated in-service dates starting in fourth quarter 2026 and total estimated costs of US$0.4 billion.
North Baja - North Baja XPress Project
In June 2023, the North Baja XPress Project, an expansion project designed to expand capacity and meet increased customer demand on our North Baja pipeline, was placed in-service.

10 | TC Energy Annual Information Form 2025

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Portland Natural Gas Transmission System (PNGTS)
On August 15, 2024, we completed the sale of PNGTS for a gross purchase price of approximately $1.6 billion (US$1.1 billion), which included US$250 million of senior notes outstanding held at PNGTS and assumed by the purchaser, BlackRock, through a fund managed by its Diversified Infrastructure business and investment funds managed by Morgan Stanley Infrastructure Partners (Purchaser). We provided customary transition services and worked jointly with the Purchaser to facilitate the safe and orderly transition of this natural gas system, which was completed in third quarter 2025.
Bison XPress Project
In third quarter 2023, we approved the Bison XPress Project, an expansion project on our Northern Border and Bison systems that will replace and upgrade certain facilities and provide much needed production egress from the Bakken basin to a delivery point at the Cheyenne Hub. In October 2024, FERC provided a certificate order approving the project that has an anticipated in-service date in 2026.

TC Energy Annual Information Form 2025 | 11

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Developments in the Mexico Natural Gas Pipelines Segment

MEXICO NATURAL GAS PIPELINES
TGNH Strategic Alliance with the CFE
In August 2022, we announced a strategic alliance with Mexico’s state-owned electric utility, the CFE, for the development of new natural gas infrastructure in central and southeast Mexico. In connection with the strategic alliance, we reached an FID to develop and construct the Southeast Gateway pipeline, a 1.3 Bcf/d, 715 km (444 mile) offshore natural gas pipeline to serve the southeast region of Mexico. The Southeast Gateway pipeline is in service and we commenced the collection of tolls beginning May 2025. In July 2025, the newly constituted CNE approved our regulated rates required to provide service to potential future interruptible service users on the Southeast Gateway pipeline other than the CFE. In 2024, the CFE became an equity partner in TGNH with a 13.01 per cent equity interest. The CFE's equity in TGNH is expected to increase to a maximum of 15 per cent, subject to regulatory approvals, and will increase to approximately 35 per cent upon expiry of the contract in 2055.
Villa de Reyes
We placed the lateral section of the Villa de Reyes pipeline into commercial service in third quarter 2023. We continue to work with our partner, the CFE, to complete the south section of the Villa de Reyes pipeline. The in-service date will be determined upon resolution of outstanding stakeholder issues.

12 | TC Energy Annual Information Form 2025

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POWER AND ENERGY SOLUTIONS

Developments in the Power and Energy Solutions Segment

CANADIAN POWER
Canadian Cogeneration Plants
In 2024, we executed contract extensions of 5-years at Mackay River, a natural gas cogeneration plant located in Alberta, and 10-years at Grandview, a natural gas cogeneration plant located in New Brunswick.
Saddlebrook Solar
In October 2023, we completed construction of the 81 MW Saddlebrook Solar Project near Aldersyde, Alberta and began commissioning activities, including supplying generation to the Alberta market. Full commercial operation was achieved on January 5, 2024. The project was partially supported with funding from Emissions Reduction Alberta and Lockheed Martin.
Renewable Energy Contracts and/or Investment Opportunities
In November 2023, a majority of the 297 MW Sharp Hills Wind Farm achieved commercial operation resulting in the commencement of our 15-year Power Purchase Agreement for 100 per cent of the power produced and the rights to all environmental attributes from the facility. In second quarter 2023, we finalized contracts to sell 50 MW under our 24-by-7 carbon-free power offering in Alberta, which provides customers power and carbon credits for the decarbonization of the customers’ Scope 2 emissions. Contract terms range from 15 to 20 years and commenced in January 2025.
Bruce Power
The Unit 6 MCR, the first of the six-unit MCR life extension program, was completed in third quarter 2023. The Unit 3 MCR and Unit 4 MCR, which are the second and third units in the MCR life extension program, commenced in first quarter 2023 and 2025 respectively, with expected completion dates in 2026 and 2028, respectively. The Unit 5 MCR final cost and schedule estimate was verified by the IESO on April 2, 2025. The Unit 5 MCR is expected to commence in fourth quarter 2026 with an expected return to service in early 2030. Investments in the remaining two units' MCR life extension programs are expected to continue through 2033. Future MCR investments will be subject to discrete decisions for each unit with specified off-ramps available for Bruce Power and the IESO. Along with the MCR life extension program, Bruce Power's Project 2030 has a goal of achieving a site peak output of 7,000 MW by 2033 in support of the province of Ontario's climate change targets and future clean energy needs. Project 2030 is focused on continued asset optimization, innovation and leveraging new technology, to increase site capability. Project 2030 is being implemented in three stages with Stage 1, 2 and 3a fully approved for execution. The program commenced in 2019 with a site capability of 6,430 MW and closed out 2025 at approximately 6,580 MW; a net gain of approximately 150 MW. Upon completion of Stages 1, 2 and 3a, the site is projected to reach an output of 6,840 MW. All three stages are being implemented in parallel to the MCR life extension program. Bruce Power's contract price increased in April 2022, in accordance with contract terms, reflecting capital to be invested under the Unit 3 MCR program and the 2022 to 2024 Asset Management program plus normal annual inflation adjustments. The contract price was then increased again in April 2024 as a result of the IESO approving the Unit 4 MCR program and increased again in April 2025 to reflect the 2025 to 2027 Asset Management program plus normal annual inflation adjustments and the 9-year reset for salaries and pensions.

TC Energy Annual Information Form 2025 | 13

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DISCONTINUED OPERATIONS

Spinoff Transaction
On July 27, 2023, we announced plans to separate into two independent, investment-grade, publicly listed companies through the spinoff of our Liquids Pipelines business into its own entity, South Bow. TC Energy shareholders voted to approve the Spinoff Transaction at our 2024 Annual and Special Meeting of shareholders held on June 4, 2024. The Spinoff Transaction received final approval from the Court of King’s Bench of Alberta on June 4, 2024 and was completed on October 1, 2024. The Spinoff Transaction was effected by way of a plan of arrangement under the CBCA pursuant to which, among other things, holders of TC Energy common shares retained their interest in TC Energy and received a pro rata allocation of South Bow’s common shares. On October 1, 2024, TC Energy and South Bow entered into a separation agreement setting 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, we reached an agreement with South Bow with respect to liabilities we indemnified South Bow for under the Separation Agreement, releasing us from those liabilities.

14 | TC Energy Annual Information Form 2025

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General

EMPLOYEES

At Year End, TC Energy's principal operating subsidiary, TCPL, had 6,574 employees, substantially all of whom were employed
in Canada and the U.S., as set forth in the following table.

Calgary			2,185
Western Canada (excluding Calgary)			592
Eastern Canada			275
Houston			749
U.S. Midwest			769
U.S. Northeast			203
U.S. Southeast/Gulf Coast (excluding Houston)			1,184
U.S. West Coast			96
Mexico			521
Total			6,574

HEALTH, SAFETY, SUSTAINABILITY AND ENVIRONMENTAL PROTECTION GOVERNANCE AND SOCIAL POLICIES

A discussion of our health, safety, sustainability and environmental protection governance can be found in the MD&A in the Other information – Health, safety, sustainability and environmental matters section, which section is incorporated by reference herein.

Social Policies

We have a number of corporate governance documents, such as policies and standards, including a Commitment Statement,
to help guide our teams’ behavior and actions with respect to our core values as well as legal and compliance obligations so they understand their responsibilities and extend respect and courtesy to Indigenous groups and other stakeholders. We have a Code of Business Ethics (COBE) Policy which functions together with TC Energy's other policies and applies to all employees, officers and directors, and contingent workforce contractors of TC Energy and its wholly-owned subsidiaries and/or operated entities
in all countries where we conduct business, with the exception of independently operated entities whose corporate governance documents meet or exceed TC Energy’s requirements. Annual online COBE training is provided to all employees and contingent workforce contractors, and all employees and contingent workforce contractors (including executive officers) and directors must certify their compliance with COBE annually. In addition, TC Energy has a Contractor COBE Policy which imposes the same requirements as the COBE Policy on Contractors, as applicable.

We also have an Avoiding Bribery and Corruption (ABC) Program which includes an ABC Policy, annual online training included
as part of annual online COBE training, instructor-led training provided to personnel in higher risk locations of our business,
a supplier and contractor due diligence review process, and auditing of certain types of transactions.

Our Indigenous Relations Policy is informed by our guiding principles and core values to ensure we build and sustain support through early and honest communication, by mitigating impacts, and through mutually beneficial partnerships. We seek
to listen to Indigenous peoples and incorporate their traditional and local knowledge in project design and planning. We strive
to work with Indigenous communities to mitigate negative impacts and maximize benefits through hiring and buying locally.
We aim to build mutually beneficial, partnership-oriented relationships with Indigenous communities who are most impacted
by our activities. In Canada, we will seek to expand benefits for equity participation in our projects because the best way to align interests from the start is to sit at the table together as partners/owners. Through all these efforts, we strive to be considered
as a partner of choice for Indigenous groups and play a meaningful role in reconciliation.

Consistent with our four core values, safety in every step, personal accountability, one team and active learning, Commitment Statement and as outlined in our COBE Policy, TC Energy does not tolerate human rights abuses. In our business activities, including engaging with Indigenous groups and other stakeholders across Canada, the U.S and Mexico, we are committed
to respecting human rights and will not be complicit with, or engage in, any activity that supports or facilitates abuse of
human rights such as forced labour, child labour, or physical or mental abuses.

TC Energy Annual Information Form 2025 | 15

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Risk factors

A discussion of our risk factors can be found in the MD&A in the Natural Gas Pipelines Business, Natural Gas Pipelines - Business risks, Power and Energy Solutions – Business risks and Other information – Risk oversight and enterprise risk management sections, which sections are incorporated by reference herein.

Dividends

Our Board has not adopted a formal dividend policy. The Board reviews the financial performance of TC Energy quarterly and makes a determination of the appropriate level of dividends to be declared in the following quarter. Currently, our payment of dividends is primarily funded from dividends TC Energy receives as the sole common shareholder of TCPL.

Provisions of various trust indentures and credit arrangements with certain of our subsidiaries can restrict those subsidiaries’ ability and, in certain cases, our ability to declare and pay dividends or make distributions under certain circumstances. In the opinion of management, these provisions do not currently restrict our ability to declare or pay dividends.

Additionally, the terms of the hybrid notes issued by TCPL and trust notes issued by TransCanada Trust (a financing trust subsidiary wholly-owned by TCPL), and the respective related agreements, contain dividend stopper provisions which, among other things, are generally triggered if TCPL elects to defer interest payable on the applicable notes. When such provisions are triggered, they prohibit TC Energy and TCPL from declaring or paying dividends, among other prohibitive measures. The dividend stopper provisions have not been triggered for either the hybrid notes or the trust notes.

Dividends on our preferred shares are payable quarterly, as and when declared by the Board. The dividends declared on our common and preferred shares during the past three completed financial years, and the quarterly dividend per common share
on our outstanding common shares for the quarter ending March 31, 2026, are set out in the MD&A under the heading
About our business – 2025 Financial highlights – Dividends section, which section is incorporated by reference herein.

16 | TC Energy Annual Information Form 2025

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Description of capital structure

SHARE CAPITAL

TC Energy’s authorized share capital consists of an unlimited number of common shares and an unlimited number of first preferred shares and second preferred shares, issuable in series. The number of common shares and preferred shares issued and outstanding as at Year End are set out in the MD&A in the Financial Condition – Share information section, which section is incorporated by reference herein. The following is a description of the material characteristics of each of these classes of shares.

Common shares

The common shares entitle the holders thereof to one vote per share at all meetings of shareholders, except meetings at which only holders of another specified class of shares are entitled to vote, and, subject to the rights, privileges, restrictions and conditions attaching to the first preferred shares and the second preferred shares, whether as a class or a series, and to any other class or series of shares of TC Energy which rank prior to the common shares, entitle the holders thereof to receive (i) dividends if, as and when declared by the Board out of the assets of TC Energy properly applicable to the payment of the dividends in such amount and payable at such times and at such place or places as the Board may from time to time determine, and (ii) the remaining property of TC Energy upon a liquidation, dissolution or winding up of the Company.

We have a shareholder rights plan (the Plan) that is designed to protect the rights of our shareholders, ensure they are treated fairly and provide the Board with adequate time to identify, develop and negotiate alternative value maximizing transactions if there is a take-over bid for TC Energy. The Plan creates a right attaching to each common share outstanding and to each common share subsequently issued. Each right becomes exercisable 10 trading days after a person has acquired (an acquiring person), or commences a take-over bid to acquire, 20 per cent or more of the common shares, other than by an acquisition pursuant to a take-over bid permitted under the terms of the Plan (a permitted bid). Prior to a flip-in event (as described below), each right permits registered holders to purchase from the Company common shares of TC Energy at an exercise price equal to three times the market price of such shares, subject to adjustments and anti-dilution provisions (the exercise price). The beneficial acquisition by any person of 20 per cent or more of the common shares, other than by way of a permitted bid, is referred to as a flip-in event. Ten trading days after a flip-in event, each right will permit registered holders other than an acquiring person to receive, upon payment of the exercise price, the number of common shares with an aggregate market price equal to twice the exercise price. The Plan was reconfirmed at the 2025 annual meeting of TC Energy shareholders and must be reconfirmed at every third annual meeting thereafter.

A discussion of our dividend reinvestment and share purchase plan can be found in the MD&A in the About our business - 2025 Financial highlights – Dividends – Dividend reinvestment and share purchase plan and the Financial condition - Dividend reinvestment plan sections, which sections are incorporated by reference herein.

TC Energy Annual Information Form 2025 | 17

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First preferred shares

Subject to certain limitations, the Board may, from time to time, issue first preferred shares in one or more series and determine for any such series, its designation, number of shares and respective rights, privileges, restrictions and conditions. The first preferred shares as a class have, among others, the provisions described below.

The first preferred shares of each series rank on a parity with the first preferred shares of every other series, and are entitled
to preference over the common shares, the second preferred shares and any other shares ranking junior to the first preferred shares with respect to the payment of dividends, the repayment of capital and the distribution of assets of TC Energy in the event of its liquidation, dissolution or winding up.

Except as provided by the CBCA, the holders of the first preferred shares will not have any voting rights nor will they be entitled to receive notice of or to attend shareholders' meetings. The holders of any particular series of first preferred shares will, if the directors so determine prior to the issuance of such series, be entitled to such voting rights as may be determined by the Board
if TC Energy fails to pay dividends on that series of preferred shares for any period as may be so determined by the Board.
TC Energy currently does not intend to issue any first preferred shares with voting rights, and any issuances of first preferred shares are expected to be made only in connection with corporate financings.

The provisions attaching to the first preferred shares as a class may be modified, amended or varied only with the approval
of the holders of the first preferred shares as a class. Any such approval to be given by the holders of the first preferred shares may be given by the affirmative vote of the holders of not less than 66 2/3 per cent of the first preferred shares represented
and voted at a meeting or adjourned meeting of such holders.

The holders of Series 1, 3, 5, 7 and 9 preferred shares will be entitled to receive quarterly fixed rate cumulative preferential cash dividends, as and when declared by the Board, to be reset periodically on prescribed dates to an annualized rate equal to the sum of the then five-year Government of Canada bond yield, calculated at the start of the applicable five-year period, and a spread as set forth in the table below and have the right to convert their shares into cumulative redeemable Series 2, 4, 6, 8
and 10 preferred shares, respectively, subject to certain conditions, on such conversion dates as set forth in the table below.
The Series 1, 3, 5, 7 and 9 preferred shares are redeemable by TC Energy in whole or in part on such redemption dates as set forth in the table below, by the payment of an amount in cash for each share to be redeemed equal to $25.00 plus all accrued and unpaid dividends thereon.

The holders of Series 2, 4, 6, 8 and 10 preferred shares will be entitled to receive quarterly floating rate cumulative preferential cash dividends, as and when declared by the Board, at an annualized rate equal to the sum of the then 90-day Government of Canada treasury bill rate, recalculated quarterly, and a spread as set forth in the table below and have the right to convert their shares into Series 1, 3, 5, 7 and 9 preferred shares, respectively, subject to certain conditions, on such conversion dates as set forth in the table below. The Series 2, 4, 6, 8 and 10 preferred shares are redeemable by TC Energy in whole or in part after their respective initial redemption date as set forth in the table below, by the payment of an amount in cash for each share to be redeemed equal to (i) $25.00 in the case of redemptions on such redemption dates as set out in the table below, or (ii) $25.50
in the case of redemptions on any other date, in each case plus all accrued and unpaid dividends thereon.

18 | TC Energy Annual Information Form 2025

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In the event of liquidation, dissolution or winding up of TC Energy, the holders of Series 1, 2, 3, 4, 5, 6, 7, 8, 9 and 10 preferred shares shall be entitled to receive $25.00 per preferred share plus all accrued and unpaid dividends thereon in preference over the common shares or any other shares ranking junior to the first preferred shares.

Series of first preferred shares			Initial redemption/conversion date			Redemption/conversion dates			Spread (%)
Series 1 preferred shares			December 31, 2014			December 31, 2029 and every fifth year thereafter			1.92
Series 2 preferred shares			—			December 31, 2029 and every fifth year thereafter			1.92
Series 3 preferred shares			June 30, 2015			June 30, 2030 and every fifth year thereafter1			1.28
Series 4 preferred shares			—			June 30, 2030 and every fifth year thereafter1			1.28
Series 5 preferred shares			January 30, 2016			January 30, 2031 and every fifth year thereafter			1.54
Series 6 preferred shares			—			January 30, 2031 and every fifth year thereafter			1.54
Series 7 preferred shares			April 30, 2019			April 30, 2029 and every fifth year thereafter			2.38
Series 8 preferred shares			—			April 30, 2029 and every fifth year thereafter			2.38
Series 9 preferred shares			October 30, 2019			October 30, 2029 and every fifth year thereafter			2.35
Series 10 preferred shares			—			October 30, 2029 and every fifth year thereafter			2.35
Series 11 preferred shares2			November 30, 2020			November 28, 2025			—
Series 12 preferred shares3			—			—			—

Except as provided by the CBCA, the respective holders of the first preferred shares of each outstanding series are not entitled
to receive notice of, attend at, nor vote at any meeting of shareholders unless and until TC Energy shall have failed to pay eight quarterly dividends on such series of preferred shares, whether or not consecutive, in which case the holders of the first preferred shares of such series shall have the right to receive notice of and to attend each meeting of shareholders at which directors are to be elected and which take place more than 60 days after the date on which the failure first occurs, and to one vote with respect to resolutions to elect directors for each of the first preferred share of such series, until all arrears of dividends have been paid. Subject to the CBCA, the series provisions attaching to the first preferred shares may be amended with the written approval of all the holders of such series of shares outstanding or by at least two thirds of the votes cast at a meeting
of the holders of such shares duly called for that purpose and at which a quorum is present.

Second preferred shares

The rights, privileges, restrictions and conditions attaching to the second preferred shares are substantially identical to those attaching to the first preferred shares, except that the second preferred shares rank junior to the first preferred shares with respect to the payment of dividends, repayment of capital and the distribution of assets of TC Energy in the event of a liquidation, dissolution or winding up of TC Energy.

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

2 On November 28, 2025, TC Energy redeemed all of its issued and outstanding Series 11 preferred shares. Subsequent to the redemption, the Series 11 preferred shares ceased to be listed on the TSX and were cancelled.

3 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.

TC Energy Annual Information Form 2025 | 19

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Credit ratings

Although TC Energy has not issued debt to the public, it has been assigned credit ratings by Moody's Investors Service, Inc. (Moody's), S&P Global Ratings (S&P) and Fitch Ratings Inc. (Fitch), and its outstanding preferred shares have also been assigned credit ratings by S&P, Fitch and DBRS Limited (DBRS). Moody's has assigned TC Energy an issuer rating of Baa3 with a stable outlook, S&P has assigned an issuer credit rating of BBB+ with a stable outlook, and Fitch has assigned a long-term issuer default rating of BBB+ with a stable outlook. TC Energy does not presently intend to issue debt securities to the public in its own name and any future debt financing requirements are expected to continue to be funded primarily through its subsidiary, TCPL.
The following table sets out the current credit ratings assigned to those outstanding classes of securities of the Company,
TCPL and TransCanada Trust, and certain related subsidiaries which have been rated by Moody's, S&P, Fitch and DBRS:

Moody's

S&P

Fitch

DBRS

TCPL - Senior unsecured debt

Baa2

BBB+

BBB+

BBB (high)

TCPL - Junior subordinated notes

Baa3

BBB-

BBB-1

BBB (low)1

TransCanada Trust - Subordinated trust notes

Ba1

BBB-

BBB-

Not rated

TC Energy Corporation - Preferred shares

Not rated

P-2 (Low)

BBB-

Pfd-3 (high)

Commercial paper (TCPL and TCPL guaranteed)

P-2

A-2

F2

R-2 (high)

Rating outlook/status

Stable

Stable

Stable

Stable

Credit ratings are intended to provide investors with an independent measure of credit quality of an issue of securities.
Credit ratings are not recommendations to purchase, hold or sell securities and do not address the market price or suitability
of a specific security for a particular investor. There is no assurance that any rating will remain in effect for any given period
of time or that any rating will not be revised or withdrawn entirely by a rating agency in the future if, in its judgment, circumstances so warrant.

Each of the Company, TCPL, TransCanada Trust and certain of our other subsidiaries paid fees to each of Moody's, S&P, Fitch
and DBRS for the credit ratings rendered in respect of their outstanding classes of securities noted above. In addition to annual monitoring fees for the Company and TCPL and their rated securities, additional payments are made in respect of other services provided in connection with various rating advisory services.

The information concerning our credit ratings relates to our financing costs, liquidity and operations. The availability and cost
of our funding options may be affected by certain factors, including the global capital markets environment and outlook as well as our financial performance. Our access to capital markets for required capital at competitive rates is influenced by our credit rating and rating outlook, as determined by credit rating agencies such as Moody's, S&P, Fitch and DBRS. If our ratings were downgraded, TC Energy's financing costs and future debt issuances could be unfavourably impacted. A description of the rating agencies' credit ratings listed in the table above is set out below.

MOODY’S

Moody's has different rating scales for short- and long-term obligations. Numerical modifiers 1, 2 and 3 are appended to each rating classification from Aa through Caa. The modifier 1 indicates that the obligation ranks in the higher end of its generic rating category; the modifier 2 indicates a mid-range ranking; and a modifier 3 indicates a ranking in the lower end of that generic rating category. The Baa2 rating assigned to TCPL's senior unsecured debt and the Baa3 rating assigned to TCPL's junior subordinated notes are in the fourth highest of nine rating categories for long-term obligations. Obligations rated Baa are judged to be medium-grade and are subject to moderate credit risk, and as such, may possess certain speculative characteristics. The Ba1 rating assigned to the TransCanada Trust subordinated trust notes, is in the fifth highest of nine rating categories for long-term obligations. Obligations rated Ba are judged to have speculative elements and are subject to substantial credit risk. The P-2 rating assigned to TCPL's and TCPL guaranteed U.S. commercial paper programs is the second highest of four rating categories for short-term debt issuers. Issuers rated P-2 have a strong ability to repay short-term debt obligations. Outlooks may be assigned at the issuer level or at the rating level. A Moody’s rating outlook is an opinion regarding the likely rating direction over the medium term. A stable outlook indicates a low likelihood of a rating change over the medium term. A negative, positive or developing outlook indicates a higher likelihood of a rating change over the medium term.

1 The assigned rating applies to only certain classes of the securities noted, further details are set out below.

20 | TC Energy Annual Information Form 2025

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S&P

S&P has different rating scales for short- and long-term obligations and Canadian preferred shares. Ratings from AA through CCC may be modified by the addition of a plus (+) or minus (-) sign to show the relative standing within a particular rating category. The BBB+ rating assigned to TCPL's senior unsecured debt is in the fourth highest of 10 rating categories for long-term obligations. A BBB rating indicates the obligor's capacity to meet its financial commitment is adequate; however, adverse economic conditions or changing circumstances are more likely to weaken the obligor's capacity to meet its financial commitments on the obligation. The BBB- ratings assigned to TCPL’s junior subordinated notes and to the TransCanada Trust subordinated trust notes, is in the fourth highest of 10 rating categories for long-term debt obligations and the P-2 (Low) rating assigned to TC Energy’s preferred shares is the second highest of eight rating categories for Canadian preferred shares. The BBB- ratings assigned to TCPL's junior subordinated notes and the TransCanada Trust subordinated trust notes, and the P-2 (Low) rating assigned to TC Energy's preferred shares indicate these obligations exhibit adequate protection parameters. However, adverse economic conditions or changing circumstances are more likely to weaken the obligor’s capacity to meet its financial commitment on the obligation. TCPL's and TCPL guaranteed U.S. commercial paper programs are each rated A-2 which is the second highest of six rating categories for short-term debt issuers. Short-term debt issuers rated A-2 have satisfactory capacity to meet their financial commitments, however they are somewhat more susceptible to adverse effects of changes in circumstances and economic conditions than obligors in the highest rating category. S&P assigns outlooks to issuers and not to individual debt securities. An S&P outlook assesses the potential direction of a long-term credit rating over the intermediate term, which is generally up to two years for investment grade issuers. S&P has assigned a stable outlook to the Company, indicating its ratings are not likely to change over the intermediate term.

FITCH

Fitch has different rating scales for short- and long-term obligations. Ratings from AA through CCC may be modified by the addition of a plus (+) or minus (-) sign to show the relative status within a particular rating category. The BBB+ rating assigned
to TCPL's senior unsecured debt, and the BBB- ratings assigned to all series of TCPL's junior subordinated notes, with the exception of the series due 2067 which are not rated by Fitch, the TransCanada Trust subordinated trust notes and TC Energy's preferred shares are in the fourth highest of 11 rating categories for long-term obligations. A BBB rating indicates that expectations of default risk are currently low and that the capacity for payment of financial commitments is considered adequate, but adverse business or economic conditions are more likely to impair this capacity. The F2 rating assigned to TCPL's and TCPL guaranteed U.S. commercial paper program is the second highest of seven rating categories for short-term debt issuers. Issuers rated F2 have good intrinsic capacity for timely payment of financial commitments. Ratings outlooks by Fitch indicate the direction a rating is likely to move over a one-to-two year period and reflect financial or other trends that have
not yet reached or been sustained to the level that would cause a rating action, but which may do so if such trends continue.

TC Energy Annual Information Form 2025 | 21

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DBRS

DBRS has different rating scales for short- and long-term obligations and Canadian preferred shares. High or low grades are used to indicate the relative standing within all rating categories other than AAA and D and other than in respect of DBRS’ ratings
of commercial paper and short-term debt, which utilize high, middle and low subcategories for its R-1 and R-2 rating categories.
In respect of long-term debt and preferred share ratings, the absence of either a high or low designation indicates the rating
is in the middle of the category. The BBB (high) rating assigned to TCPL's senior unsecured debt and the BBB (low) rating assigned to TCPL's junior subordinated notes due 2067 are in the fourth highest of 10 categories for long-term debt and indicate adequate credit quality. The capacity for the payment of financial obligations is considered acceptable. Long-term debt rated BBB may be vulnerable to future events. The Pfd-3 (high) rating assigned to TC Energy's preferred shares is in the third highest
of six rating categories for preferred shares. Preferred shares rated Pfd-3 are generally of adequate credit quality. While protection of dividends and principal is still considered acceptable, the issuing entity is more susceptible to adverse changes
in financial and economic conditions, and there may be other adverse conditions present which detract from debt protection. Pfd-3 ratings generally correspond with issuers with a BBB category or higher reference point. The R-2 (high) rating assigned
to TCPL's Canadian commercial paper program is in the fourth highest of 10 rating categories for short-term debt issuers and indicates the upper end of adequate credit quality. The capacity for payment of short-term financial obligations as they fall due is acceptable. Short-term debt rated R-2 (high) may be vulnerable to future events. Rating trends provide guidance in respect
of DBRS' opinion regarding the outlook for a credit rating. The rating trend indicates the direction in which DBRS considers the credit rating may move if present circumstances continue.

Market for securities

TC Energy's common shares are listed on the TSX and the NYSE under the symbol TRP. The following table sets out our preferred shares listed on the TSX as of February 12, 2026.

Type			Issue Date			Stock Symbol
Series 1 preferred shares			September 30, 2009			TRP.PR.A
Series 2 preferred shares			December 31, 2014			TRP.PR.F
Series 3 preferred shares			March 11, 2010			TRP.PR.B
Series 4 preferred shares			June 30, 2015			TRP.PR.H
Series 5 preferred shares			June 29, 2010			TRP.PR.C
Series 7 preferred shares			March 4, 2013			TRP.PR.D
Series 9 preferred shares			January 20, 2014			TRP.PR.E
Series 10 preferred shares			October 30, 2024			TRP.PR.L

22 | TC Energy Annual Information Form 2025

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The following tables set out the reported monthly high, low, and month end closing trading prices and monthly trading volumes of the common shares of TC Energy on the TSX and the NYSE, and the respective Series 1, 2, 3, 4, 5, 6, 7, 9, 10 and 11 preferred shares on the TSX, for the periods indicated:

COMMON SHARES

Month			TSX (TRP)															NYSE (TRP)
			High ($)			Low ($)			Close ($)			Volume traded						High (US$)			Low (US$)			Close (US$)			Volume traded
December 2025			$77.13			$73.47			$75.58			135,417,416						$56.34			$53.29			$55.01			41,845,330
November 2025			$77.73			$69.41			$75.50			61,399,157						$55.34			$49.27			$54.72			41,655,751
October 2025			$77.26			$69.79			$70.38			130,458,322						$55.37			$49.84			$50.16			53,521,212
September 2025			$75.72			$70.69			$75.67			130,669,258						$54.41			$51.08			$54.41			42,740,936
August 2025			$72.26			$65.74			$71.52			61,652,740						$52.26			$47.76			$52.06			30,495,956
July 2025			$66.99			$63.34			$66.16			155,628,759						$48.91			$46.29			$47.88			52,376,366
June 2025			$71.12			$63.99			$66.48			196,248,816						$51.99			$46.53			$48.79			65,419,664
May 2025			$70.88			$66.89			$69.54			48,067,304						$51.34			$47.92			$50.64			33,773,035
April 2025			$70.33			$62.17			$69.65			177,046,397						$50.50			$43.59			$50.41			69,452,348
March 2025			$70.97			$64.31			$67.96			201,361,199						$49.70			$44.40			$47.21			48,195,155
February 2025			$67.94			$62.55			$64.75			63,507,626						$47.51			$43.51			$44.74			36,662,346
January 2025			$70.05			$64.65			$65.49			111,508,044						$48.64			$44.86			$45.05			44,082,793

TC Energy Annual Information Form 2025 | 23

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PREFERRED SHARES

Month			Series 1			Series 2			Series 3			Series 4			Series 5			Series 61			Series 7			Series 9			Series 10			Series 112
December 2025
High			$21.39			$19.95			$18.32			$17.00			$19.46			$19.96			$24.64			$23.60			$23.38			—
Low			$20.69			$18.92			$17.74			$16.40			$18.25			$18.20			$23.70			$22.61			$20.60			—
Close			$21.39			$19.75			$18.15			$16.89			$19.42			$19.61			$24.39			$23.47			$21.68			—
Volume Traded			292,289			39,356			337,291			45,779			307,494			15,130			156,477			74,783			1,000			—
November 2025
High			$21.43			$19.50			$18.25			$17.01			$18.30			$19.50			$24.48			$23.40			$22.68			$25.21
Low			$20.40			$18.56			$17.22			$16.11			$17.71			$17.75			$22.98			$22.07			$20.00			$24.97
Close			$21.43			$19.40			$18.25			$16.65			$18.30			$18.85			$24.25			$22.95			$21.64			$25.00
Volume Traded			144,604			56,626			309,410			15,282			407,861			15,352			161,768			166,682			2,158			317,135
October 2025
High			$20.50			$18.95			$17.50			$16.54			$17.74			$17.99			$24.21			$23.16			$21.75			$25.25
Low			$19.93			$18.44			$16.91			$15.96			$17.45			$16.70			$23.19			$21.70			$19.95			$24.80
Close			$20.50			$18.61			$17.49			$16.12			$17.74			$17.80			$24.21			$23.14			$21.38			$25.17
Volume Traded			337,443			32,789			309,082			11,892			431,465			10,270			351,287			235,850			900			1,924,989
September 2025
High			$20.38			$19.05			$18.89			$16.77			$17.89			$18.11			$23.70			$22.10			$22.00			$25.02
Low			$19.47			$18.37			$16.49			$15.90			$17.29			$17.50			$23.14			$21.48			$20.27			$24.70
Close			$19.98			$18.66			$17.12			$16.09			$17.59			$17.75			$23.70			$22.10			$20.89			$24.93
Volume Traded			756,487			25,412			292,785			52,963			63,032			9,820			544,082			310,960			7,325			273,236
August 2025
High			$20.91			$19.50			$17.42			$16.90			$17.96			$18.12			$23.60			$22.46			$22.00			$24.95
Low			$20.06			$18.63			$15.62			$15.99			$17.55			$16.70			$22.86			$21.34			$20.25			$24.34
Close			$20.19			$19.29			$17.31			$16.79			$17.79			$18.09			$23.45			$22.00			$21.15			$24.95
Volume Traded			511,810			19,641			431,829			21,506			193,009			9,100			104,462			198,491			1,700			178,547
July 2025
High			$21.04			$19.49			$17.58			$17.38			$18.01			$18.01			$23.45			$22.70			$22.70			$24.79
Low			$19.40			$17.65			$16.90			$15.50			$16.85			$16.56			$22.61			$20.69			$18.95			$24.19
Close			$20.90			$19.49			$17.35			$16.38			$18.01			$18.00			$23.40			$22.60			$21.50			$24.65
Volume Traded			447,238			79,713			832,684			36,414			617,227			18,677			270,239			150,387			3,402			298,652
June 2025
High			$19.48			$17.90			$17.10			$15.95			$17.32			$17.05			$22.91			$20.95			$20.30			$24.20
Low			$18.47			$16.85			$15.02			$14.99			$15.21			$15.16			$21.87			$19.86			$18.00			$22.70
Close			$19.48			$17.86			$17.10			$15.92			$16.91			$16.75			$22.62			$20.83			$19.75			$24.15
Volume Traded			211,947			60,751			439,289			83,340			323,297			45,231			255,167			218,330			9,931			127,345
May 2025
High			$19.05			$17.50			$15.14			$15.15			$15.50			$15.50			$21.87			$19.94			$19.80			$23.44
Low			$17.43			$16.26			$14.10			$13.88			$14.27			$14.50			$20.52			$18.57			$17.25			$21.90
Close			$18.81			$17.00			$15.10			$15.15			$15.25			$15.50			$21.78			$19.80			$18.54			$22.97
Volume Traded			217,650			154,003			463,983			28,008			643,789			35,955			380,863			251,042			2,800			270,472
April 2025
High			$18.50			$17.92			$14.85			$14.90			$15.11			$15.55			$21.44			$19.61			$19.40			$23.00
Low			$16.47			$15.80			$13.45			$13.36			$13.41			$14.15			$19.26			$17.13			$16.55			$20.80
Close			$17.36			$16.10			$14.08			$14.08			$14.18			$14.75			$20.48			$18.49			$17.50			$21.77
Volume Traded			236,476			315,144			110,274			35,364			92,967			23,668			320,589			115,975			18,119			202,403
March 2025
High			$18.59			$17.94			$15.28			$15.18			$15.75			$16.04			$21.85			$20.10			$19.85			$23.10
Low			$17.80			$17.01			$14.33			$14.39			$14.74			$15.20			$21.20			$19.32			$18.01			$22.00
Close			$18.59			$17.86			$14.85			$14.82			$15.16			$15.60			$21.28			$19.60			$19.50			$22.99
Volume Traded			432,891			30,318			165,621			28,700			402,604			18,902			442,303			110,932			2,903			213,490
February 2025
High			$18.81			$18.35			$15.70			$15.64			$16.02			$16.20			$21.80			$20.20			$22.20			$23.41
Low			$18.29			$17.70			$15.15			$14.87			$15.55			$15.73			$21.01			$19.41			$19.00			$22.50
Close			$18.32			$17.75			$15.23			$15.07			$15.76			$15.89			$21.80			$19.84			$19.45			$23.10
Volume Traded			171,169			36,102			289,291			46,217			424,675			25,816			307,095			314,624			880			297,015
January 2025
High			$18.86			$18.69			$16.00			$16.60			$16.44			$16.48			$21.58			$20.18			$22.20			$23.91
Low			$18.02			$17.65			$14.50			$14.50			$14.83			$15.30			$20.86			$19.19			$18.60			$22.19
Close			$18.84			$18.32			$15.80			$15.51			$16.04			$16.11			$21.50			$20.18			$19.25			$23.25
Volume Traded			545,144			319,340			216,777			64,613			153,320			30,739			444,395			476,345			3,160			113,966

1 TC Energy's cumulative redeemable first preferred shares, Series 6, were listed on the TSX under the symbol TRP.PR.I until their conversion into cumulative redeemable first preferred shares, Series 5 on January 30, 2026.

2 TC Energy's cumulative redeemable first preferred shares, Series 11, were listed on the TSX under the symbol TRP.PR.G until their redemption on November 28, 2025.

24 | TC Energy Annual Information Form 2025

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Directors and officers

As of February 12, 2026, the directors and executive officers of TC Energy as a group beneficially owned, or exercised control
or direction over, directly or indirectly, an aggregate of 426,525 common shares, constituting 0.04 per cent of the common shares of TC Energy. The Company collects this information from our directors and executive officers but otherwise we have
no direct knowledge of individual holdings of TC Energy's securities.

DIRECTORS

The following table sets forth the names of the directors who serve on the Board as of February 12, 2026, together with
their jurisdictions of residence, all positions and offices held by them with TC Energy, unless otherwise stated, their principal occupations or employment during the past five years and the year from which each director has continually served as a director of TC Energy. Positions and offices held with TC Energy are also held by such person at TCPL. Each director holds office until the next annual meeting or until his or her successor is earlier elected or appointed.

Name and place of residence						Principal occupation during the five preceding years			Director since
Scott Bonham Atherton, California U.S.A.						Corporate director. Co-founder of Intentional Capital Real Estate (Canada) (real estate asset management) since October 2014. Director, Loblaw Companies Limited (retail grocery) since October 2016. Advisor to the CEO, Magna International Inc. (Magna) (automotive manufacturing) from May 2021 to December 2025. Director, The Bank of Nova Scotia (Scotiabank) (chartered bank) from January 2016 to April 2025, and Magna from May 2012 to May 2021.			2024
Cheryl F. Campbell Monument, Colorado U.S.A.						Corporate director. Director, Pacific Gas & Electric Corporation (PGE) (utilities) since April 2019, Summit Utilities (Summit) (natural gas distribution) since September 2020 and Board Chair of Summit since January 2024, JANA Corporation (engineering) since January 2020, and National Underground Group (infrastructure service provider) from March 2018 to December 2023.			2022
Michael R. Culbert Calgary, Alberta Canada						Corporate director. Director, ARC Resources Ltd. (ARC) (oil and gas, exploration and production) since May 2024, Humble Midstream II LLC (oil and gas) from December 2023 to February 2025, Precision Drilling Corporation (Precision) (oil and gas services) from December 2017 to June 2024, Komfort IQ Canada (HVAC controls company) from June 2022 to December 2023, Reserve Royalty Income Trust (private oil and gas royalty trust) from May 2017 to June 2021, and Enerplus Corporation (Enerplus) (oil and gas, exploration and production) from March 2014 to August 2020. Vice-Chair (Non-Executive) and Director, PETRONAS Canada Ltd. (PETRONAS) (oil and natural gas) from November 2016 to March 2020.			2020
William D. Johnson Knoxville, Tennessee U.S.A.						Corporate director. Director, Strata Clean Energy (renewable power) since January 2025, Terrestrial Energy Inc. (nuclear power) since February 2023, NiSource Inc. (utilities) since March 2022, and BrightNight LLC (renewable energy) since December 2021. President and CEO, PGE (utilities) from May 2019 to June 2020.			2021
Susan C. Jones Calgary, Alberta Canada						Corporate director. Director, Canadian National Railway Limited (freight railway) since May 2022, Piedmont Lithium Inc. (Piedmont) (emerging lithium company) from June 2021 to June 2023, ARC from April 2020 to February 2023, and Gibson Energy Inc. (Gibson) (mid-stream oil-focused infrastructure company) from December 2018 to February 2020.			2020
John E. Lowe Houston, Texas U.S.A.						Corporate director. Chair of the Board, TC Energy since January 2024. Member, International Board of Advisors, Horizon Engage (global intelligence platform) since February 2025. Director, Phillips 66 Company (energy infrastructure) from May 2012 to May 2025. Non-executive Chair of the Board, Apache Corporation (Apache) (oil and gas) from May 2015 to September 2022. Senior Executive Advisor at Tudor, Pickering, Holt & Co. LLC (energy investment and merchant banking) from September 2012 to August 2021.			2015

TC Energy Annual Information Form 2025 | 25

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Name and place of residence						Principal occupation during the five preceding years			Director since
Dawn Madahbee Leach Little Current, Ontario Canada						General Manager, Waubetek Business Corporation (Indigenous financial institution) since 1988 and Founder, President and CEO of Indigenous Business International (strategic advisor) since 2016. Director, Peace Hills Trust (financial institution) since 2012, English River First Nation’s Des Nedhe Group (Indigenous business investment) since 2024 and Chairperson of The National Indigenous Economic Development Board (federally appointed advisory board) since 2000. Director, Niobay Metals Inc. (mining) from May 2018 to June 2025.			2024
François L. Poirier Calgary, Alberta Canada						President and CEO since January 2021. Chief Operating Officer (COO) and President, Power and Storage from September 2020 to December 2020. COO and President, Power and Storage and Mexico from January 2020 to September 2020. Executive Vice-President, Corporate Development and Strategy, and President, Power & Storage and Mexico from May 2019 to January 2020. Director, Canadian Imperial Bank of Commerce (chartered bank) since September 2024.			2021
Una Power Vancouver, British Columbia Canada						Corporate director. Director, Teck Resources Limited (Teck) (diversified mining) since April 2017 and Scotiabank (chartered bank) since April 2016.			2019
Mary Pat Salomone Naples, Florida U.S.A.						Corporate director. Director, South Bow Corporation (energy infrastructure) since October 2024, Intertape Polymer Group (manufacturing) from November 2015 to June 2022, and Herc Rentals (equipment rental) from July 2016 to December 2021.			2013
Siim A. Vanaselja Toronto, Ontario Canada						Corporate director. Chair of the Board, TC Energy from May 2017 to December 2023. Director, Power Corporation (financial services) since May 2020, Power Financial Corporation (financial services) since May 2018, RioCan Real Estate Investment Trust (real estate) since May 2017, and Great-West Lifeco Inc. (financial services) since May 2014.			2014
Thierry Vandal Mamaroneck, New York U.S.A.						President, Axium Infrastructure U.S., Inc. (independent infrastructure fund management firm) and Director, Axium Infrastructure Inc. (independent infrastructure fund management firm) since 2015. Director, Royal Bank of Canada (chartered bank) since 2015.			2017
Dheeraj "D" Verma Houston, Texas U.S.A.						Senior Advisor, Quantum Energy Partners (Quantum) (private equity firm) since November 2021. President, Quantum Energy Partners from November 2016 to November 2021. Director, Jagged Peak Energy Inc. (oil and gas) from January 2017 to January 2020.			2022

Cease Trade Orders, Bankruptcies, Penalties or Sanctions

As of the date hereof, except as indicated below, no other director or executive officer of the Company is or was a director
or officer of another company in the past 10 years that:

•was the subject of a cease trade or similar order, or an order denying that company access to any exemption under securities legislation, that was in effect for a period of more than 30 consecutive days

•was involved in an event that resulted in the company being subject to one of the above orders after the director or executive officer no longer held that role with the company, which resulted from an event that occurred while that person was acting
in the capacity as director, chief executive officer or chief financial officer

•while acting in that capacity, or within a year of ceasing to act in that capacity, became bankrupt, made a proposal under any legislation relating to bankruptcy or insolvency or was subject to or instituted any proceedings, arrangement or compromise with creditors or had a receiver, receiver manager or trustee appointed to hold the assets of that company.

In January 2019, PGE filed for bankruptcy under Chapter 11 of the United States Bankruptcy Code as a result of claims arising from fires caused by PGE’s electrical equipment. Following discussions initiated by the PGE board of directors, Mr. Johnson agreed to serve as President and CEO throughout PGE’s bankruptcy process, beginning May 2, 2019, with the understanding that upon PGE’s emergence from bankruptcy he would resign from PGE. On July 1, 2020, PGE emerged from Chapter 11 bankruptcy, upon completing a restructuring process that was confirmed by the United States Bankruptcy Court on June 20, 2020. Mr. Johnson resigned as President and CEO of PGE on June 30, 2020.

Ms. Campbell joined the board of directors of PGE in April 2019, after PGE filed for bankruptcy under Chapter 11 of the United States Bankruptcy Code in January 2019 and prior to its emergence from Chapter 11 bankruptcy in July 2020. Ms. Campbell continues to be a director of PGE.

26 | TC Energy Annual Information Form 2025

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No director or executive officer of the Company has within the past 10 years:

•become bankrupt

•made a proposal under any legislation relating to bankruptcy or insolvency

•become subject to or launched any proceedings, arrangement or compromise with any creditors, or

•had a receiver, receiver manager or trustee appointed to hold any of their assets.

No director or executive officer of the Company has been subject to:

•any penalties or sanctions imposed by a court relating to securities legislation or by a securities regulatory authority
or has entered into a settlement agreement with a securities regulatory authority, or

•any other penalties or sanctions imposed by a court or regulatory body that would likely be considered important
to a reasonable investor in making an investment decision.

BOARD COMMITTEES

TC Energy has four standing committees of the Board: the Audit Committee, the Governance Committee, the Health, Safety, Sustainability and Environment Committee and the Human Resources Committee. As President and CEO of TC Energy, Mr. Poirier is not a member of any Board committees, but is invited to attend committee meetings as required.

The voting members of each of these committees, as of February 12, 2026, are identified below. Information about the Audit Committee can be found in this AIF under the heading Audit Committee.

Director

Audit Committee

Governance Committee

Health, Safety, Sustainability and Environment Committee

Human Resources Committee

Scott Bonham

ü

ü

Cheryl F. Campbell

ü

ü

Michael R. Culbert

ü

ü

William D. Johnson

ü

Chair

Susan C. Jones

ü

ü

John E. Lowe (Chair)

ü

ü

Dawn Madahbee Leach

ü

ü

Una Power

Chair

ü

Mary Pat Salomone

ü

Chair

Siim A. Vanaselja

ü

ü

Thierry Vandal

Chair

ü

Dheeraj "D" Verma

ü

ü

TC Energy Annual Information Form 2025 | 27

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OFFICERS

With the exception of Tina V. Faraca, Patrick C. Muttart, Sean P. O'Donnell and Alisa M. Williams, all of the executive officers and corporate officers of TC Energy reside in Alberta, Canada. Positions and offices held with TC Energy are also held by such person at TCPL. As of the date hereof, the officers of TC Energy, their present positions within TC Energy, unless otherwise stated, and their principal occupations during the five preceding years are as follows:

Executive officers

Name			Present position held			Principal occupation during the five preceding years
François L. Poirier			President and Chief Executive Officer			Prior to January 2021, COO and President, Power and Storage. Prior to September 2020, COO and President, Power and Storage and Mexico. Prior to January 2020, Executive Vice-President, Corporate Development and Strategy, and President, Power & Storage and Mexico.
Dawn E. de Lima			Executive Vice-President, Corporate Services			Prior to December 2020, Chief Shared Services Officer, TransAlta Corporation (electricity service provider).
Anita Dusevic Oliva			Executive Vice-President and General Counsel			Prior to April 1, 2025, Operating Partner, Brookfield Infrastructure (infrastructure). Prior to February 2023, COO, Inter Pipeline Ltd. (Inter Pipeline) (oil and natural gas). Prior to April 2022, Senior Vice President, Corporate Services, Inter Pipeline. Prior to November 2020, Vice President, Legal, Inter Pipeline.
Tina V. Faraca Texas, U.S.A.			Executive Vice-President and Chief Operating Officer, Natural Gas Pipelines			Prior to February 2025, Executive Vice-President and President, U.S. Natural Gas Pipelines. Prior to August 2023, President, U.S. Natural Gas Pipelines. Prior to September 2022, Senior Vice-President, Operations, Projects and Technical Operational Services. Prior to December 2021, Senior Vice-President, Commercial. Prior to April 2020, Chief Commercial Officer, Enable Midstream (oil and natural gas).
Gregory D. Grant			Executive Vice-President and President, Power and Energy Solutions			Prior to February 2025, President, Canadian Natural Gas Pipelines. Prior to January 2022, Senior Vice-President, Commercial. Prior to March 2020, Senior Vice-President, Strategy and Corporate Development.
Patrick C. Muttart Illinois, U.S.A.			Senior Vice-President, External Relations			Prior to December 2022, Senior Vice-President, Stakeholder Relations. Prior to September 2021, Director External Affairs, PMI Global Services (tobacco manufacturing).
Sean P. O'Donnell Texas, U.S.A.			Executive Vice-President, Strategy and Corporate Development and Chief Financial Officer			Prior to February 2025, Executive Vice-President and Chief Financial Officer (CFO). Prior to May 2024, Senior Vice-President, Capital Markets and Corporate Planning. Prior to November 2023, Executive Vice-President and CFO, Mexico Pacific Holdings LLC (energy infrastructure). Prior to November 2023, Operating Partner, Partner and Managing Director, Quantum Capital Group, LLC (formerly known as Quantum Energy Partners, LLC) (private equity firm).

28 | TC Energy Annual Information Form 2025

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Corporate officers

Name			Present position held			Principal occupation during the five preceding years
Jane M. Brindle			Vice-President, Law and Corporate Secretary			Prior to December 2024, Director, Corporate Secretarial and Finance Law.
Yvonne Frame-Zawalykut			Vice-President, Corporate Controller			Prior to February 2023, Vice-President and Assistant Controller. Prior to November 2022, Director, Corporate Planning. Prior to December 2020, Director, Internal Group Finance.
David R. Marchand			Vice-President, Finance and Treasurer			Prior to December 2024, Vice-President, Finance. Prior to November 2024, Director, Finance. Prior to October 2021, Manager, Finance.
Michele L. Waters			Vice-President, Risk Management			Prior to November 2024, Director, Risk and Insurance, Cenovus Energy Inc.
Alisa M. Williams Texas, U.S.A.			Vice-President, Tax			Prior to August 2023, Director, Income Tax, U.S. and Mexico.

CONFLICTS OF INTEREST

Directors and officers of TC Energy and its subsidiaries are required to disclose any existing or potential conflicts in accordance with TC Energy's policies governing directors and officers and in accordance with the CBCA.

COBE covers potential conflicts of interest and requires that all employees, officers, directors and contract workers of TC Energy avoid situations that may result in a potential conflict.

In the event an employee, officer, director or contract worker finds themselves in a potential conflict situation, COBE stipulates that:

•the conflict should be reported; and

•the person should refrain from participation in any decision or action where there is a real or perceived conflict.

COBE also notes that employees and officers of TC Energy may not engage in outside business activities that are in conflict
with or detrimental to the interests of TC Energy. The CEO and the executive leadership team must receive consent from
the Chair of the Governance Committee for all outside business activities.

Under COBE, directors must also declare any material interest that they may have in a material contract or transaction
and recuse themselves from related deliberations and approvals.

In addition to COBE, the directors and corporate officers of TC Energy are required to disclose any related parties and related party transactions in their annual directors and officers questionnaires. These questionnaires assist TC Energy in identifying
and monitoring material related party transactions.

The Governance Committee reviews and approves any material related party transactions prior to the transaction occurring,
and maintains oversight over material related party transactions following such approval.

There were no material conflicts of interests or related party transactions reported by the Board, CEO or the corporate officers, including the executive leadership team, in 2025.

TC Energy Annual Information Form 2025 | 29

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Serving on other boards

The Board believes that it is important for it to be composed of qualified and knowledgeable directors. As a result, due to
the specialized nature of the energy infrastructure business, some of the directors are associated with or sit on the boards
of companies that ship natural gas through our pipeline systems. Transmission services on most of TC Energy’s pipeline systems in Canada and the U.S. are subject to regulation and, accordingly, we generally cannot deny transportation services to a creditworthy shipper. The Governance Committee monitors relationships among directors to ensure that business associations do not affect the Board’s performance.

The Board considers whether directors serving on the boards of, or acting as officers or in another similar capacity, for other entities including public and private companies, Crown corporations and other state-owned entities, and non-profit organizations pose any potential conflict. The Board reviews these relationships annually to determine that they do not interfere with any of our director’s ability to act in our best interests. If a director declares a material interest in any material contract
or material transaction being considered at a meeting, the director is not present during the discussion and does not vote
on the matter.

COBE requires employees to receive consent before accepting a directorship with an entity that is not an affiliate. The CEO
and executive vice-presidents must receive the consent of the Chair of the Governance Committee. All other employees must receive the consent of the Corporate Secretary or their delegate.

Affiliates

The Board oversees relationships between TC Energy and any affiliates to avoid any potential conflicts of interest.

Corporate governance

Our Board and management are committed to the highest standards of ethical conduct and corporate governance.

TC Energy is a public company listed on the TSX and the NYSE, and we recognize and respect rules and regulations in both Canada and the U.S.

Our corporate governance practices comply with the Canadian governance guidelines, which include the governance rules
of the CBCA, TSX and Canadian Securities Administrators, including:

•National Instrument 52-110, Audit Committees,

•National Policy 58-201, Corporate Governance Guidelines, and

•National Instrument 58-101, Disclosure of Corporate Governance Practices.

We also comply with the governance listing standards of the NYSE and the governance rules of the SEC that apply, in each case, to foreign private issuers.

Our governance practices comply with the NYSE standards for U.S. companies in all significant respects. As a non-U.S. company, we are not required to comply with most of the governance listing standards of the NYSE. As a foreign private issuer, however, we must disclose how our governance practices differ from those followed by U.S. companies that are subject to the NYSE standards. Our corporate governance practices do not significantly differ from those required to be followed by U.S. domestic issuers under the NYSE's listing standards. A summary of our governance practices compared to U.S. standards can be found on our website (www.tcenergy.com).

We benchmark our policies and procedures against major North American companies to assess our standards and we adopt best practices as appropriate. Some of our best practices are derived from the NYSE rules and comply with applicable rules adopted
by the SEC to meet the requirements of the Sarbanes-Oxley Act of 2002 and the Dodd-Frank Wall Street Reform and Consumer Protection Act.

30 | TC Energy Annual Information Form 2025

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Audit Committee

The Audit Committee is responsible for assisting the Board in overseeing the integrity of our financial statements and our compliance with legal and regulatory requirements. It is also responsible for overseeing and monitoring the accounting and reporting process and the process, performance and independence of our internal and external auditors. The charter of the
Audit Committee can be found in Schedule B of this AIF.

RELEVANT EDUCATION AND EXPERIENCE OF MEMBERS

The members of the Audit Committee as of February 12, 2026 are Una Power (Chair), Scott Bonham, Cheryl F. Campbell, Michael R. Culbert, Susan C. Jones and Dawn Madahbee Leach.

The Board believes that the composition of the Audit Committee reflects a high level of financial literacy and expertise.
Each member of the Audit Committee has been determined by the Board to be independent and financially literate within the meaning of the definitions under Canadian and U.S. securities laws and the NYSE rules. In addition, the Board has determined that Ms. Power is an Audit Committee Financial Expert as that term is defined under U.S. securities laws. The Board has made
this determination based on the education and breadth and depth of experience of each member of the Audit Committee.
The following is a description of the education and experience, apart from their respective roles as directors of TC Energy,
of each member of the Audit Committee that is relevant to the performance of his or her responsibilities as a member of
the Audit Committee.

Una Power (Chair)

Ms. Power earned a Bachelor of Commerce (Honours) degree from Memorial University and holds Chartered Professional Accountant, Chartered Accountant and Chartered Financial Analyst designations. She serves on the board of directors for Teck where she currently serves as Audit Committee Chair and also serves on the board of directors for Scotiabank, where she previously served as a member and Chair of its Audit Committee. Ms. Power was previously the Chief Financial Officer of Nexen Energy ULC, a former publicly traded oil and gas company that is now a wholly-owned subsidiary of CNOOC Limited, where she held various executive positions with responsibility for financial and risk management, strategic planning, budgeting, business development, energy marketing and trading, information technology and capital investment.

Scott Bonham

Mr. Bonham holds a Bachelor of Science degree in electrical engineering from Queen’s University and a Master of Business Administration from Harvard Business School. He currently serves on the board of directors for Loblaw Companies Limited, where he is a member of the Audit Committee and the Risk and Compliance Committee. He previously served on the board of directors for Scotiabank, where he was a member of the Audit and Conduct Review and Corporate Governance Committees. He has
an extensive background in venture capital and from 2000 to 2015, he was co-founder of GGV Capital. He is also the co-founder
of Intentional Capital Real Estate (Canada) and previously served as a director of Magna.

Cheryl F. Campbell

Ms. Campbell holds a Master of Science degree in finance, with a minor in management, from the University of Colorado, Denver, as well as Bachelor of Science degrees in chemical engineering and business from the University of Colorado, Boulder. She currently serves on the board of directors of PGE, where she is Chair of the Safety & Nuclear Oversight Committee as well
as a member of the Sustainability & Governance Committee. She also serves as the Chair of the board of Summit, as well as serving on the board of JANA Corporation. She previously served as a director and Audit Committee member of National Underground Group and, for 13 years, as Senior Vice President, Gas, with Xcel Energy, Inc.

Michael R. Culbert

Mr. Culbert holds a Bachelor of Science degree in Business Administration from Emmanuel College in Boston, Massachusetts.
He currently serves on the board of directors of ARC and is a member of the Human Resources and Compensation and Safety Reserves and Operational Excellence Committees. He previously served as a director of Precision, Reserve Royalty Income Trust, Enerplus and PETRONAS, and was a member of each of their Audit Committees, as well as the Vice-Chair of PETRONAS. Mr. Culbert was also a director and President of PNW LNG LP and former co-founder, director, President and Chief Executive Officer of Progress Energy Ltd.

TC Energy Annual Information Form 2025 | 31

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Susan C. Jones

Ms. Jones earned a Bachelor of Arts degree in Political Science and Hispanic Studies from the University of Victoria. She also
holds a Bachelor of Laws degree from the University of Ottawa. She earned a Leadership Diploma from the University of Oxford and holds a Director Certificate from Harvard University. Ms. Jones serves as a director of Canadian National Railway Company and is a member of its Audit, Finance and Risk Committee and Chair of its Safety & Environment Committee. Ms. Jones previously served as a director of ARC and was a member of the Audit and Finance Committee of Seven Generations Energy Ltd. prior to
its merger with ARC. She also served as a director of Piedmont. She previously served on the boards and as a member of the Audit Committees of Gibson and Canpotex Limited, where she also served as Chair of the board. Ms. Jones held an executive leadership role at Nutrien Ltd. for 15 years, most recently as Executive Vice-President and Chief Executive Officer of the Potash Business Unit.

Dawn Madahbee Leach

Ms. Madahbee Leach graduated from the University of Waterloo’s Economic Development Program and holds a degree
in Political Science and Law from York and Laurentian Universities. She is the General Manager for the Waubetek Business Development Corporation since she helped create and start the organization in 1988. Waubetek is a leading Indigenous Financial Institution that provides financial services to Indigenous entrepreneurs across Canada. She is also the founder, President and Chief Executive Officer of Indigenous Business International, which assists Indigenous people and companies internationally with various economic sector strategies and project reviews. She is the Chair of the National Indigenous Economic Development Board and has been part of this federally appointed board since 2000, providing advice and guidance to the federal government on issues related to Indigenous economic policies and programming. She also serves on the board of Peace Hills Trust where she is
a member of the Executive, Loans and Trust Committees and is Chair of the Investment Committee. She also previously served as a board member of Niobay Metals Inc.

PRE-APPROVAL POLICIES AND PROCEDURES

TC Energy's Audit Committee maintains a pre-approval policy with respect to permitted non-audit services and audit services. For non-audit service engagements of up to $250,000, approval of the Audit Committee Chair is required, and the Audit Committee is to be informed of the engagement at the next scheduled Audit Committee meeting. For all non-audit service engagements of $250,000 or more, pre-approval of the Audit Committee is required.

To date, all non-audit services have been pre-approved by the Audit Committee in accordance with the pre-approval policy described above.

EXTERNAL AUDITOR SERVICE FEES

The table below shows the services KPMG LLP provided during the last two fiscal years and the fees they invoiced us:

($ millions)			2025			2024
Audit fees
•audit of the annual consolidated financial statements			18.7			19.4
•services related to statutory and regulatory filings or engagements
•review of interim consolidated financial statements and information contained in various prospectuses and other securities offering documents
Audit-related fees			0.1			1.4
•services related to the audit of the financial statements of TC Energy pipeline abandonment trusts and certain post-retirement plans, and certain special purpose audits
Tax fees			1.0			1.5
•Canadian and international tax planning and tax compliance matters, including the review of income tax returns and other tax filings
All other fees			0.4			0.5
•fees for other products and services provided by the auditors and not described above, which included fees related to advice and assistance with ESG services, and French and Spanish translation services
Total fees			20.2			22.8

Note

•2025 total fees are lower than 2024 primarily due to the Spinoff Transaction work included in 2024.

32 | TC Energy Annual Information Form 2025

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Legal proceedings and regulatory actions

Except as described below, there are no legal proceedings in respect of which the Company is or was a party, or in respect
of which any of the Company’s property is or was the subject during the year ended December 31, 2025, nor are there any such proceedings known by the Company to be contemplated, that involve a claim for damages exceeding 10% of the Company’s current assets. In addition, there have not been any (a) penalties or sanctions imposed against the Company by a court relating to securities legislation or by a securities regulatory authority during the year ended December 31, 2025, (b) any other penalties or sanctions imposed by a court or regulatory body against the Company that would likely be considered important to a reasonable investor in making an investment decision, or (c) settlement agreements entered into by the Company before
a court relating to securities legislation or with a securities regulatory authority during the year ended December 31, 2025.

Pacific Atlantic Pipeline Construction Ltd.

CGL 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, reached a mutually acceptable resolution to their disputes in third quarter 2025. The settlement was not an admission of liability by either party and the parties mutually released their respective claims in arbitration.
Details of the arbitration and the settlement are confidential, but did include the retention by CGL LP of the letter of credit
funds drawn in 2024 and the settlement did not have a material impact on the Company's financial statements.

TC Energy Annual Information Form 2025 | 33

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Transfer agent and registrar

TC Energy's transfer agent and registrar is Computershare Investor Services, Inc. with its Canadian transfer facilities in the cities of Calgary, Montréal, Toronto and Vancouver.

Material contracts

TC Energy did not enter into any material contracts outside the ordinary course of business during the year ended December 31, 2025, nor has it entered into any material contracts outside the ordinary course of business prior to the year ended December 31, 2025 which are still in effect as at the date of this AIF.

Interest of experts

KPMG LLP are the auditors of TC Energy and have confirmed with respect to TC Energy that they are independent within the meaning of the relevant rules and related interpretations prescribed by the relevant professional bodies in Canada and any applicable legislation or regulations and also that they are independent accountants with respect to TC Energy under all relevant U.S. professional and regulatory standards.

Additional information

1.Additional information in relation to TC Energy may be found under TC Energy's profile on SEDAR+ (www.sedarplus.ca).

2.Additional information including directors' and officers' remuneration and indebtedness, principal holders of TC Energy's securities and securities authorized for issuance under equity compensation plans (all where applicable), is contained in TC Energy's Management Information Circular for its most recent annual meeting of shareholders that involved the election of directors and can be obtained upon request from the Corporate Secretary of TC Energy.

3.Additional financial information is provided in TC Energy's audited consolidated financial statements and MD&A for its most recently completed financial year.

34 | TC Energy Annual Information Form 2025

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Glossary

Capitalized terms used throughout this AIF but not otherwise defined herein have the meanings given to such terms in the MD&A and are incorporated by reference into this AIF.

Units of measure
Bcf						Billion cubic feet
hp						Horsepower
km						Kilometres
MMcf/d						Million cubic feet per day
MW						Megawatt(s)
MWh						Megawatt hours
TJ/d						Terajoules per day
General terms and terms related to our operations
B.C.						British Columbia
ESG						Environmental, social and governance
FID						Final investment decision
force majeure						Unforeseeable circumstances that prevent a party to a contract from fulfilling it
GHG						Greenhouse gas
investment base						Includes rate base as well as assets under construction
LNG						Liquefied natural gas
MCR						Major component replacement
rate base						Average assets in service, working capital and deferred amounts used in setting of regulated rates
WCSB						Western Canada Sedimentary Basin
Year End						Year ended December 31, 2025

Accounting terms
AFUDC						Allowance for funds used during construction
GAAP						U.S. generally accepted accounting principles
ROE						Return on common equity
Government and regulatory bodies terms
AER						Alberta Energy Regulator
BCEAO						Environmental Assessment Office (British Columbia)
BCER						B.C. Energy Regulator (formerly B.C. Oil and Gas Commission)
CBCA						Canada Business Corporations Act
CER						Canada Energy Regulator (formerly the National Energy Board (Canada))
CFE						Comisión Federal de Electricidad (Mexico)
CNE						Comisión Nacional de Energía (Mexico)
DOS						U.S. Department of State
FERC						Federal Energy Regulatory Commission (U.S.)
IESO						Independent Electricity System Operator (Ontario)
NYSE						New York Stock Exchange
PHMSA						Pipeline and Hazardous Materials Safety and Administration
SEC						U.S. Securities and Exchange Commission
TSX						Toronto Stock Exchange

TC Energy Annual Information Form 2025 | 35

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Schedule A

METRIC CONVERSION TABLE

The conversion factors set out below are approximate factors. To convert from Metric to Imperial multiply by the factor indicated. To convert from Imperial to Metric divide by the factor indicated.

Metric			Imperial			Factor
Kilometres			Miles			0.62
Millimetres			Inches			0.04
Gigajoules			Million British thermal units			0.95
Cubic metres*			Cubic feet			35.3
Kilopascals			Pounds per square inch			0.15
Degrees Celsius			Degrees Fahrenheit			to convert to Fahrenheit multiply by 1.8, then add 32 degrees; to convert to Celsius subtract 32 degrees, then divide by 1.8

*The conversion is based on natural gas at a base pressure of 101.325 kilopascals and at a base temperature of 15 degrees Celsius.

36 | TC Energy Annual Information Form 2025

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Schedule B

CHARTER OF THE AUDIT COMMITTEE

1.    PURPOSE

The Audit Committee shall assist the Board of Directors (the Board) in overseeing and monitoring, among other things, the:

•Company’s financial accounting and reporting process;

•integrity of the financial statements;

•Company’s internal control over financial reporting;

•external financial audit process;

•compliance by the Company with legal and regulatory requirements; and

•independence and performance of the Company’s internal and external auditor.

To fulfill its purpose, the Audit Committee has been delegated certain authorities by the Board that it may exercise on behalf of the Board.

2.    ROLES AND RESPONSIBILITIES

I.    Appointment of the Company’s External Auditor

Subject to confirmation by the external auditor of their compliance with Canadian and U.S. regulatory registration requirements, the Audit Committee shall recommend to the Board the appointment of the external auditor, such appointment to be confirmed by the Company’s shareholders at each annual meeting. The Audit Committee shall also recommend to the Board the compensation to be paid to the external auditor for audit services. The Audit Committee shall also be directly responsible for the oversight of the work of the external auditor (including resolution of disagreements between management and the external auditor regarding financial reporting) for the purpose of preparing or issuing an audit report or related work. The external auditor shall report directly to the Audit Committee.

The Audit Committee shall review and approve the audit plan of the external auditor. The Audit Committee shall also receive periodic reports from the external auditor regarding the auditor’s independence, discuss such reports with the auditor, consider whether the provision of non‑audit services is compatible with maintaining the auditor’s independence and take appropriate action to satisfy itself of the independence of the external auditor. In addition, to further satisfy itself of audit quality and the independence of the external auditor, the Audit Committee shall undertake a Periodic Comprehensive Review of the External Auditor at least once every five years.

II.    Oversight in Respect of Financial Disclosure

The Audit Committee shall, to the extent it deems it necessary or appropriate:

(a)    review, discuss with management and the external auditor and recommend to the Board for approval, the Company’s audited annual consolidated financial statements, annual information form, management’s discussion and analysis (MD&A), all financial information in prospectuses and other offering memoranda, financial statements required by securities regulators, all prospectuses and all documents which may be incorporated by reference into a prospectus, including, without limitation, the annual management information circular, but excluding any pricing or prospectus supplement relating to the issuance of debt securities of the Company;

(b)    review, discuss with management and the external auditor and approve, the release to the public of the Company’s interim reports, including the consolidated financial statements, MD&A and news releases on quarterly financial results;

(c)    review and discuss with management and the external auditor the use of non-GAAP information and the applicable reconciliation;

TC Energy Annual Information Form 2025 | 37

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(d)    review and discuss with management any financial outlook or future-oriented financial information disclosure in advance of its public release; provided, however, that such discussion may be done generally (consisting of discussing the types of information to be disclosed and the types of presentations to be made). The Audit Committee need not discuss in advance each instance in which the Company may provide financial projections or presentations to credit rating agencies;

(e)    review with management and the external auditor major issues regarding accounting policies and auditing practices, including any significant changes in the Company’s selection or application of accounting policies, as well as major issues as to the adequacy of the Company’s internal controls and any special audit steps adopted in light of material control deficiencies that could significantly affect the Company’s financial statements;

(f)    review and discuss quarterly findings reports from the external auditor on:

(i)    all critical accounting policies and practices to be used;

(ii)    all alternative treatments of financial information within generally accepted accounting principles that have been discussed with management, ramifications of the use of such alternative disclosures and treatments, and the treatment preferred by the external auditor;

(iii)    other material written communications between the external auditor and management, such as any management letter or schedule of unadjusted differences;

(g)    review with management and the external auditor the effect of regulatory and accounting developments on the Company’s financial statements;

(h)    review with management and the external auditor the effect of any off-balance sheet structures on the Company’s financial statements;

(i)    review with management, the external auditor and, if necessary, legal counsel, any litigation, claim or contingency, including arbitration and tax assessments, that could have a material effect upon the financial position of the Company, and the manner in which these matters have been disclosed in the financial statements;

(j)    review disclosures made to the Audit Committee by the Company’s Chief Executive Officer (CEO) and Chief Financial Officer (CFO) during their certification process for the periodic reports filed with securities regulators about any significant deficiencies in the design or operation of internal controls or material weaknesses therein and any fraud involving management or other employees who have a significant role in the Company’s internal controls;

(k)    discuss with management the Company’s material financial risk exposures and the steps management has taken to monitor and control such exposures, including the Company’s risk assessment and risk management policies;

III.    Oversight in Respect of Legal and Regulatory Matters

(a)    review with the Company’s General Counsel legal matters that may have a material impact on the financial statements, the Company’s compliance policies and any material reports or inquiries received from regulators or governmental agencies;

IV.    Oversight in Respect of Internal Audit

(a)    review and approve the audit plans of the internal auditor of the Company including the degree of coordination between such plans and those of the external auditor and the extent to which the planned audit scope can be relied upon to detect weaknesses in internal control, fraud or other illegal acts;

(b)    review the significant findings prepared by the internal audit department and recommendations issued by it or by any external party relating to internal audit issues, together with management’s response thereto;

(c)    review compliance with the Company’s policies and avoidance of conflicts of interest;

(d)    review the report prepared by the internal auditor on officers’ expenses and aircraft usage;

38 | TC Energy Annual Information Form 2025

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(e)    review the adequacy of the resources of the internal auditor to ensure the objectivity and independence of the internal audit function, including

(i)    receive reports from the internal audit department on its audit process with subsidiaries and affiliates; and

(ii)    review the Internal Audit Charter and as needed, approve any substantive changes.

(f)    ensure the internal auditor has access to the Chair of the Audit Committee, the Board and the CEO and meet separately with the internal auditor to review with him or her any problems or difficulties he or she may have encountered and specifically:

(i)    any difficulties which were encountered in the course of the audit work, including restrictions on the scope of activities or access to required information, and any disagreements with management;

(ii)    any changes required in the planned scope of the internal audit;

(iii)    the internal audit department responsibilities, budget and staffing;

and to report to the Board on such meetings;

V.    Oversight in Respect of the External Auditor

(a)    review any letter, report or other communication from the external auditor in respect of any identified weakness in internal control or unadjusted difference and management’s response and follow‑up, inquire regularly of management and the external auditor of any significant issues between them and how they have been resolved, and intervene in the resolution if required;

(b)    receive and review annually the external auditor’s formal written statement of independence delineating all relationships between itself and the Company;

(c)    meet separately with the external auditor to review any problems or difficulties the external auditor may have encountered and specifically:

(i)    any difficulties which were encountered in the course of the audit work, including any restrictions on the scope of activities or access to required information, and any disagreements with management;

(ii)    any changes required in the planned scope of the audit;

and to report to the Board on such meetings;

(d)    meet with the external auditor prior to the audit to review the planning and staffing of the audit;

(e)    receive and review annually the external auditor's written report on their own internal quality control procedures; any material issues raised by the most recent internal quality control review, or peer review, of the external auditor, or by any inquiry or investigation by governmental or professional authorities, within the preceding five years, and any steps taken to deal with such issues;

(f)    review and evaluate the external auditor, including the lead partner of the external auditor team;

(g)    ensure the rotation of the lead (or coordinating) audit partner having primary responsibility for the audit and the audit partner responsible for reviewing the audit as required by law, but at least every five years;

VI.    Oversight in Respect of Audit and Non‑Audit Services

(a)    pre-approve all audit services (which may entail providing comfort letters in connection with securities underwritings) and all permitted non‑audit services, other than non‑audit services where:

(i)    the aggregate amount of all such non‑audit services provided to the Company that were not pre-approved constitutes not more than five percent of the total fees paid by the Company and its subsidiaries to the external auditor during the fiscal year in which the non‑audit services are provided;

(ii)    such services were not recognized by the Company at the time of the engagement to be non‑audit services;

TC Energy Annual Information Form 2025 | 39

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(iii)    such services are promptly brought to the attention of the Audit Committee and approved, prior to the completion of the audit, by the Audit Committee or by one or more members of the Audit Committee to whom authority to grant such approvals has been delegated by the Audit Committee;

(b)    approval by the Audit Committee of a non‑audit service to be performed by the external auditor shall be disclosed as required under securities laws and regulations;

(c)    the Audit Committee may delegate to one or more designated members of the Audit Committee the authority to grant pre-approvals required by this subsection. The decisions of any member to whom authority is delegated to pre-approve an activity shall be presented to the Audit Committee at its first scheduled meeting following such pre-approval;

(d)    if the Audit Committee approves an audit service within the scope of the engagement of the external auditor, such audit service shall be deemed to have been pre-approved for purposes of this subsection;

VII.    Oversight in Respect of Certain Policies

(a)    review and recommend to the Board for approval the implementation of, and significant amendments to, policies and program initiatives deemed advisable by management or the Audit Committee with respect to the Company’s code of business ethics (COBE), risk management and financial reporting policies;

(b)    obtain reports from management, the Company’s senior internal auditing executive and the external auditor and report to the Board on the status and adequacy of the Company’s efforts to ensure its businesses are conducted and its facilities are operated in an ethical, legally compliant and socially responsible manner, in accordance with the Company’s COBE;

(c)    establish a non‑traceable, confidential and anonymous system by which callers may ask for advice or report any ethical or financial concern, ensure that procedures for the receipt, retention and treatment of complaints in respect of accounting, internal controls and auditing matters are in place, and receive reports on such matters as necessary;

(d)    annually review and assess the adequacy of the Company’s public disclosure policy;

(e)    review and approve the Company’s hiring policy for partners, employees and former partners and employees of the present and former external auditor (recognizing the Sarbanes-Oxley Act of 2002 does not permit the CEO, controller, CFO or chief accounting officer to have participated in the Company’s audit as an employee of the external auditor during the preceding one-year period) and monitor the Company’s adherence to the policy;

VIII.    Oversight in Respect of Financial Aspects of the Company’s Canadian Pension Plans (the Company’s pension plans), specifically:

(a)review and approve as needed the Statement of Investment Beliefs for the Company’s pension plans;

(b)delegate the ongoing administration and management of the financial aspects of the Canadian pension plans to the Pension Committee comprised of members of the Company’s management team appointed by the Human Resources Committee, in accordance with the Pension Committee Charter, which terms shall be approved by both the Audit Committee and the Human Resources Committee, and the terms of the Statement of Investment Beliefs;

(c)monitor the financial management activities of the Pension Committee and receive updates at least annually from the Pension Committee on the investment of the Plan assets to ensure compliance with the Statement of Investment Beliefs;

(d)    provide advice to the Human Resources Committee on any proposed changes in the Company’s pension plans in respect of any significant effect such changes may have on pension financial matters;

(e)    review and consider financial and investment reports and the funded status relating to the Company’s pension plans and recommend to the Board on pension contributions;

40 | TC Energy Annual Information Form 2025

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(f)    receive, review and report to the Board on the actuarial valuation and funding requirements for the Company’s pension plans;

(g)    approve the initial selection or change of actuary for the Company’s pension plans;

(h)    approve the appointment or termination of the pension plans’ auditor;

IX.    U.S. Stock Plans

(a)    review and approve the engagement and related fees of the auditor for any plan of a U.S. subsidiary that offers Company stock to employees as an investment option under the plan;

X.    Oversight in Respect of Internal Administration

(a)    review annually the reports of the Company’s representatives on certain audit committees of subsidiaries and affiliates of the Company and any significant issues and auditor recommendations concerning such subsidiaries and affiliates;

(b)    oversee succession planning for the senior management in finance, treasury, tax, risk, internal audit and the controllers’ group;

XI.    Information Security

(a)review quarterly, the report of the Chief Information Officer (or such other appropriate Company representative) on information security controls, education and awareness.

XII.    Oversight Function

While the Audit Committee has the responsibilities and powers set forth in this Charter, it is not the duty of the Audit Committee to plan or conduct audits or to determine that the Company’s financial statements and disclosures are complete and accurate or are in accordance with generally accepted accounting principles and applicable rules and regulations. These are the responsibilities of management and the external auditor. The Audit Committee, its Chair and any of its members who have accounting or related financial management experience or expertise, are members of the Board, appointed to the Audit Committee to provide broad oversight of the financial disclosure, financial risk and control related activities of the Company, and are specifically not accountable nor responsible for the day to day operation of such activities. Although designation of a member or members as an “audit committee financial expert” is based on that individual’s education and experience, which that individual will bring to bear in carrying out his or her duties on the Audit Committee, designation as an “audit committee financial expert” does not impose on such person any duties, obligations or liability that are greater than the duties, obligations and liability imposed on such person as a member of the Audit Committee and Board in the absence of such designation. Rather, the role of any audit committee financial expert, like the role of all Audit Committee members, is to oversee the process and not to certify or guarantee the internal or external audit of the Company’s financial information or public disclosure.

3.    COMPOSITION OF AUDIT COMMITTEE

The Audit Committee shall consist of three or more directors, a majority of whom are resident Canadians (as defined in the Canada Business Corporations Act), and all of whom are unrelated and/or independent for the purposes of applicable Canadian and United States securities law and applicable rules of any stock exchange on which the Company's securities are listed. Each member of the Audit Committee shall be financially literate and at least one member shall have accounting or related financial management expertise (as those terms are defined from time to time under the requirements or guidelines for audit committee service under securities laws and the applicable rules of any stock exchange on which the Company’s securities are listed for trading or, if it is not so defined, as that term is interpreted by the Board in its business judgment).

4.    APPOINTMENT OF AUDIT COMMITTEE MEMBERS

The members of the Audit Committee shall be appointed by the Board from time to time on the recommendation of the Governance Committee and shall hold office until the next annual meeting of shareholders or until their successors are earlier appointed or until they cease to be directors of the Company.

TC Energy Annual Information Form 2025 | 41

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5.    VACANCIES

Where a vacancy occurs at any time in the membership of the Audit Committee, it may be filled by the Board on the recommendation of the Governance Committee.

6.    AUDIT COMMITTEE CHAIR

The Board shall appoint a Chair of the Audit Committee who shall:

(a)    review and approve the agenda for each meeting of the Audit Committee and, as appropriate, consult with members of management;

(b)    preside over meetings of the Audit Committee;

(c)    make suggestions and provide feedback from the Audit Committee to management regarding information that is or should be provided to the Audit Committee;

(d)    report to the Board on the activities of the Audit Committee relative to its recommendations, resolutions, actions and concerns; and

(e)    meet as necessary with the internal and external auditor.

7.    ABSENCE OF AUDIT COMMITTEE CHAIR

If the Chair of the Audit Committee is not present at any meeting of the Audit Committee, one of the other members of the Audit Committee present at the meeting shall be chosen by the Audit Committee to preside at the meeting.

8.    SECRETARY OF AUDIT COMMITTEE

The Corporate Secretary shall act as Secretary to the Audit Committee.

9.    MEETINGS

The Chair, or any two members of the Audit Committee, or the internal auditor, or the external auditor, may call a meeting of the Audit Committee. The Audit Committee shall meet at least quarterly. The Audit Committee shall meet periodically with management, the internal auditor and the external auditor in separate executive sessions.

10.    QUORUM

A majority of the members of the Audit Committee, present in person or by telephone or other telecommunication device that permit all persons participating in the meeting to speak to each other, shall constitute a quorum.

11.    NOTICE OF MEETINGS

Notice of the time and place of every meeting shall be given in writing, facsimile communication or by other electronic means to each member of the Audit Committee at least 24 hours prior to the time fixed for such meeting; provided, however, that a member may in any manner waive a notice of a meeting. Attendance of a member at a meeting is a waiver of notice of the meeting, except where a member attends a meeting for the express purpose of objecting to the transaction of any business on the grounds that the meeting is not lawfully called.

12.    ATTENDANCE OF COMPANY OFFICERS AND EMPLOYEES AT MEETING

At the invitation of the Chair of the Audit Committee, one or more officers or employees of the Company may attend any meeting of the Audit Committee.

13.    PROCEDURE, RECORDS AND REPORTING

The Audit Committee shall fix its own procedure at meetings, keep records of its proceedings and report to the Board when the Audit Committee may deem appropriate but not later than the next meeting of the Board.

14.    REVIEW OF CHARTER AND EVALUATION OF AUDIT COMMITTEE

The Audit Committee shall review its Charter annually or otherwise, as it deems appropriate and, if necessary, propose changes to the Governance Committee and the Board. The Audit Committee shall annually review the Audit Committee’s own performance.

42 | TC Energy Annual Information Form 2025

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15.    OUTSIDE EXPERTS AND ADVISORS

The Audit Committee is authorized, when deemed necessary or desirable, to retain and set and pay the compensation for independent counsel, outside experts and other advisors, at the Company’s expense, to advise the Audit Committee or its members independently on any matter.

16.    RELIANCE

Absent actual knowledge to the contrary (which shall be promptly reported to the Board), each member of the Audit Committee shall be entitled to rely on (i) the integrity of those persons or organizations within and outside the Company from which it receives information, (ii) the accuracy of the financial and other information provided to the Audit Committee by such persons or organizations and (iii) representations made by management and the external auditor, as to any information technology, internal audit and other non-audit services provided by the external auditor to the Company and its subsidiaries.

TC Energy Annual Information Form 2025 | 43

EXHIBIT 13.2

Management's discussion and analysis

February 12, 2026

This management's discussion and analysis (MD&A) contains information to help the reader make investment decisions about TC Energy Corporation (TC Energy). It discusses our business, operations, financial position, risks and other factors for the year ended December 31, 2025.

This MD&A should also be read in conjunction with our December 31, 2025 audited Consolidated financial statements and notes for the same period, which have been prepared in accordance with U.S. GAAP.

Contents

ABOUT THIS DOCUMENT						10
ABOUT OUR BUSINESS						12
			•  Our core businesses			13
			•  Our strategy			15
			•  2025 Financial highlights			17
			•Non-GAAP measures			22
			•Supplementary financial measure			29
			•  Outlook			29
			•  Capital program			30
NATURAL GAS PIPELINES BUSINESS						33
CANADIAN NATURAL GAS PIPELINES						42
U.S. NATURAL GAS PIPELINES						46
MEXICO NATURAL GAS PIPELINES						50
POWER AND ENERGY SOLUTIONS						55
CORPORATE						66
FOREIGN EXCHANGE						72
FINANCIAL CONDITION						74
DISCONTINUED OPERATIONS						88
			•  Non-GAAP measures			89
OTHER INFORMATION						94
			•  Risk oversight and enterprise risk management			94
			•  Controls and procedures			109
			•  Critical accounting estimates			110
			•  Financial instruments			112
			•  Related party transactions			114
			•  Accounting changes			114
			•  Quarterly results			115
GLOSSARY						128

TC Energy Management's discussion and analysis 2025 | 9

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About this document

Throughout this MD&A, the terms we, us, our and TC Energy mean TC Energy Corporation and its subsidiaries. Abbreviations and acronyms that are not defined in the document are defined in the glossary on page 128. All information is as of     February 12, 2026 and all amounts are in Canadian dollars, unless noted otherwise.

On October 1, 2024, TC Energy completed the spinoff of its Liquids Pipelines business into a new public company, South Bow Corporation (South Bow)(the Spinoff Transaction). Upon completion of the Spinoff Transaction, the Liquids Pipelines business was accounted for as a discontinued operation. To allow for a meaningful comparison, discussions throughout this MD&A are based on continuing operations unless otherwise noted. Refer to Note 4, Discontinued operations, of our 2025 Consolidated financial statements for additional information.

FORWARD-LOOKING INFORMATION

We disclose forward-looking information to help the reader understand management's assessment of our future plans and financial outlook and our future prospects overall.

Statements that are forward looking are based on certain assumptions and on what we know and expect today and generally include words like anticipate, expect, believe, may, will, should, estimate or other similar words.

Forward-looking statements in this MD&A include information about the following, among other things:

•our financial and operational performance, including the performance of our subsidiaries

•expectations about strategies and goals for growth and expansion, including acquisitions

•expected cash flows and future financing options available along with portfolio management

•expectations regarding the size, structure, timing, conditions and outcome of ongoing and future transactions

•expected dividend growth

•expected access to and cost of capital

•expected energy demand levels

•expected costs and schedules for planned projects, including projects under construction and in development

•expected capital expenditures, contractual obligations, commitments and contingent liabilities, including environmental remediation costs

•expected regulatory processes and outcomes

•expected outcomes with respect to legal proceedings, including arbitration and insurance claims

•expected impact of future tax and accounting changes

•commitments and targets contained in our Report on Sustainability, including statements related to our GHG emissions reduction targets, such as our methane emissions intensity target

•expected industry, market and economic conditions, and ongoing trade negotiations, including their impact on our customers and suppliers.

Forward-looking statements do not guarantee future performance. Actual events and results could be significantly different because of assumptions, risks or uncertainties related to our business or events that happen after the date of this MD&A.

10 | TC Energy Management's discussion and analysis 2025

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Our forward-looking information is based on the following key assumptions and subject to the following risks and uncertainties:

Assumptions

•realization of expected impacts from acquisitions and divestitures

•regulatory decisions and outcomes

•planned and unplanned outages and the utilization of our pipelines, power and storage assets

•integrity and reliability of our assets

•anticipated construction costs, schedules and completion dates

•access to capital markets, including portfolio management

•expected industry, market and economic conditions, including the impact of these on our customers and suppliers

•inflation rates, commodity and labour prices

•interest, tax and foreign exchange rates

•nature and scope of hedging.

Risks and uncertainties

•realization of expected impacts from acquisitions and divestitures

•our ability to successfully implement our strategic priorities, and whether they will yield the expected benefits

•our ability to implement a capital allocation strategy aligned with maximizing shareholder value

•operating performance of our pipelines, power generation and storage assets

•amount of capacity sold and rates achieved in our pipeline businesses

•amount of capacity payments and revenues from power generation assets due to plant availability

•production levels within supply basins

•construction and completion of capital projects

•cost, availability of, and inflationary pressures on, labour, equipment and materials

•availability and market prices of commodities

•access to capital markets on competitive terms

•interest, tax and foreign exchange rates

•performance and credit risk of our counterparties

•regulatory decisions and outcomes of legal proceedings, including arbitration and insurance claims

•our ability to effectively anticipate and assess changes to government policies and regulations, including those related
to the environment

•our ability to realize the value of tangible assets and contractual recoveries

•competition in the businesses in which we operate

•unexpected or unusual weather

•acts of civil disobedience

•cybersecurity and technological developments

•sustainability-related risks including climate-related risks and the impact of energy transition on our business

•economic and political conditions, and ongoing trade negotiations in North America, as well as globally

•global health crises, such as pandemics and epidemics, and the impacts related thereto.

You can read more about these factors and others in this MD&A and in other reports we have filed with Canadian securities regulators and the SEC.

As actual results could vary significantly from the forward-looking information, you should not put undue reliance on forward-looking information and should not use future-oriented information or financial outlooks for anything other than their intended purpose. We do not update our forward-looking statements due to new information or future events unless we are required to by law.

FOR MORE INFORMATION

You can find more information about TC Energy in our Annual Information Form and other disclosure documents, which are available on SEDAR+ (www.sedarplus.ca).

TC Energy Management's discussion and analysis 2025 | 11

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About our business

With over 70 years of experience, TC Energy is a leader in the responsible development and reliable operation of North American energy infrastructure, including natural gas pipelines, power generation and natural gas storage facilities.

12 | TC Energy Management's discussion and analysis 2025

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OUR CORE BUSINESSES

We operate in two core businesses – Natural Gas Pipelines and Power and Energy Solutions. In order to provide information that is aligned with how management decisions about our businesses are made and how performance of our businesses is assessed, our results are reflected in four operating segments: Canadian Natural Gas Pipelines, U.S. Natural Gas Pipelines, Mexico Natural Gas Pipelines and Power and Energy Solutions. We also have a Corporate segment consisting of corporate and administrative functions that provide governance, financing and other support to TC Energy's business segments.

TC Energy completed the Spinoff Transaction on October 1, 2024 and subsequently accounted for the Liquids Pipelines business as a discontinued operation. Refer to the Discontinued operations section on page 88 for additional information.

Year at-a-glance

at December 31
(millions of $)						2025						2024
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

year ended December 31
(millions of $)						2025						2024¹
Total revenues from continuing operations by segment
Canadian Natural Gas Pipelines						5,785						5,600
U.S. Natural Gas Pipelines						7,145						6,339
Mexico Natural Gas Pipelines						1,450						870
Power and Energy Solutions						845						954
Corporate						14						8
						15,239						13,771

1    Excludes revenues of $2,217 million related to discontinued operations, which represents nine months of Liquids Pipelines earnings in 2024.

TC Energy Management's discussion and analysis 2025 | 13

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year ended December 31
(millions of $)						2025						2024¹
Comparable EBITDA from continuing operations by segment2
Canadian Natural Gas Pipelines						3,687						3,388
U.S. Natural Gas Pipelines						4,906						4,511
Mexico Natural Gas Pipelines						1,365						999
Power and Energy Solutions						1,008						1,214
Corporate						(14)						(63)
						10,952						10,049

1    Excludes Comparable EBITDA from discontinued operations of $1,145 million, which represents nine months of Liquids Pipelines earnings in 2024.

2    Comparable EBITDA is a non-GAAP measure and does not have any standardized meaning as prescribed by U.S. GAAP and therefore may not be comparable to similar measures presented by other companies. The most directly comparable GAAP measure is segmented earnings (losses). Refer to the Financial results sections for each business segment for a reconciliation to comparable EBITDA as well as the About our business - Non-GAAP measures section for additional information.

14 | TC Energy Management's discussion and analysis 2025

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OUR STRATEGY

Our vision is to be the trusted leader in North America’s energy infrastructure, committed to excellence in safety, performance and stakeholder relationships. Our mission is to safely and efficiently move, generate and store the critical energy that North America and the world rely on. Our value proposition: to deliver solid growth with low risk and repeatable performance, year after year.

Our business consists of natural gas transportation and storage, as well as power generation assets:

•we deliver natural gas to Canada, the U.S. and Mexico, including to export terminals that ship LNG globally

•we generate electricity in Canada and the U.S., primarily from nuclear energy, but also from natural gas, wind and solar assets

•we store natural gas in Canada and the U.S. through regulated and non-regulated businesses.

These long-life infrastructure assets are anchored by our conservative risk preferences and are generally supported by long-term commercial arrangements and/or rate regulation. We believe that our assets will generate predictable and sustainable cash flows and earnings, providing the cornerstones of our low-risk value proposition. Our long-term strategy is driven by the following key beliefs:

•natural gas will continue to play a pivotal role in North America's energy future and support global GHG emissions reduction

•the need for reliable, on-demand energy sources will continue to grow

•energy assets will become increasingly valuable in a world with growing energy demand and existing challenges in developing new infrastructure.

Allocation of comparable EBITDA from continuing operations1

year ended December 31						2025						2024
Comparable EBITDA from continuing operations by segment2
Canadian Natural Gas Pipelines						34		%				33		%
U.S. Natural Gas Pipelines						45		%				45		%
Mexico Natural Gas Pipelines						12		%				10		%
Power and Energy Solutions						9		%				12		%
						100		%				100		%

1    Refer to the Financial highlights section for an allocation of segmented earnings by business segment.

2    Excludes losses from Corporate comparable EBITDA from continuing operations of $14 million and $63 million for the years ended December 31, 2025 and 2024, respectively.

Our asset mix will continue to evolve with the North American energy mix. We anticipate the following trends in capital allocation over the next several years:

•Natural Gas Pipelines will continue to attract capital to meet growing customer demand, driven by coal-to-gas conversion, LNG exports and data centre buildouts

•Power and Energy Solutions' capital will primarily be allocated to extending the life and increasing the capacity of the nuclear business. We will make measured investment in emerging technologies to develop capabilities that are complementary to our Natural Gas Pipelines business, without taking significant commodity price risk, volumetric risk or utilizing unproven technologies

•additional discretionary investment will fund select high-grade opportunities in our development projects portfolio and incremental opportunities around existing assets across our businesses.

TC Energy Management's discussion and analysis 2025 | 15

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Key components of our strategy

Maximize the value of our assets through safety and operational excellence

Maintaining safe and reliable operations by maximizing asset availability and integrity while minimizing environmental impacts remains the foundation of our business. Our extensive natural gas pipeline network connects long-life, low-cost supply basins with premium North American and export markets, generating predictable and sustainable cash flows and earnings, while our power and non-regulated storage assets, primarily under long-term contracts, provide stable returns. We continually seek to enhance and protect asset value through operational, commercial and marketing initiatives.

Execute our selective portfolio of growth projects

Safety, executability, profitability, and reliability are fundamental to our investments, which focus on developing high-quality, long-life assets largely underpinned by long-term contracts or rate regulation. Leveraging our incumbent positions in regions with growing natural gas and power demand, we manage costs and construction risk in a disciplined manner to maximize capital efficiency and shareholder returns. We also look to advance select lower-carbon growth initiatives in emerging sub-sectors where technology is proven, risks and returns are acceptable and we can build a strong competitive position.

Ensure financial strength and agility

Disciplined capital allocation supports our ability to maximize asset value over the short, medium and long term while improving cost competitiveness, extending asset life and remaining within annual net capital spend targets. We assess opportunities to develop or acquire complementary energy infrastructure that protects and grows our business, enhances resilience under a changing energy mix and diversifies access to attractive supply and market regions within our risk preferences. Supported by our high-quality, diversified portfolio and core competencies in safety, operational excellence, and project execution, we aim to deliver predictable, low-risk cash flows and shareholder value across various economic cycles and energy transition scenarios.

Our risk preferences

The following is an overview of our risk philosophy:

•financial strength and flexibility: rely on internally generated cash flows, existing debt capacity, partnerships and portfolio management to finance new initiatives

•known and acceptable project risks: select investments with known, acceptable and manageable project execution risk, including stakeholder considerations, partnership agreements, human capital and capability constraints

•business underpinned by strong fundamentals and policy support: invest in assets with stable cash flows supported by strong underlying macroeconomic fundamentals, conducive policy and regulations and/or long-term contracts with creditworthy counterparties

•manage credit metrics to ensure strong investment-grade ratings: investment-grade ratings are an important competitive advantage and we manage leverage to ensure that strong access to capital on competitive terms is maintained while balancing the interests of equity and fixed income investors

•prudent management of counterparty exposure: limit counterparty concentration and sovereign risk; seek diversification and solid commercial arrangements underpinned by strong fundamentals.

16 | TC Energy Management's discussion and analysis 2025

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2025 FINANCIAL HIGHLIGHTS

We use certain financial measures that do not have a standardized meaning under GAAP because we believe they improve our ability to compare results between reporting periods and enhance understanding of our operating performance. Known as non-GAAP measures, they may not be comparable to similar measures provided by other companies.

Comparable EBITDA, comparable earnings and comparable earnings per common share from continuing and discontinued operations and comparable funds generated from operations are all non-GAAP measures. Refer to page 22 for more information about the non-GAAP measures we use, as well as the Financial results section in each business segment and Discontinued operations section for reconciliations to the most directly comparable GAAP measures.

As discussed on page 10 of the About this document section, TC Energy completed the Spinoff Transaction on October 1, 2024. To allow for a meaningful comparison, discussions throughout this MD&A are based on continuing operations unless otherwise noted. Refer to the Discontinued operations section for additional information.

year ended December 31
(millions of $, except per share amounts)						2025						2024						2023
Income
Revenues						15,239						13,771						13,267
Net income (loss) attributable to common shares						3,400						4,594						2,829
from continuing operations						3,612						4,199						2,217
from discontinued operations1						(212)						395						612
Net income (loss) per common share – basic						$3.27						$4.43						$2.75
from continuing operations						$3.47						$4.05						$2.15
from discontinued operations1						($0.20)						$0.38						$0.60
Comparable EBITDA2						10,952						11,194						10,988
from continuing operations						10,952						10,049						9,472
from discontinued operations1						—						1,145						1,516
Comparable earnings2						3,654						4,430						4,652
from continuing operations						3,654						3,865						3,896
from discontinued operations1						—						565						756
Comparable earnings per common share2						$3.51						$4.27						$4.52
from continuing operations						$3.51						$3.73						$3.78
from discontinued operations1						—						$0.54						$0.74

1Represents nine months of Liquids Pipelines earnings in 2024 and a full year of earnings in 2023. Refer to the Discontinued operations section for additional information.

2Additional information on the most directly comparable GAAP measure can be found on page 22.

TC Energy Management's discussion and analysis 2025 | 17

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year ended December 31
(millions of $)						2025						2024						2023
Cash flows1
Net cash provided by operations2						7,346						7,696						7,268
Comparable funds generated from operations2,3						7,996						7,890						7,980
Capital spending4						6,337						7,904						12,298
Acquisitions, net of cash acquired						—						—						(307)
Proceeds from sales of assets, net of transaction costs						—						791						33
Disposition of equity interest, net of transaction costs5						—						419						5,328

1Includes continuing and discontinued operations.

2Includes nine months of Liquids Pipelines earnings in 2024 and a full year of earnings in 2023. Refer to the Discontinued operations section for additional information.

3Additional information on the most directly comparable GAAP measure can be found on page 22.

4Capital spending reflects cash flows associated with our Capital expenditures, Capital projects in development and Contributions to equity investments. For the year ended December 31, 2024, Contributions to equity investments was net of Other distributions from equity investments of $3.1 billion in the Canadian Natural Gas Pipelines segment. Refer to Note 5, Segmented information, Note 10, Equity investments and Note 11, Loans with affiliates, of our 2025 Consolidated financial statements for additional information.

5Included in the Financing activities section of the Consolidated statement of cash flows, of our 2025 Consolidated financial statements.

at December 31
(millions of $, except per share amounts)						2025						2024						2023
Balance sheet
Total assets1						118,751						118,243						125,034
Long-term debt, including current portion						46,792						47,931						52,914
Junior subordinated notes						12,094						11,048						10,287
Preferred shares						2,255						2,499						2,499
Non-controlling interests						9,604						10,768						9,455
Common shareholders' equity						25,040						25,093						27,054
Dividends declared2
per common share3						$3.40						$3.7025						$3.72
Basic common shares (millions)
– weighted average for the year ended						1,040						1,038						1,030
– issued and outstanding at end of year						1,041						1,039						1,037

1At December 31, 2025, includes assets of $197 million (2024 - $371 million; 2023 - $15,510 million), related to discontinued operations. Refer to         Note 4, Discontinued operations, of our 2025 Consolidated financial statements for additional information.

2For the year ended.

3Dividends declared in fourth quarter 2024 and thereafter reflect TC Energy’s proportionate allocation following the Spinoff Transaction.

18 | TC Energy Management's discussion and analysis 2025

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Consolidated results

year ended December 31
(millions of $, except per share amounts)						2025						2024						2023
Canadian Natural Gas Pipelines						2,164						2,016						(90)
U.S. Natural Gas Pipelines						3,927						4,053						3,531
Mexico Natural Gas Pipelines						1,186						929						796
Power and Energy Solutions						773						1,102						1,004
Corporate						(14)						(136)						(144)
Total 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 tax1						(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						3,400						4,594						2,829
Net income (loss) per common share – basic						$3.27						$4.43						$2.75
from continuing operations						$3.47						$4.05						$2.15
from discontinued operations1						($0.20)						$0.38						$0.60

1Represents nine months of Liquids Pipelines earnings in 2024 and a full year of earnings in 2023. Refer to the Discontinued operations section for additional information.

year ended December 31
(millions of $)						2025						2024						2023
Amounts attributable to common shares
Net income (loss) from continuing operations						4,306						4,984						2,456
Net (income) loss attributable to non-controlling interests						(575)						(681)						(146)
Net income (loss) attributable to controlling interests from continuing operations						3,731						4,303						2,310
Preferred share dividends						(119)						(104)						(93)
Net income (loss) attributable to common shares from continuing operations						3,612						4,199						2,217
Net income (loss) from discontinued operations, net of tax1						(212)						395						612
Net income (loss) attributable to common shares						3,400						4,594						2,829

1Represents nine months of Liquids Pipelines earnings in 2024 and a full year of earnings in 2023. Refer to the Discontinued operations section for additional information.

Net income attributable to common shares from continuing operations in 2025 was $3.6 billion or $3.47 per common share (2024 – $4.2 billion or $4.05 per common share; 2023 – $2.2 billion or $2.15 per common share), a decrease of $0.6 billion or $0.58 per common share in 2025 compared to 2024 and an increase of $2.0 billion or $1.90 per common share in 2024 compared to 2023. Refer to the About our business - Non-GAAP measures section for a listing of specific items included in Net income attributable to common shares from continuing operations, which have been excluded from our calculation of comparable measures.

Refer to the Discontinued operations - Non-GAAP measures section for a listing of specific items included in Net income (loss) from discontinued operations, net of tax, which have been excluded from our calculation of comparable measures.

TC Energy Management's discussion and analysis 2025 | 19

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Cash flows

Net cash provided by operations of $7.3 billion in 2025 was five per cent lower than 2024 primarily due to the timing of working capital changes, partially offset by higher funds generated from operations. Comparable funds generated from operations of $8.0 billion in 2025 were one per cent higher than 2024 primarily due to higher comparable EBITDA and risk management activities used to manage our foreign exchange exposure to net liabilities in Mexico and to U.S. dollar‑denominated income, partially offset by lower distributions from our equity investments.

Funds used in investing activities

Capital spending1

year ended December 31
(millions of $)						2025						2024						2023
Canadian Natural Gas Pipelines						1,405						2,100						6,184
U.S. Natural Gas Pipelines						3,457						2,575						2,660
Mexico Natural Gas Pipelines						522						2,228						2,292
Power and Energy Solutions						922						824						1,080
Corporate						31						50						33
						6,337						7,777						12,249
Discontinued operations						—						127						49
						6,337						7,904						12,298

1Capital spending reflects cash flows associated with our Capital expenditures, Capital projects in development and Contributions to equity investments. For the year ended December 31, 2024, Contributions to equity investments were net of Other distributions from equity investments of $3.1 billion in the Canadian Natural Gas Pipelines segment. Refer to Note 5, Segmented information, Note 10, Equity investments and Note 11, Loans with affiliates, of our 2025 Consolidated financial statements for additional information.

In 2025 and 2024, we invested $6.3 billion and $7.9 billion, respectively, in capital projects to maintain and optimize the value of our existing assets and to develop new, complementary assets in high-demand areas. Our total capital spending in 2025 and 2024 included contributions of $1.1 billion and $1.5 billion (net of distributions), respectively, to our equity investments, predominantly related to Bruce Power and Coastal GasLink Limited Partnership (Coastal GasLink LP).

Proceeds from sales of assets

In 2024, TC Energy and its partner, Northern New England Investment Company, Inc., a subsidiary of Énergir L.P. (Énergir), completed the sale of Portland Natural Gas Transmission System (PNGTS) to a third party. Our share of the proceeds was     $743 million (US$546 million), net of transaction costs.

In 2024, we also completed the sale of other non-core assets for gross proceeds of $48 million.

In 2023, we completed the sale of a 20.1 per cent equity interest in Port Neches Link LLC to its joint venture partner, Motiva Enterprises, for gross proceeds of $33 million (US$25 million). As part of the Spinoff Transaction on October 1, 2024, our remaining interest in Port Neches Link LLC was transferred to South Bow.

Acquisitions

In 2023, we acquired 100 per cent of the Class B Membership Interests in Fluvanna Wind Farm and Blue Cloud Wind Farm (Texas Wind Farms) for US$224 million, before post-closing adjustments.

Balance sheet

We continue to maintain a solid financial position while growing our total assets, excluding discontinued operations, by         $0.7 billion in 2025. At December 31, 2025, common shareholders' equity and non-controlling interests represented         36 per cent (2024 – 37 per cent) of our capital structure, while other subordinated capital, in the form of junior subordinated notes and preferred shares, represented an additional 14 per cent (2024 – 14 per cent). Refer to the Financial condition section for additional information.

20 | TC Energy Management's discussion and analysis 2025

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Dividends

Commencing with the dividends payable on January 31, 2025 to shareholders of record at the close of business on     December 31, 2024, the amounts reflect TC Energy’s proportionate allocation following the Spinoff Transaction. Refer to our 2024 Annual Report for additional information.

Our Board of Directors have declared a quarterly dividend on our outstanding common shares of $0.8775 per common share for the quarter ending March 31, 2026, which equates to an annual dividend of $3.51 per common share.

Dividend reinvestment and share purchase plan

Under the 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.

Commencing with the dividends declared on July 27, 2023, common shares purchased under TC Energy's DRP are acquired on the open market at 100 per cent of the weighted average purchase price.

Cash dividends paid

year ended December 31
(millions of $)						2025						2024						2023
Common shares						3,507						3,953						2,787
Preferred shares						114						99						92

TC Energy Management's discussion and analysis 2025 | 21

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NON-GAAP MEASURES

This MD&A references non-GAAP measures, which are identified in the table below. These measures do not have any standardized meaning as prescribed by GAAP and therefore may not be comparable to similar measures presented by other entities. These measures are reviewed regularly by our President and Chief Executive Officer, management and the Board of Directors in assessing our performance and making decisions regarding the ongoing operations of our business and its ability to generate cash flows. Some or all of these measures may also be used by investors and other external users of our financial statements as a supplemental measure to provide decision-useful information regarding our period-over-period performance and ability to generate earnings that are core to our ongoing operations. Discussions throughout this MD&A on the factors impacting comparable earnings before interest, taxes, depreciation and amortization (comparable EBITDA) and comparable earnings before interest and taxes (comparable EBIT) are consistent with the factors that impact segmented earnings, except where noted otherwise.

Comparable measures

We calculate comparable measures by adjusting certain GAAP measures for specific items we believe are significant but not reflective of our underlying operations in the period. Except as otherwise described herein, these comparable measures are calculated on a consistent basis from period to period and are adjusted for specific items in each period, as applicable.

Our decision to adjust for a specific item in reporting comparable measures is subjective and made after careful consideration. We maintain a consistent approach to adjustments, which generally fall into the categories described below:

•by their nature are unusual, infrequent and separately identifiable from our normal business operations and in our view are not reflective of our underlying operations in the period and generally include the following:

◦gains or losses on sales of assets or assets held for sale; impairment of goodwill, plant, property and equipment, equity investments and other assets; legal, contractual and other infrequent settlements; acquisition, integration and restructuring costs; expected credit loss provisions on net investment in leases and certain contract assets in Mexico; impacts resulting from changes in legislation and enacted tax rates and unusual tax refunds/payments and valuation allowance adjustments

•unrealized gains and losses related to fair value adjustments that do not reflect realized earnings or losses or cash impacts incurred in the current period from our underlying operations and generally include the following:

◦unrealized gains and losses from changes in the fair value of derivatives related to financial and commodity price risk management activities; unrealized fair value adjustments related to our proportionate share of Bruce Power’s risk management activities and its funds invested for post-retirement benefits; unrealized foreign exchange gains and losses on intercompany loans that impact consolidated earnings.

The following table identifies our non-GAAP measures against their most directly comparable GAAP measures. These measures are applicable to our continuing and discontinued operations. Quantitative reconciliations of our comparable measures to their GAAP measures and a discussion of specific adjustments made for 2025 and comparative periods can be found on pages 24     and 25, the Financial results section in each business segment, and the Financial condition section. Non-GAAP measures for discontinued operations are found in the Discontinued operations section on page 89.

Non-GAAP measure			GAAP measure
comparable EBITDA			segmented earnings (losses)
comparable EBIT			segmented earnings (losses)
comparable earnings			net income (loss) attributable to common shares
comparable earnings per common share			net income (loss) per common share
funds generated from operations			net cash provided by operations
comparable funds generated from operations			net cash provided by operations

22 | TC Energy Management's discussion and analysis 2025

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Comparable EBITDA and comparable EBIT

Comparable EBITDA represents segmented earnings (losses) adjusted for specific items described in the Comparable measures section, excluding charges for depreciation and amortization. We use comparable EBITDA as a measure of our earnings from ongoing operations as it is a useful indicator of our performance and is also presented on a consolidated basis. Comparable EBIT represents segmented earnings (losses) adjusted for specific items and is an effective tool for evaluating trends in each segment. Refer to each business segment and the Discontinued operations section for a reconciliation to segmented earnings (losses).

Funds generated from operations and comparable funds generated from operations

Funds generated from operations reflects net cash provided by operations before changes in operating working capital. The components of changes in working capital are disclosed in Note 28, Changes in operating working capital, of our 2025 Consolidated financial statements. Comparable funds generated from operations is adjusted for the cash impact of specific items described in the Comparable measures section. We believe funds generated from operations and comparable funds generated from operations are useful measures of our consolidated operating cash flows because they exclude fluctuations from working capital balances, which do not necessarily reflect underlying operations in the same period, and are used to provide a consistent measure of the cash-generating ability of our businesses. Refer to the Financial condition section for a reconciliation to Net cash provided by operations.

Comparable earnings and comparable earnings per common share

Comparable earnings represents earnings attributable to common shareholders on a consolidated basis, adjusted for specific items described in the Comparable measures section. Comparable earnings is comprised of segmented earnings (losses), Interest expense, AFUDC, Foreign exchange (gains) losses, net, Interest income and other, Income tax expense (recovery), Net income (loss) attributable to non-controlling interests and Preferred share dividends on our Consolidated statement of income, adjusted for specific items. We use comparable earnings as a measure of our earnings from ongoing operations as it is a useful indicator of our performance and is also presented on a consolidated basis. Refer to page 25 and the Discontinued operations section for reconciliations to Net income (loss) attributable to common shares and Net income (loss) per common share for our continuing operations and discontinued operations.

TC Energy Management's discussion and analysis 2025 | 23

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Comparable earnings and comparable earnings per common share - from continuing operations

The following specific items were recognized in Net income (loss) attributable to common shares from continuing operations and were excluded from comparable earnings from continuing operations:

2025

•a pre-tax impairment charge of $110 million for certain Power and Energy Solutions projects following our decision to discontinue development along with updated forecast assumptions as we refocus our Power and Energy Solutions strategy

•pre-tax unrealized foreign exchange losses, net, of $89 million on the peso-denominated intercompany loan between TransCanada PipeLines Limited (TCPL) and Transportadora de Gas Natural de la Huasteca (TGNH), net of non-controlling interest

•a pre-tax expense of $75 million on the expected credit loss provision related to TGNH net investment in leases, net of         non-controlling interest as well as certain contract assets in Mexico.

2024

•a pre-tax gain of $572 million related to the sale of PNGTS which was completed on August 15, 2024

•a pre-tax net gain on debt extinguishment of $228 million related to the purchase and cancellation of certain senior unsecured notes and medium term notes and the retirement of outstanding callable notes in October 2024

•pre-tax unrealized foreign exchange gains, net, of $143 million on the peso-denominated intercompany loan between TCPL and TGNH, net of non-controlling interest

•a pre-tax gain of $48 million related to the sale of non-core assets in U.S. Natural Gas Pipelines and Canadian Natural Gas Pipelines

•a pre-tax recovery of $22 million on the expected credit loss provision related to TGNH net investment in leases, net of         non-controlling interest as well as certain contract assets in Mexico

•a deferred income tax expense of $96 million resulting from the revaluation of remaining deferred tax balances following the Spinoff Transaction

•a pre-tax impairment charge of $36 million for a Power and Energy Solutions project following our decision to discontinue development as we refocus our Power and Energy Solutions strategy

•a pre-tax expense of $34 million related to a non-recurring third-party settlement

•a pre-tax expense of $24 million related to Focus Project costs

•pre-tax costs of $10 million related to the NGTL System ownership transfer.

2023

•a pre-tax impairment charge of $2.1 billion related to our equity investment in Coastal GasLink LP

•a pre-tax expense of $65 million related to Focus Project costs

•pre-tax unrealized foreign exchange losses, net, of $44 million on the peso-denominated intercompany loan between TCPL and TGNH

•a pre-tax recovery of $80 million on the expected credit loss provision related to TGNH net investment in leases and certain contract assets in Mexico.

Refer to the Financial results section in each business segment and the Financial condition section of this MD&A for additional information.

24 | TC Energy Management's discussion and analysis 2025

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Reconciliation of net income (loss) attributable to common shares to comparable earnings - from continuing operations

year ended December 31
(millions of $, except per share amounts)						2025						2024						2023
Net income (loss) attributable to common shares from continuing operations						3,612						4,199						2,217
Specific items (pre tax):
Power and Energy Solutions impairment charges						110						36						—
Foreign exchange (gains) losses, net – intercompany loan1						89						(143)						44
Expected credit loss provision on net investment in leases   and certain contract assets in Mexico2						75						(22)						(80)
Gain on sale of PNGTS						—						(572)						—
Net gain on debt extinguishment3						—						(228)						—
Gain on sale of non-core assets						—						(48)						—
Third-party settlement						—						34						—
Focus Project costs4						—						24						65
NGTL System ownership transfer costs						—						10						—
Coastal GasLink impairment charge						—						—						2,100
Bruce Power unrealized fair value adjustments						(30)						(8)						(7)
Risk management activities5						(228)						433						(395)
Taxes on specific items6						26						150						(48)
Comparable earnings from continuing operations						3,654						3,865						3,896
Net income (loss) per common share from continuing operations						$3.47						$4.05						$2.15
Specific items (net of tax)						0.04						(0.32)						1.63
Comparable earnings per common share from continuing operations						$3.51						$3.73						$3.78

1In 2023, TCPL and TGNH entered into an unsecured revolving credit facility. While the loan receivable and payable eliminate on consolidation, differences in each entity’s reporting currency create a net income impact from revaluing and translating these balances into TC Energy’s reporting currency. As the resulting unrealized foreign exchange gains and losses do not reflect amounts expected to be realized at settlement, we exclude them from comparable measures, net of non‑controlling interest.

2We have recognized an expected credit loss provision related to net investment in leases and certain contract assets in Mexico, which will fluctuate from period to period based on changing economic assumptions and forward-looking information. This provision is an estimate of losses that may occur over the duration of the TSA through 2055. This provision does not reflect losses or cash outflows that were incurred under this lease arrangement in the current period or from our underlying operations, and therefore, we have excluded any unrealized changes, net of non-controlling interest, from comparable measures. Refer to Note 27, Risk management and financial instruments, of our 2025 Consolidated financial statements for additional information.

3In October 2024, TCPL commenced and completed our 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, we retired outstanding callable notes at par. These extinguishments of debt resulted in a pre-tax
net gain of $228 million, primarily due to fair value discounts and unamortized debt issue costs. The net gain on debt extinguishment was recorded in Interest expense in the Consolidated statement of income. Refer to Note 19, Long-term debt, of our 2025 Consolidated financial statements for additional information.

4In 2023 and 2024, we recognized expenses related to the Focus Project for external consulting and severance, some of which are not recoverable through regulatory and commercial tolling structures.

5						year ended December 31
						(millions of $)						2025						2024						2023
						U.S. Natural Gas Pipelines						58						(113)						80
						Canadian Power						(16)						84						(31)
						U.S. Power						9						(10)						9
						Natural Gas Storage						(35)						(57)						91
						Interest rate						2						(71)						—
						Foreign exchange						210						(266)						246
												228						(433)						395
						Income tax attributable to risk management activities						(56)						105						(99)
						Total unrealized gains (losses) from risk management activities						172						(328)						296
6						Refer to the Corporate - Financial results section for additional information.

TC Energy Management's discussion and analysis 2025 | 25

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Comparable EBITDA to comparable earnings - from continuing operations

Comparable EBITDA from continuing operations represents segmented earnings (losses) from continuing operations adjusted
for the specific items described above and excludes charges for depreciation and amortization. For further information on our reconciliation to comparable EBITDA, refer to the Financial results sections for each business segment.

year ended December 31
(millions of $, except per share amounts)						2025						2024						2023
Comparable EBITDA from continuing operations
Canadian Natural Gas Pipelines						3,687						3,388						3,335
U.S. Natural Gas Pipelines						4,906						4,511						4,385
Mexico Natural Gas Pipelines						1,365						999						805
Power and Energy Solutions						1,008						1,214						1,020
Corporate						(14)						(63)						(73)
Comparable EBITDA from continuing operations						10,952						10,049						9,472
Depreciation and amortization						(2,769)						(2,535)						(2,446)
Interest expense included in comparable earnings						(3,409)						(3,176)						(2,966)
Allowance for funds used during construction						453						784						575
Foreign exchange gains (losses), net included in comparable earnings						96						(85)						118
Interest income and other						205						324						272
Income tax (expense) recovery included in comparable earnings						(1,112)						(772)						(890)
Net (income) loss attributable to non-controlling interests included in comparable earnings						(643)						(620)						(146)
Preferred share dividends						(119)						(104)						(93)
Comparable earnings from continuing operations						3,654						3,865						3,896
Comparable earnings per common share from continuing operations						$3.51						$3.73						$3.78

26 | TC Energy Management's discussion and analysis 2025

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Comparable EBITDA from continuing operations

2025 versus 2024

Comparable EBITDA from continuing operations in 2025 increased by $903 million compared to 2024 primarily due to the net result of the following:

•increased EBITDA from Canadian Natural Gas Pipelines primarily due to higher flow-through costs and incentive earnings on the NGTL System and Mainline and higher contributions from Coastal GasLink mainly resulting from the declared commercial in-service of the pipeline in fourth quarter 2024

•higher U.S. dollar-denominated EBITDA from Mexico Natural Gas Pipelines mainly due to higher earnings in TGNH primarily related to the completion of the Southeast Gateway pipeline in second quarter 2025, partially offset by lower equity earnings from Sur de Texas as a result of peso-denominated financial exposure and higher income tax expense mainly related to foreign exchange impacts of U.S dollar-denominated liabilities

•higher U.S. dollar-denominated EBITDA from U.S. Natural Gas Pipelines due to an increase in earnings from Columbia Gas as a result of higher transportation rates effective April 1, 2025, incremental earnings from projects placed in service and additional contract sales, partially offset by lower earnings from our equity investments and higher operational costs

•increased EBITDA from Corporate primarily due to costs in 2024 related to TC Energy's corporate services and governance functions that were not allocated to discontinued operations

•decreased Power and Energy Solutions EBITDA resulting from lower contributions from Bruce Power mainly due to the Unit 4 Major Component Replacement (MCR), higher operating costs, partially offset by a higher contract price; decreased Canadian Power earnings primarily due to lower realized power prices, partially offset by Natural Gas Storage and other contributions reflecting the net impact of lower business development costs and lower realized Alberta natural gas storage spreads

•the positive foreign exchange impact of a stronger U.S. dollar on the Canadian dollar equivalent comparable EBITDA in our U.S. dollar-denominated operations. As detailed on page 72, U.S. dollar-denominated comparable EBITDA from continuing operations increased by US$463 million compared to 2024, which was translated to Canadian dollars at an average rate of
1.40 in 2025 versus 1.37 in 2024. Refer to the Foreign exchange section for additional information.

2024 versus 2023

Comparable EBITDA from continuing operations in 2024 increased by $577 million compared to 2023 primarily due to the net result of the following:

•increased Power and Energy Solutions EBITDA primarily attributable to higher contributions from Bruce Power due to higher generation and a higher contract price, and Natural Gas Storage and other due to higher realized Alberta natural gas storage spreads, partially offset by decreased Canadian Power earnings primarily due to lower realized power prices net of lower natural gas fuel costs

•higher U.S. dollar-denominated EBITDA from Mexico Natural Gas Pipelines mainly due to increased equity earnings from Sur de Texas as a result of peso-denominated financial exposure and lower income tax expense

•increased EBITDA from Canadian Natural Gas Pipelines primarily due to higher flow-through costs and increased rate-base earnings on the NGTL System and Foothills, partially offset by lower earnings from Coastal GasLink related to the recognition
of a $200 million incentive payment in 2023

•higher U.S. dollar-denominated EBITDA from U.S. Natural Gas Pipelines due to incremental earnings from growth projects placed in service and additional contract sales, partially offset by higher operational costs and decreased earnings as a result of the sale of PNGTS, which was completed on August 15, 2024

•the positive foreign exchange impact of a stronger U.S. dollar on the Canadian dollar equivalent comparable EBITDA in our U.S. dollar-denominated operations. As detailed on page 72,U.S. dollar-denominated comparable EBITDA from continuing operations increased by US$180 million compared to 2023, which was translated to Canadian dollars at an average rate of
1.37 in 2024 versus 1.35 in 2023. Refer to the Foreign exchange section for additional information.

Due to the flow-through treatment of certain costs including income taxes, financial charges and depreciation in our
Canadian rate-regulated pipelines, changes in these costs impact our comparable EBITDA despite having no significant effect
on net income.

TC Energy Management's discussion and analysis 2025 | 27

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Comparable earnings from continuing operations

2025 versus 2024

Comparable earnings from continuing operations in 2025 were $211 million or $0.22 per common share lower than in 2024, and were primarily the net result of:

•changes in comparable EBITDA from continuing operations described above

•higher income tax expense primarily due to Mexico foreign exchange exposure and higher flow-through income taxes

•lower AFUDC primarily due to the completion of the Southeast Gateway pipeline project

•higher depreciation and amortization primarily due to higher depreciation rates on the NGTL System under the 2025-2029 NGTL Settlement and depreciation rate changes as a result of the Columbia Gas Settlement

•higher interest expense primarily due to lower capitalized interest resulting from the declared commercial in-service of         the Coastal GasLink pipeline in fourth quarter 2024 and increased levels of short-term borrowing

•lower interest income and other due to lower interest earned on short-term investments and an increase in insurance-related provisions

•higher net income attributable to non-controlling interests primarily due to the net effect of higher net income recognized from Columbia Gas Transmission, LLC (Columbia Gas) and Columbia Gulf Transmission, LLC (Columbia Gulf) assets, the completion of the Southeast Gateway pipeline in second quarter 2025 and the full year impact of the sale of a 13.01 per cent non-controlling equity interest in TGNH to the CFE, completed in second quarter 2024

•risk management activities used to manage our foreign exchange exposure to net liabilities in Mexico and to U.S. dollar‑denominated income and the revaluation of our peso-denominated net monetary liabilities to U.S. dollars.

2024 versus 2023

Comparable earnings from continuing operations in 2024 were $31 million or $0.05 per common share lower than in 2023, and were primarily the net result of:

•changes in comparable EBITDA from continuing operations described above

•higher depreciation and amortization reflecting expansion facilities and new projects placed in service

•higher interest expense primarily due to long-term debt issuances, net of maturities, the foreign exchange impact of a stronger U.S. dollar in 2024 compared to 2023, higher interest rates on short-term borrowings in 2024 and the impact of interest expense allocated to discontinued operations for nine months in 2024 compared to a full year in 2023

•higher AFUDC predominantly due to spending on the Southeast Gateway pipeline project, partially offset by projects placed in service and the cessation of AFUDC on Tula in fourth quarter 2023

•risk management activities used to manage our foreign exchange exposure to net liabilities in Mexico and to U.S. dollar‑denominated income and the revaluation of our peso-denominated net monetary liabilities to U.S. dollars

•higher interest income and other due to higher interest earned on short-term investments and a reduction in insurance-related provisions

•decreased income tax expense due to the impact of Mexico foreign exchange exposure and lower comparable earnings subject to income tax, partially offset by lower foreign income tax rate differentials and higher flow-through income taxes

•higher net income attributable to non-controlling interests primarily due to the net effect of the sale of a 40 per cent non-controlling equity interest in Columbia Gas and Columbia Gulf in fourth quarter 2023 and the full year impact of the     13.01 per cent non-controlling equity interest in TGNH to the CFE, completed in second quarter 2024, partially offset by the divestiture of PNGTS in third quarter 2024.

Comparable earnings per common share reflect the dilutive effect of common shares issued. Refer to the Financial condition section for additional information.

28 | TC Energy Management's discussion and analysis 2025

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SUPPLEMENTARY FINANCIAL MEASURE

Net capital expenditures

Net capital expenditures represents capital costs incurred for growth projects, maintenance capital expenditures, contributions to equity investments and projects under development, adjusted for the portion attributed to non-controlling interests in the entities we control. Net capital expenditures reflect capital costs incurred during the period, excluding the impact of timing of cash payments. We use net capital expenditures as a key measure in evaluating our performance in managing our capital spending activities in comparison to our capital plan.

Net capital expenditures does not include an adjustment related to the CFE’s minority interest in TGNH capital expenditures until after the in-service of the projects included as part of the 2022 strategic alliance between TGNH and the CFE. The CFE’s contribution in second quarter 2024 to obtain a 13.01 per cent equity interest in TGNH included consideration of its proportionate share of required capital contributions for approved projects. Net capital expenditures will be adjusted for any new capital projects approved in TGNH going forward.

OUTLOOK

Comparable EBITDA and comparable earnings

We expect our 2026 comparable EBITDA and our 2026 comparable earnings per common share to be higher than 2025 due to the net impact of the following:

•new projects anticipated to be placed in service in 2026, along with the full-year impact of projects placed in service in 2025

•higher revenue from the Columbia Gas settlement

•higher net generation from Bruce Power due to the return to service of Unit 3 from the MCR outage, partially offset by the commencement of the Unit 5 MCR outage

•higher depreciation due to the in-service of Canadian Natural Gas Pipelines and U.S. Natural Gas Pipelines projects

•lower AFUDC primarily due to Southeast Gateway pipeline in-service in 2025.

Consolidated capital expenditures

In 2025, we incurred approximately $5.9 billion in gross capital expenditures on our secured capital program and projects under development, as well as capitalized interest and AFUDC, where applicable. Net capital expenditures after adjusting for the capital expenditures attributable to the non-controlling interests of entities we control were approximately $5.3 billion.

Prior to adjustments for non-controlling interests, we expect to incur gross capital expenditures of approximately $6.0 to     $6.5 billion in 2026. We anticipate our net capital expenditures in 2026 to be approximately $5.5 to $6.0 billion.

The majority of our 2026 capital program is focused on the advancement of secured projects including U.S. Natural Gas Pipelines projects, NGTL System expansions, pipeline projects in Mexico, Bruce Power MCR programs and normal course maintenance capital expenditures.

Refer to the Outlook section in each business segment for additional details on expected earnings and capital expenditures
for 2026.

TC Energy Management's discussion and analysis 2025 | 29

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CAPITAL PROGRAM

We are developing quality projects under our capital program. These long-life infrastructure assets are supported by long-term commercial arrangements with creditworthy counterparties and/or regulated business models and are expected to generate growth in earnings and cash flows.

Our capital program consists of approximately $21 billion of secured projects that represent commercially supported, committed projects that are either under construction or are in, or preparing to commence the permitting stage.

Three years of maintenance capital expenditures for our businesses are included in the Secured projects table. Maintenance capital expenditures on our regulated Canadian and U.S. natural gas pipelines are added to rate base on which we have the opportunity to earn a return and recover these expenditures through current or future tolls, which is similar to our capacity capital projects on these pipelines.

During 2025, we placed approximately $8.3 billion of projects into service, which included natural gas pipeline capacity projects along our extensive North American asset footprint, including the Southeast Gateway pipeline, as well as progress on the Bruce Power life extension program. In addition, approximately $2.2 billion of maintenance capital expenditures were incurred in the period.

All projects are subject to cost and timing adjustments due to factors including weather, market conditions, route refinement, land acquisition, permitting conditions, scheduling and timing of regulatory permits, as well as other potential restrictions and uncertainties, including inflationary pressures on labour and materials. Amounts exclude capitalized interest and AFUDC, where applicable.

30 | TC Energy Management's discussion and analysis 2025

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Secured projects

Estimated and incurred project costs referred to in the following table include 100 per cent of the capital expenditures related to projects within entities that we own or partially own and fully consolidate, as well as our share of equity contributions to fund projects within our equity investments.

(billions of Canadian $, unless otherwise noted)						Expected in-service date						Estimated project cost						Project costs incurred at December 31, 2025
Canadian Natural Gas Pipelines1
NGTL System						2026						0.5			2			0.4
						2027						0.4			2			—
						2028+						0.6			2			—
Regulated maintenance capital expenditures						2026-2028						2.6						—
U.S. Natural Gas Pipelines
Gillis Access – Extension						2026-2027						US 0.4						US 0.1
Heartland project						2027						US 0.9						US 0.1
Northwoods project						2029						US 0.9						—
Pulaski and Maysville projects						2029						US 0.8						—
Southeast Virginia Energy Storage project						2030						US 0.3						—
TCO Connector project						2030						US 0.3						—
Other capital3						2026-2031						US 1.9						US 0.4
Regulated maintenance capital expenditures						2026-2028						US 2.6						—
Mexico Natural Gas Pipelines
Villa de Reyes – South section4						—						US 0.4						US 0.3
Tula5						—						US 0.4						US 0.3
Power and Energy Solutions
Bruce Power – Unit 3 MCR						2026						1.1						1.1
Bruce Power – Unit 4 MCR6						2028						0.9						0.4
Bruce Power – Unit 5 MCR6						2030						1.1						0.2
Bruce Power – life extension7						2026-2031						1.5						0.7
Other
Non-recoverable maintenance capital expenditures8						2026-2028						0.5						—
												18.1						4.0
Foreign exchange impact on secured projects9												3.3						0.4
Total secured projects												21.4						4.4

1Our share of committed equity to fund the estimated cost of the Coastal GasLink - Cedar Link project is $37 million.

2Includes amounts related to projects within the Multi-Year Growth Plan (MYGP) that have received FID.

3Includes capital expenditures related to certain    large-scope     maintenance projects across our U.S. natural gas footprint due to their discrete nature for regulatory recovery.

4We are working with the CFE on completing the remaining section of the Villa de Reyes pipeline. The in-service date will be determined upon resolution of outstanding stakeholder issues.

5Estimated project cost as per contracts signed in 2022 as part of the TGNH strategic alliance between TC Energy and the CFE. We continue to evaluate the development and completion of the Tula pipeline with the CFE, subject to a future FID and an updated cost estimate.

6Amounts are net of expected investment tax credits.

7Reflects amounts to be invested under the Asset Management program to 2027, other life extension projects and the incremental uprate initiative.

8Includes non-recoverable maintenance capital expenditures from all segments and is primarily related to our Power and Energy Solutions and Corporate assets.

9Reflects U.S./Canada foreign exchange rate of 1.37 at December 31, 2025.

TC Energy Management's discussion and analysis 2025 | 31

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Projects under development

In addition to our secured projects, we are pursuing a portfolio of quality projects in various stages of development across each of our business units. Projects under development have greater uncertainty with respect to timing and estimated project costs and are subject to company and regulatory approvals, unless otherwise noted. New growth opportunities will be assessed within our disciplined capital allocation framework in order to fit within our annual capital expenditure parameters. As these new opportunities advance and reach required milestones, they will be included in the Secured projects table.

Canadian Natural Gas Pipelines

We continue to focus on optimizing the utilization and value of our existing Canadian Natural Gas Pipelines assets, including sanctioned in-corridor expansions, providing connectivity to LNG export terminals, connecting growing WCSB gas supplies to domestic and export markets and other opportunities, including progressing our Multi-Year Growth Plan (MYGP). The MYGP is comprised of multiple distinct projects with various targeted in-service dates, subject to final company and regulatory approvals.

U.S. Natural Gas Pipelines

We are currently pursuing a variety of projects that are expected to replace, upgrade, expand and extend our U.S. Natural Gas Pipelines footprint. The enhanced facilities associated with these projects are expected to improve the reliability of our systems and provide additional transportation capacity under long-term contracts. We continue to see growing demand across multiple segments, driving potential expansion projects to support new natural gas-fired power generation, coal to natural gas conversions, LDC growth and data centres. Our footprint is well positioned to deliver natural gas supply through our existing utility customer base or by way of direct connections. Additional opportunities include direct and indirect interconnects to deliver natural gas to power generation for data centres, continued LNG development in proximity to our footprint and LDC peak day growth.

Power and Energy Solutions

Bruce Power

Life Extension Program

The continuation of Bruce Power’s life extension program will require the investment of our proportionate share of both the MCR program costs on Units 7 and 8 and the remaining Asset Management program costs, which continue beyond the completion of the MCR program in 2033, extending the life of Units 3 to 8 and the Bruce Power site to 2064. Preparation work for the Unit 7 and 8 MCRs is underway and future MCR investments will be subject to discrete decisions for each unit with specified off-ramps available to Bruce Power and the IESO. Refer to the Power and Energy Solutions – Significant events section for additional information.

Energy Solutions

Ontario Pumped Storage

With our prospective partners, Saugeen Ojibway Nation, we continue to advance the Ontario Pumped Storage Project, an energy storage facility located in Meaford, Ontario. The 1,000 MW project is expected to provide enough electricity to power one million homes for up to 11 hours, while enhancing the reliability and efficiency of Ontario's electricity system.

Using water and gravity, the project is like a natural battery that will store surplus electricity when demand is low and later redeploy it during periods of high demand. The project will support the planned buildout of Ontario’s nuclear fleet and can deliver Ontario’s clean nuclear power on demand.

In January 2025, the Ontario Government announced it was investing up to $285 million to advance pre-development work on the project. With this investment, the project is advancing critical development work, including the completion of a detailed cost estimate, the commencement of federal and provincial environmental assessments, advanced design and engineering and continued community engagement. It is expected that our Board of Directors, Saugeen Ojibway Nation and the Ontario Government will each make a final investment decision on the project following this pre-development work.

32 | TC Energy Management's discussion and analysis 2025

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NATURAL GAS PIPELINES BUSINESS

Our natural gas pipeline network transports natural gas from supply basins to LDCs, power generation plants, industrial facilities, interconnecting pipelines, LNG export terminals and other businesses across Canada, the U.S. and Mexico. Our network of pipelines taps into most major supply basins and transports over 30 per cent of continental daily natural gas needs through:

•wholly-owned natural gas pipelines – 63,185 km (39,260 miles)

•partially-owned natural gas pipelines – 30,986 km (19,253 miles).

In addition to our natural gas pipelines, we have regulated natural gas storage facilities in the U.S. with a total working gas capacity of 532 Bcf, making us one of the largest providers of natural gas storage and related services to key markets in North America.

Our Natural Gas Pipelines business is split into three operating segments representing its geographic diversity:        Canadian Natural Gas Pipelines, U.S. Natural Gas Pipelines and Mexico Natural Gas Pipelines.

Strategy

Our strategy is to maximize the value of our existing natural gas pipeline systems in a safe and reliable manner while responding to the changing flow patterns of natural gas in North America. We also pursue new pipeline opportunities to add incremental value to our business.

Our key areas of focus include:

•primarily in-corridor expansion and extension of our existing significant North American natural gas pipeline footprint

•connections to new and growing industrial and electric power generation markets and LDCs

•expanding our systems in key locations in North America and developing new projects to provide connectivity to LNG export terminals, both operating and proposed

•connections to growing Canadian and U.S. shale gas and other supplies

•minimizing our GHG and methane emissions through operational excellence.

Each of these areas plays a critical role in meeting the transportation requirements for supply of and demand for natural gas in North America.

Our natural gas pipeline systems are helping solve the energy trilemma - energy security, affordability and sustainability. We believe natural gas provides a reliable, high-efficiency energy source that is helping to support the displacement of coal-fired power while backstopping the intermittency of renewable power sources across North America. We continue to improve operational efficiencies and factor sustainability-related considerations into our decision making around new projects, modernization, maintenance, electrification and enhanced leak detection. Our business model provides socioeconomic benefits as we work closely with Indigenous communities, community-based organizations, landowners and other stakeholders in alignment with our values and sustainability commitments.

Recent highlights

Canadian Natural Gas Pipelines

•placed approximately $0.2 billion of capacity capital projects into service in 2025 primarily related to the Valhalla section of NGTL's Valhalla North and Berland River (VNBR) project

•approximately $1.1 billion of MYGP expansion facilities have received FID at December 31, 2025, with in-service dates starting in 2026

•NGTL System achieved record inflows

•continued strong throughput on the Canadian Mainline.

TC Energy Management's discussion and analysis 2025 | 33

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U.S. Natural Gas Pipelines

•placed approximately US$2.7 billion of capital projects in service in 2025, including the East Lateral XPress, VR Project,         WR Project, Eastern Panhandle, Ventura XPress and maintenance capital

•sanctioned approximately US$2.3 billion of capital projects including the Northwoods and TCO Connector projects

•Columbia Gas filed a Section 4 Rate Case with FERC in September 2024 requesting an increase to maximum transportation rates effective April 1, 2025 and on October 30, 2025, FERC approved the settlement filing (Columbia Gas Settlement). Previously accrued rate refund liabilities were refunded to customers, including interest, in fourth quarter 2025

•ANR and Great Lakes each filed a Section 4 Rate Case with FERC in April 2025 requesting an increase to their maximum transportation rates effective November 1, 2025, subject to refund. The rate cases are progressing as expected as we continue to pursue a collaborative process through settlement negotiations

•achieved record throughput volumes on a number of our pipelines.

Mexico Natural Gas Pipelines

•the Southeast Gateway Pipeline was completed in May 2025. In July 2025, the newly constituted CNE approved our regulated rates required to provide service to potential future interruptible service users on the Southeast Gateway pipeline other than the CFE

•overall pipeline utilization continued to increase.

34 | TC Energy Management's discussion and analysis 2025

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UNDERSTANDING OUR NATURAL GAS PIPELINES BUSINESS

Natural gas pipelines move natural gas from major sources of supply to locations or markets that use natural gas to meet their energy needs.

Our natural gas pipelines business builds, owns and operates a network of natural gas pipelines across North America that connects gas production to interconnects, end-use markets and LNG export terminals. The network includes underground pipelines that transport natural gas predominantly under high pressure, compressor stations that act like pumps to move large volumes of natural gas along the pipeline, meter stations that record the amount of natural gas coming on the network at receipt locations and leaving the network at delivery locations and regulated natural gas storage facilities that provide services to customers and help maintain the overall balance of the pipeline systems.

Regulation of tolls and cost recovery

Our natural gas pipelines are generally regulated by the CER in Canada and FERC in the U.S. During March 2025, Mexico natural gas pipeline regulation transitioned from the CRE to the newly constituted CNE under the SENER.

These entities regulate the construction, operation and requested abandonment of pipeline infrastructure. For our rate regulated assets in Canada and the U.S., these regulators allow us to recover costs to operate the network by collecting tolls for services. These tolls generally include a return on our capital invested in the assets or rate base, as well as recovery of the rate base over time through depreciation. Other costs generally recovered through tolls include OM&A, taxes and interest on debt. The regulators generally review our costs to ensure they are reasonable and prudently incurred and approve tolls that provide a reasonable opportunity to recover those costs. In Mexico, while the majority of our capacity is subscribed under a long-term contractual rate, the regulator sets rates for interruptible services.

Business environment and strategic priorities

The North American natural gas pipeline network has been developed to connect diverse supply regions to domestic markets and to meet demand from LNG export facilities. Use and growth of this infrastructure is affected by changes in the location and relative cost of natural gas supplies, as well as changes in the location of markets and level of demand.

We have significant pipeline footprints that serve two of the most prolific supply regions of North America – the WCSB and the Appalachian basin. Our pipelines also source natural gas from other significant basins including the Rockies, Williston, Haynesville, Fayetteville and Anadarko basins. We expect continued growth in North American natural gas production to meet demand within growing domestic markets, particularly in the electric generation and industrial sectors which benefit from a relatively low natural gas price. In addition, North American supply is expected to benefit from increased natural gas demand in Mexico and growing access to international markets via LNG exports. We expect North American natural gas demand, including LNG exports, of approximately 155 Bcf/d by 2029, reflecting an increase of approximately 30 Bcf/d from 2024 levels.

As the world shifts toward a lower-carbon economy, we believe that further retirements of coal-fired power generation as well as export demand growth over the next five to 10 years will offer growth opportunities for base-load power from natural     gas-fired generation. We expect that this projected growth in demand for natural gas, coupled with the anticipated increases in key producing areas like WCSB, onshore Gulf Coast, Appalachian and the Permian basin, will provide investment opportunities for pipeline infrastructure companies to build new facilities or increase utilization of their existing footprint. Modernizing our existing systems and assets and decarbonizing our energy consumption along our natural gas pipeline systems is expected to provide ongoing additional capital investment opportunities that will meet our risk preferences while supporting our GHG emissions reduction targets.

TC Energy Management's discussion and analysis 2025 | 35

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Changing demand

The abundant supply of natural gas has supported increased demand, particularly in the following areas:

•natural gas-fired power generation, including for use in emerging data centres

•global LNG exports

•petrochemical and industrial facilities

•Alberta oil sands.

Natural gas producers continue to progress opportunities to sell natural gas to global markets which involves connecting natural gas supplies to LNG export terminals, both operating and proposed, along the U.S. Gulf Coast and the east and west coasts of Canada, the U.S. and Mexico. The increasing export of natural gas to Mexico is driven by the CFE’s need to serve existing markets and requires pipelines to serve new regions. We believe that natural gas is a key energy transition fuel for Mexico.

Overall, we are forecasting significant natural gas demand growth in the future to support economic expansion and industrial load growth, conversion to lower GHG emission-intensive fuels for industrial and power generation use and LNG export prospects. The demand created by these new markets provides additional opportunities for us to build new pipeline infrastructure and to increase throughput on our existing pipelines.

Commodity prices

The profitability of our natural gas pipelines business is not directly tied to commodity prices given we are a transporter of the commodity and the transportation tolls are not tied to the price of natural gas. However, the cyclical supply and demand nature of commodities and related pricing can have an indirect impact on our business where producers may choose to accelerate or delay development of gas reserves or, similarly on the demand side, projects requiring natural gas may be accelerated or delayed depending on market or price conditions.

More competition

Changes in supply and demand levels and locations have resulted in increased competition to provide transportation services throughout North America. Our well-distributed footprint of natural gas pipelines, particularly in the low-cost WCSB and the Appalachian basin, both of which are connected to North American demand centres, has placed us in a strong competitive position. Incumbent pipelines benefit from the connectivity and economies of scale afforded by the base infrastructure, as well as existing right-of-way and operational synergies given the increasing challenges of siting and permitting new pipeline construction and expansions. We have and will continue to offer competitive services to capture growing supply and North American demand that now includes access to global markets through LNG exports.

Strategic priorities

Our pipelines deliver the natural gas that millions of individuals and businesses across North America rely on for their energy needs. We are focused on capturing opportunities resulting from growing natural gas supply and connecting new markets while satisfying increasing demand for natural gas within existing markets. We are also focused on adapting our existing assets to changing natural gas flow dynamics and supporting our corporate-level sustainability commitments and targets.

Our goal is to place all of our projects into service on time and on budget while ensuring the safety of our people, the environment and the general public impacted by the construction and operation of these facilities. In 2026, we will continue to focus on the execution of our existing capital program, which includes initiating and advancing a suite of U.S. pipeline projects as well as investment in Canada, which includes the NGTL System and the Cedar Link project and investment in our Mexico gas pipelines. We will remain focused on capital discipline as we continue to pursue the next wave of growth opportunities.

Our marketing entities will complement our natural gas pipeline operations and generate non-regulated revenues by managing the procurement of natural gas supply and pipeline transportation capacity for natural gas customers within our pipeline corridors.

36 | TC Energy Management's discussion and analysis 2025

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TC Energy Management's discussion and analysis 2025 | 37

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We are the operator of all of the following natural gas pipelines and regulated natural gas storage assets except for Iroquois.

Length

Description

Ownership

Canadian pipelines

C1

NGTL System

24,096 km (14,973 miles)

Receives, transports and delivers natural gas within Alberta and British Columbia, and connects with Canadian Mainline, Coastal GasLink, Foothills and third-party pipelines. This is our natural gas gathering and transportation system for the WCSB, connecting most of the natural gas production in western Canada to domestic and export markets and is well positioned to connect growing supply in northeast British Columbia and northwest Alberta. Our capital program for new pipeline facilities is driven by these two supply areas, along with growing demand for intra-Alberta firm transportation for electric power generation, oil sands development and petro-chemical feedstock, as well as to our major export points at the Empress and Alberta/British Columbia delivery locations. The NGTL System is also well positioned to connect WCSB supply to LNG export facilities on the Canadian west coast through future extensions or expansions of the system or future connections to other pipelines serving that area.

100

%

C2

Canadian Mainline

14,087 km (8,753 miles)

Transports natural gas from the Alberta/Saskatchewan border and the Ontario/U.S. border to serve Canadian and U.S. markets. This pipeline supplies markets in the Canadian Prairies, Ontario, Québec, the Canadian Maritimes, as well as to U.S. markets including the Midwest, Gulf Coast and U.S. Northeast from the WCSB and, through interconnects, from the Appalachian basin.

100

%

C3

Foothills

1,289 km (801 miles)

Transports natural gas from central Alberta to the U.S. border for export to the U.S. Midwest, Pacific Northwest, California and Nevada.

100

%

C4

Coastal GasLink

671 km (417 miles)

Transports natural gas from the Montney region to LNG Canada's liquefaction facility near Kitimat, British Columbia, supplied via connections with the NGTL System and other pipelines.

35

%

C5

Trans Québec & Maritimes (TQM)

648 km (403 miles)

Connects with the Canadian Mainline near the Ontario/Québec border to transport natural gas to the Montréal to Québec City corridor and interconnects with a third-party pipeline at the U.S. border.

50

%

C6

Ventures LP

133 km (83 miles)

Transports natural gas to the oil sands region near Fort McMurray, Alberta.

100

%

C7

Great Lakes Canada

60 km (37 miles)

Transports natural gas from the Great Lakes system in the U.S. to a point near Dawn, Ontario through a connection at the U.S. border underneath the St. Clair River.

100

%

U.S. pipelines and gas storage assets

U1

Columbia Gas

18,598 km (11,556 miles)

Transports natural gas primarily from the Appalachian basin, which contains the Marcellus and Utica shale plays, two of the largest natural gas shale plays in North America, to markets and pipeline interconnects throughout the U.S. Northeast, Midwest and Atlantic regions and is well positioned to connect growing supply to markets in this area. This system also interconnects with other pipelines that provide access to key markets in the U.S. Northeast, the Midwest, the Atlantic coast and south to the Gulf of Mexico and its growing demand for natural gas to serve LNG exports.

60

%

U1.1

Columbia Storage

285 Bcf

Provides regulated underground natural gas storage service from several facilities (not all shown) to customers in key eastern markets. We own a 60 per cent interest in the 273 Bcf Columbia Storage facility and a 50 per cent interest in the 12 Bcf Hardy Storage facility.

Various

38 | TC Energy Management's discussion and analysis 2025

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Length

Description

Ownership

U2

ANR1

15,075 km (9,367 miles)

Transports natural gas from various supply basins to markets throughout the U.S. Midwest and U.S. Gulf Coast. This pipeline system connects supply basins and markets throughout the U.S. Midwest and south to the Gulf of Mexico. This includes connecting supply in Texas, Oklahoma, the Appalachian basin and the Gulf of Mexico to markets in Wisconsin, Michigan, Illinois and Ohio. In addition, ANR has bidirectional capability on its Southeast Mainline and delivers gas produced from the Appalachian basin to customers throughout the U.S. Gulf Coast region.

100

%

U2.1

ANR Storage

247 Bcf

Provides regulated underground natural gas storage service from several facilities (not all shown) to customers in key mid-western markets.

100

%

U3

Columbia Gulf

5,419 km (3,367 miles)

Transports natural gas to various markets and pipeline interconnects in the southern U.S. and U.S. Gulf Coast. This pipeline system transports growing Appalachian basin supplies to various U.S. Gulf Coast markets and LNG export terminals from its interconnections with Columbia Gas and other pipelines.

60

%

U4

Great Lakes

3,404 km (2,115 miles)

Connects with the Canadian Mainline near Emerson, Manitoba and to Great Lakes Canada near St Clair, Ontario, plus interconnects with ANR at Crystal Falls and Farwell in Michigan, to transport natural gas to eastern Canada and the U.S. Midwest.

100

%

U5

Northern Border

2,272 km (1,412 miles)

Transports WCSB, Bakken and Rockies natural gas from connections with Foothills and Bison to U.S. Midwest markets.

50

%

U6

GTN

2,216 km (1,377 miles)

Transports WCSB and Rockies natural gas to Washington, Oregon and California. Connects with Tuscarora and Foothills.

100

%

U7

Iroquois

669 km (416 miles)

Connects with the Canadian Mainline and serves markets in New York.

50

%

U8

Tuscarora

491 km (305 miles)

Transports natural gas from GTN at Malin, Oregon to markets in northeastern California and northwestern Nevada.

100

%

U9

Bison

488 km (303 miles)

Transports natural gas from the Powder River basin in Wyoming to Northern Border in North Dakota.

100

%

U10

Millennium

424 km (263 miles)

Transports natural gas primarily sourced from the Marcellus shale play to markets across southern New York and the lower Hudson Valley, as well as to New York City through its pipeline interconnections.

47.5

%

U11

Crossroads

325 km (202 miles)

Interstate natural gas pipeline operating in Indiana and Ohio with multiple interconnects to other pipelines.

100

%

U12

North Baja1

138 km (86 miles)

Transports natural gas between Arizona and California and connects with a third-party pipeline on the California/Mexico border.

100

%

U13

Gillis Access

68 km (42 miles)

A pipeline system that connects supplies from the Haynesville basin at Gillis, Louisiana to markets elsewhere in Louisiana.

100

%

TC Energy Management's discussion and analysis 2025 | 39

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Length

Description

Ownership

Mexico pipelines

M1

Sur de Texas

770 km (478 miles)

Offshore pipeline that transports natural gas from the U.S./ Mexican border near Brownsville, Texas, to Mexican power plants in Altamira, Tamaulipas and Tuxpan, Veracruz, where it interconnects with the Tamazunchale and Tula pipelines and other third-party facilities. This offshore pipeline transports natural gas from the Texas border to power and industrial markets in the eastern and central regions of Mexico.

60

%

M2

Southeast Gateway

715 km (444 miles)

Offshore pipeline that connects to the Tula pipeline and transports gas to delivery points in Coatzacoalcos, Veracruz and Paraíso, Tabasco in Mexico’s southeast region.

86.99

%

M3

Topolobampo

572 km (355 miles)

Transports natural gas to El Oro and Topolobampo, Sinaloa, from interconnects with third-party pipelines in El Encino, Chihuahua and El Oro. The system supplies power plants and industrial facilities.

100

%

M4

Mazatlán

430 km (267 miles)

Transports natural gas from El Oro to Mazatlán, Sinaloa, interconnects with third-party pipelines and connects to the Topolobampo pipeline at El Oro. The system supplies power plants and industrial facilities.

100

%

M5

Tamazunchale

370 km (230 miles)

Transports natural gas from Naranjos, Veracruz and Higueros (Sur de Texas-Tuxpan System) to Tamazunchale, San Luis Potosi and on to El Sauz, Querétaro in central Mexico. The system supplies power plants and industrial facilities.

86.99

%

M6

Villa de Reyes – North and Lateral sections

316 km (196 miles)

The north and lateral sections of the Villa de Reyes pipeline are interconnected to our Tamazunchale pipeline and third-party systems, supporting gas deliveries to power plants in Villa de Reyes, San Luis Potosí and Salamanca, Guanajuato.

86.99

%

M7

Guadalajara

313 km (194 miles)

Bidirectional pipeline that connects imported LNG supply near Manzanillo and continental gas supply near Guadalajara to power plants and industrial customers in the states of Colima and Jalisco.

100

%

M8

Tula – East section

114 km (71 miles)

The east section of the Tula pipeline transports natural gas from Sur de Texas to power plants in Tuxpan, Veracruz.

86.99

%

Under construction

Canadian pipelines

NGTL System2,3,4

35 km (22 miles)

Includes expansion facilities, the Berland River compressor unit of the VNBR project and portions of the MYGP, with targeted in-service dates beginning in 2026.

100

%

NGTL System – MYGP2,3,4

n/a

A plan of multiple distinct projects for expansion facilities on the NGTL System with targeted in-service dates between 2027 and 2030.

Coastal GasLink – Cedar Link project2,3

n/a

The Cedar Link project is an expansion of the Coastal GasLink pipeline that is expected to enable delivery of up to 0.4 Bcf/d of natural gas to the Cedar LNG facility. This includes the addition of a new compressor station, connector pipeline and meter station to Coastal GasLink's existing pipeline infrastructure, which is expected to be placed in service in 2028.

35

%

40 | TC Energy Management's discussion and analysis 2025

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Under construction (continued)

Length

Description

Ownership

U.S. pipelines

U14

Gillis Access – Extension2,3

63 km (39 miles)

An extension of Gillis Access to further connect supplies from Haynesville basin at Gillis with anticipated in-service dates starting in late 2026.

100

%

Bison XPress Project1,2

n/a

A project with Northern Border, a 50 per cent owned subsidiary, and Bison, a wholly-owned subsidiary, that will replace and upgrade certain facilities while improving reliability, which is expected to be placed in service in 2026.

Various

Mexico pipelines

M9

Villa de Reyes – South section

110 km (68 miles)

This pipeline section will connect to the operational north and lateral sections of the Villa de Reyes pipeline and to the Tula pipeline.

86.99

%

Permitting and pre-construction phase

Canadian pipelines

NGTL System – MYGP2,3,4

54 km (34 miles)

Includes portions of the MYGP expansion facilities with targeted in-service dates beginning in 2027.

100

%

U.S. pipelines

Pulaski Project2,3

64 km (40 miles)

A pipeline extension project on our Columbia Gulf system designed to serve existing power plants. The project is expected to be placed in service in 2029.

60

%

Maysville Project2,3

64 km (40 miles)

A pipeline extension project on our Columbia Gulf system designed to serve existing power plants. The project is expected to be placed in service in 2029.

60

%

TCO Connector

45 km (28 miles)

A pipeline extension project on our Columbia Gas system designed to service a new gas-fired power plant. The project is expected to be placed in service 2030.

60

%

Southeast Virginia Energy Storage Project2

1.1 Bcf

An LNG storage facility located on our Columbia Gas system in southeast Virginia designed to serve an existing LDC's growing market. The project is expected to be placed in service in 2030.

60

%

Heartland Project1,2

n/a

An expansion project on our ANR system that is designed to increase capacity and improve system reliability with upgrades to compression facilities, expected to be placed in service in 2027.

100

%

Northwoods Project1,2

n/a

An expansion project on our ANR system that is designed to increase capacity to serve natural gas-fired electric generation demand in the U.S. Midwest, including data centres and overall economic growth. The project is expected to be placed in service in 2029.

100

%

Mexico pipelines

M10

Tula3

100 km (62 miles)

TC Energy and the CFE are assessing options to complete the remaining sections of the pipeline, which are subject to FID.

86.99

%

1Includes compressor station modifications, additions and/or expansion projects with no additional pipe length.

2Facilities and some pipelines are not shown on the map.

3Final pipe lengths are subject to change during construction and/or final design considerations.

4Includes projects within the MYGP that have received FID.

TC Energy Management's discussion and analysis 2025 | 41

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Canadian Natural Gas Pipelines

UNDERSTANDING OUR CANADIAN NATURAL GAS PIPELINES SEGMENT

The Canadian Natural Gas Pipelines business is subject to regulation by various federal and provincial governmental agencies. The CER has jurisdiction over our regulated Canadian natural gas interprovincial pipeline systems, while provincial regulators have jurisdiction over pipeline systems operating entirely within a single province. All of our major Canadian natural gas pipeline assets are regulated by the CER with the exception of the Coastal GasLink pipeline, which is regulated by the BC Energy Regulator.

For the interprovincial natural gas pipelines it regulates, the CER approves tolls, facilities and services that are in the public interest and provide a reasonable opportunity for the pipeline to recover its costs to operate the pipeline. Included in the overall toll is a return on the investment we have made in the assets, referred to as the return on equity. Generally, the CER has approved a deemed capital structure of 40 per cent equity and 60 per cent debt. Typically, tolls are based on the cost of providing service, including the cost of financing, divided by a forecast of volumes. Any variance in either costs or the actual volumes transported can result in an over-collection or under-collection of revenues that is normally trued up the following year in the calculation of the tolls for that period. The return on equity, however, would continue to be earned at the rate approved by the CER.

Subject to approval by the CER, we and our customers can also establish settlement arrangements that may have elements that vary from the typical toll-setting process. Settlements can include longer terms and mechanisms such as incentive agreements that can have an impact on the actual return on equity achieved. Examples include fixing the OM&A component in determining revenue requirements where variances are to the pipeline's account or shared between the pipeline and shippers.

The NGTL System is operating under the CER approved five-year negotiated revenue requirement settlement for 2025-2029     (the 2025-2029 NGTL Settlement), which commenced on January 1, 2025 and includes an approved ROE of 10.1 per cent on     40 per cent deemed common equity. This settlement provides the NGTL System with higher depreciation rates and the opportunity to further increase depreciation rates with an incentive if tolls fall below specified levels, or if growth projects are undertaken. It also includes incentive mechanisms to reduce both physical emissions and emission compliance costs, while also providing incentive for certain operating costs where variances from projected amounts and emissions savings are shared with customers. The Canadian Mainline is operating under the 2021-2026 Mainline settlement, which includes an incentive to decrease costs and increase revenues.

SIGNIFICANT EVENTS

NGTL System

In the year ended December 31, 2025, the NGTL System placed approximately $0.2 billion of capacity projects in service.

Multi-Year Growth Plan

The 2025-2029 NGTL Settlement enables an investment framework that supports our Board of Directors' approval to allocate up to $3.3 billion of capital towards progression of the MYGP for expansion facilities to meet commitments on the NGTL System. It is comprised of multiple distinct projects with various targeted in-service dates, subject to final company and regulatory approvals. To date, approximately $1.1 billion of MYGP expansion facilities have received FID, with various in-service dates starting in 2026. We continue to evaluate plans for each MYGP facility to optimize cost and schedule. Completion of the MYGP is expected to enable approximately 1.0 Bcf/d of incremental system throughput.

Valhalla North and Berland River Project

We continue to advance construction of the Valhalla North and Berland River project. The Valhalla section, which consists of approximately 33 km (21 miles) of new pipeline, was placed in service in third quarter 2025, with a capital cost of approximately $0.2 billion. The Berland River section, which includes a new non-emitting electric compressor unit and associated facilities, has a target in-service date in the second half of 2026 and an estimated capital cost of $0.3 billion. The project is designed to provide incremental capacity on the NGTL System of approximately 428 TJ/d (400 MMcf/d).

42 | TC Energy Management's discussion and analysis 2025

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Coastal GasLink

Coastal GasLink Pipeline

In October 2025, pursuant to the November 2024 commercial agreement executed with LNG Canada (LNGC) and each of the five LNGC participants, TC Energy received a one-time payment of $199 million in recognition of completed work and final cost settlement. This payment was recognized by TC Energy as an in-substance distribution from Coastal GasLink LP in our 2024 Consolidated financial statements.

Reclamation activities associated with post-construction work were completed in 2025. In addition, Coastal GasLink LP has resolved all material claims with a net positive recovery overall to Coastal GasLink LP. Refer to Note 30, Commitments, contingencies and guarantees, of our 2025 Consolidated financial statements for additional information.

Indigenous Equity Option

In March 2022, we announced the signing of option agreements to sell up to a 10 per cent equity interest in Coastal GasLink LP to Indigenous communities across the project corridor, from our current 35 per cent equity ownership. In January 2026, prospective investors entered into a binding window for these options, which is expected to remain in effect through to the end of 2026. Closing of the equity sale is subject to customary regulatory approvals and consents, including the consent of LNGC.

TC Energy Management's discussion and analysis 2025 | 43

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FINANCIAL RESULTS

The following is a reconciliation of comparable EBITDA and comparable EBIT (our non-GAAP measures) to segmented earnings (losses)(the most directly comparable GAAP measure). Refer to page 22 for more information on non-GAAP measures we use.

year ended December 31
(millions of $)						2025						2024						2023
NGTL System						2,586						2,393						2,201
Canadian Mainline						817						787						789
Other Canadian pipelines1						284						208						345
Comparable EBITDA						3,687						3,388						3,335
Depreciation and amortization						(1,523)						(1,382)						(1,325)
Comparable EBIT						2,164						2,006						2,010
Specific items:
Gain on sale of non-core assets						—						10						—
Coastal GasLink impairment charge						—						—						(2,100)
Segmented earnings (losses)						2,164						2,016						(90)

1Includes results from Foothills, Ventures LP, Great Lakes Canada and our proportionate share of income related to investments in TQM and Coastal GasLink, as well as general and administrative and business development costs related to our Canadian natural gas pipelines.

Canadian Natural Gas Pipelines segmented earnings were $2.2 billion in 2025 compared to $2.0 billion in 2024 and segmented losses of $0.1 billion in 2023, and included the following specific items, which have been excluded from our calculation of comparable EBITDA and comparable EBIT:

•a pre-tax gain on sale of non-core assets of $10 million in second quarter 2024

•a pre-tax impairment charge in 2023 of $2.1 billion related to our equity investment in Coastal GasLink LP.

Net income for our rate-regulated Canadian natural gas pipelines is primarily affected by our approved ROE, investment base, the level of deemed common equity and incentive earnings. Comparable EBITDA is impacted by these factors, as well as changes in depreciation, financial charges and income taxes. These additional items do not have a significant impact on net income as they are almost entirely recovered in revenues on a flow-through basis.

Net income and average investment base

year ended December 31
(millions of $)						2025						2024						2023
Net income
NGTL System						804						775						770
Canadian Mainline						258						244						230
Average investment base
NGTL System						19,277						19,334						19,008
Canadian Mainline						3,762						3,697						3,709

Net income for the NGTL System increased by $29 million in 2025 compared to 2024 primarily due to higher incentive earnings and increased by $5 million in 2024 compared to 2023 mainly due to a higher average investment base resulting from continued system expansions, partially offset by an incentive loss. The NGTL System is currently operating under the 2025-2029 NGTL Settlement, which commenced on January 1, 2025 and includes an approved ROE of 10.1 per cent on 40 per cent deemed common equity. This settlement provides the NGTL System with higher depreciation rates and the opportunity to further increase depreciation rates with an incentive if tolls fall below specified levels, or if growth projects are undertaken. It also includes incentive mechanisms to reduce both physical emissions and emission compliance costs, while also providing an incentive for certain operating costs where variances from projected amounts and emissions savings are shared with customers. Refer to the Canadian Natural Gas Pipelines - Significant events section for additional information.

44 | TC Energy Management's discussion and analysis 2025

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Net income for the Canadian Mainline increased by $14 million in 2025 compared to 2024 and by $14 million in 2024 compared to 2023 mainly as a result of higher incentive earnings. The Canadian Mainline is operating under the 2021-2026 Mainline Settlement, which includes an approved ROE of 10.1 per cent on 40 per cent deemed common equity and an incentive to decrease costs and increase revenues on the pipeline under a beneficial sharing mechanism with our customers.

Comparable EBITDA

Comparable EBITDA for Canadian Natural Gas Pipelines was $299 million higher in 2025 compared to 2024 primarily due to:

•higher flow-through depreciation and income taxes as well as higher incentive earnings, partially offset by lower flow-through financial charges and lower rate base earnings on the NGTL System

•higher contributions from Coastal GasLink mainly resulting from the declared commercial in-service of the pipeline in fourth quarter 2024

•higher incentive earnings, flow-through depreciation and income taxes on the Canadian Mainline.

Comparable EBITDA for Canadian Natural Gas Pipelines in 2024 was $53 million higher than 2023 primarily due to the
net effect of:

•higher flow-through income taxes, depreciation and financial charges, as well as higher rate-base earnings on the
NGTL System due to continued system expansions

•higher flow-through income taxes, financial charges and depreciation, as well as higher rate-base earnings on Foothills primarily due to the NGTL System/Foothills West Path Delivery Program completed in 2023

•earnings from Coastal GasLink in 2023 related to the recognition of a $200 million incentive payment upon meeting certain milestones.

Depreciation and amortization

Depreciation and amortization was $141 million higher in 2025 compared to 2024, primarily reflecting higher depreciation     rates on the NGTL System under the 2025-2029 NGTL Settlement. Depreciation and amortization was $57 million higher in 2024 compared to 2023, mainly due to incremental depreciation on the NGTL System from expansion facilities that were placed in service.

OUTLOOK

Comparable EBITDA and comparable earnings

Net income for Canadian rate-regulated pipelines is affected by changes in investment base, ROE and deemed capital structure, as well as by the terms of toll settlements approved by the CER. Under the current regulatory model, return on rate base from Canadian rate-regulated natural gas pipelines is not materially affected by short-term fluctuations in the commodity price of natural gas, changes in throughput volumes or changes in contracted capacity levels.

Canadian Natural Gas Pipelines comparable EBITDA in 2026 is expected to be higher than 2025 mainly due to higher contributions from the NGTL System. Due to the flow-through treatment of certain costs on our Canadian rate-regulated pipelines, changes in these costs can impact our comparable EBITDA despite having no significant effect on comparable earnings. We expect our comparable earnings in 2026 for the NGTL System and the Canadian Mainline to be consistent         with 2025.

Capital expenditures

We incurred $1.3 billion of capital expenditures in 2025 in our Canadian Natural Gas Pipelines business on growth projects and maintenance capital expenditures. We expect to incur approximately $1.5 billion in 2026, primarily on NGTL System expansion projects and maintenance capital expenditures, all of which are immediately reflected in investment base and related earnings.

TC Energy Management's discussion and analysis 2025 | 45

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U.S. Natural Gas Pipelines

UNDERSTANDING OUR U.S. NATURAL GAS PIPELINES SEGMENT

The U.S. interstate natural gas pipeline business is subject to regulation by various federal, state and local governmental agencies. FERC, however, has comprehensive jurisdiction over our U.S. interstate natural gas business. FERC approves maximum transportation rates that are cost-based and are designed to recover the pipeline's investment, operating expenses and a reasonable return for our investors. In the U.S., we have the ability to contract for negotiated or discounted rates with shippers.

FERC does not require U.S. interstate pipelines to calculate rates annually, nor do they generally allow for the collection or refund of the variance between actual and expected revenues and costs into future years. This difference in U.S. regulation from the Canadian regulatory environment puts our U.S. pipelines at risk for the difference in expected and actual costs and revenues between rate cases. If revenues no longer provide a reasonable opportunity to recover our costs, we can file with FERC for a new determination of rates, subject to any moratorium in effect. Similarly, FERC or our shippers may institute proceedings to lower rates if they consider the return on capital invested to be unjust or unreasonable.

Similar to Canada, we can also establish settlement arrangements with our U.S. shippers that are ultimately subject to approval by FERC. Rate case moratoriums for a period of time, before either we or the shippers can file for a rate review, are common for a settlement in that they provide some certainty for shippers in terms of rates, eliminate the costs associated with frequent rate proceedings for all parties and can provide an incentive for pipelines to lower costs.

PHMSA Pipeline Safety Regulations

Most of our U.S. natural gas pipeline systems are subject to federal pipeline safety statutes and regulations enacted and administered by PHMSA. PHMSA will continue to produce new rules affecting numerous aspects of operation and maintenance of our pipeline system. PHMSA’s priorities are generally dictated by legislation which is influenced by numerous stakeholders and informed by learnings from recent industry incidents and stakeholder priorities. When PHMSA implements new rules, TC Energy seeks recovery of additional expenditures driven by such rules in future rate cases and modernization settlements.

SIGNIFICANT EVENTS

Columbia Gas Section 4 Rate Case

Columbia Gas reached a settlement with its customers effective April 2025 and received FERC approval in October 2025. As part of the settlement, there is a moratorium on any further rate changes until March 31, 2028. 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. In fourth quarter 2025, previously accrued rate refund liabilities, including interest, were refunded to customers.

ANR and Great Lakes Section 4 Rate Cases

In April 2025, ANR and Great Lakes each filed Section 4 Rate Cases with FERC requesting an increase to their respective maximum transportation rates effective November 1, 2025, subject to refund. We will pursue a collaborative process to find a mutually beneficial outcome with our customers through settlement.

Northwoods Project

In April 2025, we approved the Northwoods project, an expansion project on our ANR system designed to provide 0.4 Bcf/d of capacity to serve natural gas-fired electric generation demand in the U.S. Midwest, including data centres and overall economic growth. The project involves pipeline looping, compressor facility additions as well as other system updates, with an anticipated in-service date of late 2029 and an estimated project cost of approximately US$0.9 billion.

East Lateral XPress

The East Lateral XPress project, an expansion project on the Columbia Gulf system that connects supply to U.S. Gulf Coast LNG export markets, was placed in service in May 2025, with a total project cost of approximately US$0.3 billion.

Ventura XPress Project

The Ventura XPress project, a set of ANR projects designed to improve base system reliability and allow for additional long-term contracted transportation services to a point of delivery on the Northern Border pipeline at Ventura, Iowa, was placed in service in October 2025 with a total project cost of approximately US$0.2 billion.

46 | TC Energy Management's discussion and analysis 2025

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TCO Connector Project

In October 2025, we approved the TCO Connector project on our Columbia Gas system. This project is designed to provide approximately 0.5 Bcf/d of capacity to serve new natural gas-fired power generation supporting forecasted electric generation growth, including expected data centre growth across our system. The project has an anticipated in-service date of 2030 and an estimated project cost of approximately US$0.3 billion.

VR and WR Projects

In November 2025, we placed the VR and WR projects into service. The VR project, provides incremental capacity from Greensville County, Virginia to delivery points in Norfolk, Virginia, with a total project cost of approximately US$0.5 billion.     The WR project, provides mainline capacity to multiple points of delivery on our ANR System in Wisconsin with a total project cost of approximately US$0.7 billion.

TC Energy Management's discussion and analysis 2025 | 47

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FINANCIAL RESULTS

The following is a reconciliation of comparable EBITDA and comparable EBIT (our non-GAAP measures) to segmented earnings (losses) (the most directly comparable GAAP measure). Refer to page 22 for more information on non-GAAP measures we use.

year ended December 31
(millions of US$, unless otherwise noted)						2025						2024						2023
Columbia Gas1						1,803						1,600						1,530
ANR						651						642						650
Columbia Gulf1						235						235						208
Great Lakes						191						204						183
GTN						263						188						202
PNGTS1,2						—						66						104
Other U.S. pipelines3						363						359						371
Comparable EBITDA						3,506						3,294						3,248
Depreciation and amortization						(743)						(697)						(692)
Comparable EBIT						2,763						2,597						2,556
Foreign exchange impact						1,106						959						895
Comparable EBIT (Cdn$)						3,869						3,556						3,451
Specific items:
Gain on sale of PNGTS						—						572						—
Gain on sale of non-core assets						—						38						—
Risk management activities						58						(113)						80
Segmented earnings (losses) (Cdn$)						3,927						4,053						3,531

1Includes non-controlling interest. Refer to the Corporate - Financial results section for additional information.

2The sale of PNGTS was completed in August 2024.

3Reflects comparable EBITDA from our ownership in our mineral rights business (CEVCO), North Baja, Gillis Access, Tuscarora, Bison, Crossroads and our share of equity income from Northern Border, Iroquois, Millennium and Hardy Storage, our U.S. natural gas marketing business, as well as general and administrative and business development costs related to our U.S. natural gas pipelines.

U.S. Natural Gas Pipelines segmented earnings in 2025 decreased by $126 million compared to 2024 and increased by         $522 million in 2024 compared to 2023 and included the following specific items, which have been excluded from our calculation of comparable EBITDA and comparable EBIT:

•a pre-tax gain of $572 million related to the sale of PNGTS in August 2024

•a pre-tax gain on sale of a non-core asset of $38 million in second quarter 2024

•unrealized gains and losses from changes in the fair value of derivatives used in our U.S. natural gas marketing business.

A stronger U.S. dollar in 2025 and 2024 had a positive impact on the Canadian dollar equivalent segmented earnings from our U.S. dollar-denominated operations. Refer to the Foreign exchange section for additional information.

Earnings from our U.S. Natural Gas Pipelines operations are generally affected by contracted volume levels, volumes delivered and the rates charged, as well as by the cost of providing services. Columbia Gas and ANR results are also affected by the contracting and pricing of their natural gas storage capacity and incidental commodity sales. Natural gas pipeline and storage volumes and revenues are generally higher in the winter months because of the seasonal nature of the business.

48 | TC Energy Management's discussion and analysis 2025

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Comparable EBITDA for U.S. Natural Gas Pipelines was US$212 million higher in 2025 than 2024 primarily due to the net effect of:

•a net increase in earnings from Columbia Gas as a result of higher transportation rates effective April 1, 2025, pursuant to the Columbia Gas Settlement. Refer to the U.S. Natural Gas Pipelines – Significant events section for additional information

•incremental earnings from projects placed in service, as well as increased earnings from additional contract sales on GTN

•increased earnings from our mineral rights business due to higher commodity prices

•decreased earnings as a result of the sale of our 61.7 per cent equity interest in PNGTS, which was completed in August 2024

•decreased equity earnings from Iroquois and Millennium

•decreased earnings due to higher operational costs, reflective of system utilization and projects placed in service across our footprint.

Comparable EBITDA for U.S. Natural Gas Pipelines was US$46 million higher in 2024 than 2023 primarily due to the net effect of:

•incremental earnings from growth and modernization projects placed in service, as well as increased earnings from additional contract sales on ANR and Great Lakes

•increased equity earnings from Northern Border

•decreased earnings due to higher operational costs, reflective of increased system utilization across our footprint

•decreased earnings as a result of the sale of our 61.7 per cent equity interest in PNGTS, which was completed in August 2024

•lower realized earnings related to our U.S. natural gas marketing business primarily due to lower margins

•reduced earnings from our mineral rights business due to lower commodity prices.

Depreciation and amortization

Depreciation and amortization was US$46 million higher in 2025 compared to 2024 and US$5 million higher in 2024 compared to 2023. The increase in depreciation is primarily due to new projects placed in service and depreciation rate changes as a result of the Columbia Gas Settlement, partially offset by the impact of the sale of PNGTS in 2024.

OUTLOOK

Comparable EBITDA

Our U.S. natural gas pipelines are largely backed by long-term take-or-pay contracts that are expected to deliver stable and consistent financial performance. Our ability to retain customers and recontract or sell capacity at favourable rates is influenced by prevailing market conditions and competitive factors, including alternatives available to end-use customers in the form of competing natural gas pipelines and supply sources, as well as broader conditions that impact demand from certain customers or market segments. Comparable EBITDA is also affected by operational and other costs, which can be impacted by safety, environmental and other regulatory decisions, as well as customer credit risk.

U.S. Natural Gas Pipelines comparable EBITDA in 2026 is expected to be higher than 2025 primarily due to full year in-service of the East Lateral XPress, Ventura XPress, VR and WR projects, as well as a full year of increased rates on Columbia Gas as a result of the Columbia Gas Settlement. Our pipeline systems continue to see historically strong demand for service and we anticipate that during 2026, our assets will maintain the high utilization levels experienced in 2025. These positive results are expected to be partially offset by higher operational costs, reflective of continued increases to system utilization across our footprint and an anticipated increase in property taxes from capital projects placed in service.

Capital expenditures

We incurred a total of US$2.4 billion of capital expenditures in 2025 on our U.S. natural gas pipelines and expect to incur approximately US$2.4 billion in 2026 primarily on our Columbia Gas and ANR expansion projects and Gillis Access expansion project, as well as Columbia Gas and ANR maintenance capital expenditures, the return on and recovery of which, is expected to be reflected in future tolls. We expect net capital expenditures in 2026 to be approximately US$2.0 billion after considering capital expenditures attributable to the non-controlling interests of entities we control.

TC Energy Management's discussion and analysis 2025 | 49

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Mexico Natural Gas Pipelines

UNDERSTANDING OUR MEXICO NATURAL GAS PIPELINES SEGMENT

For over a decade, Mexico has been undergoing a significant transition from fuel oil and diesel as its primary energy sources for electric generation to using natural gas. As a result, new natural gas pipeline infrastructure has been and continues to be required to meet the growing demand for natural gas. The CFE, Mexico's state-owned electric utility, is the primary counterparty on all of our existing pipelines under long-term contracts, which are predominately denominated in U.S. dollars. These fixed-rate contracts are generally designed to recover the cost of service and provide a return on and of invested capital. As the pipeline developer and operator, we are generally at risk for operating and construction costs. Our Mexico pipelines also have regulatory approved tariffs, services and related rates for other potential users.

SIGNIFICANT EVENTS

TGNH Strategic Alliance with the CFE

The Southeast Gateway pipeline is in service and we commenced the collection of tolls beginning May 2025. In July 2025, the newly constituted CNE approved our regulated rates required to provide service to potential future interruptible service users on the Southeast Gateway pipeline other than the CFE.

In 2024, the CFE became an equity partner in TGNH with a 13.01 per cent equity interest. The CFE's equity in TGNH is expected to increase to a maximum of 15 per cent, subject to regulatory approvals, and will increase to approximately 35 per cent upon expiry of the contract in 2055.

50 | TC Energy Management's discussion and analysis 2025

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FINANCIAL RESULTS

The following is a reconciliation of comparable EBITDA and comparable EBIT (our non-GAAP measures) to segmented earnings (losses) (the most directly comparable GAAP measure). Refer to page 22 for more information on non-GAAP measures we use.

year ended December 31
(millions of US$, unless otherwise noted)						2025						2024						2023
TGNH1,2						625						231						232
Sur de Texas3						79						220						75
Topolobampo						154						156						157
Guadalajara						57						56						61
Mazatlán						66						67						71
Comparable EBITDA						981						730						596
Depreciation and amortization						(69)						(67)						(66)
Comparable EBIT						912						663						530
Foreign exchange impact						357						244						186
Comparable EBIT (Cdn$)						1,269						907						716
Specific item:
Expected credit loss provision on net investment in leases and certain contract assets in Mexico2						(83)						22						80
Segmented earnings (losses) (Cdn$)						1,186						929						796

1Includes the operating sections of the Tamazunchale, Villa de Reyes, Tula and Southeast Gateway pipelines.

2Includes non-controlling interest. Refer to the Corporate - Financial results section for additional information.

3Represents equity income from our 60 per cent interest and fees earned from the construction and operation of the pipeline.

Mexico Natural Gas Pipelines segmented earnings in 2025 increased by $257 million compared to 2024 and increased by         $133 million in 2024 compared to 2023 and included an expense of $83 million in 2025 (2024 – $22 million recovery;         2023 – $80 million recovery) on the expected credit loss provision related to the TGNH net investment in leases and certain contract assets in Mexico, which we have excluded from our calculation of comparable EBITDA and comparable EBIT. Refer to Note 27, Risk management and financial instruments, of our 2025 Consolidated financial statements for additional information.

A stronger U.S. dollar in 2025 and 2024 had a positive impact on the Canadian dollar equivalent segmented earnings from our U.S. dollar-denominated operations in Mexico. Refer to the Foreign exchange section for additional information.

Comparable EBITDA for Mexico Natural Gas Pipelines increased by US$251 million in 2025 compared to 2024 mainly due to the net effect of:

•higher earnings in TGNH due to the completion of the Southeast Gateway pipeline in second quarter 2025

•lower equity earnings from Sur de Texas primarily due to the foreign exchange impacts on the revaluation of peso‑denominated liabilities as a result of a stronger Mexican peso and higher income tax expense mainly related to the    foreign exchange impacts of U.S. dollar-denominated liabilities.

Comparable EBITDA for Mexico Natural Gas Pipelines increased by US$134 million in 2024 compared to 2023 primarily due to:

•higher equity earnings in Sur de Texas primarily due to the foreign exchange impacts on the revaluation of peso-denominated liabilities as a result of a weaker Mexican peso and lower income tax expense mainly related to the foreign exchange impacts of U.S. dollar-denominated liabilities

•lower earnings from Guadalajara primarily due to lower fixed revenue in accordance with the transportation contract and higher operating costs.

Depreciation and amortization

Depreciation and amortization was generally consistent between 2025 and 2024 and between 2024 and 2023. Under sales-type lease accounting, our in-service TGNH pipeline assets are derecognized from Plant, property and equipment and recorded as a net investment in lease on our Consolidated balance sheet with no depreciation expense being recognized.

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Sur de Texas results

Sur de Texas results reflect equity income from our 60 per cent interest and fees earned from the construction and operation of the pipeline. We use foreign exchange derivatives to manage Sur de Texas' foreign exchange exposures, and the impact of these derivatives is recognized in Foreign exchange (gains) losses, net in the Consolidated statement of income. Refer to the Foreign exchange section for additional information.

The following table details our proportionate share of equity income and the foreign exchange impact on Sur de Texas equity earnings from changes in the value of the Mexican peso against the U.S. dollar:

year ended December 31
(millions of US$)						2025						2024						2023
Equity income before foreign exchange impact						136						137						137
Foreign exchange impact included in equity earnings						(57)						83						(62)
Comparable EBITDA - Sur de Texas						79						220						75

OUTLOOK

Comparable EBITDA

Mexico Natural Gas Pipelines comparable EBITDA reflects long-term, stable, principally U.S. dollar-denominated transportation contracts that are affected by the cost of providing service and includes our share of equity income from our 60 per cent equity interest in the Sur de Texas pipeline. Due to the long-term nature of the underlying transportation contracts, comparable EBITDA is generally consistent year-over-year except when new assets are placed in service. Comparable EBITDA for 2026 is expected to be higher than 2025 due to the Southeast Gateway project, which was completed in second quarter 2025.

Capital expenditures

We incurred US$0.2 billion of capital expenditures in 2025 primarily related to the construction of the Southeast Gateway pipeline and maintenance capital expenditures. We expect to incur approximately US$0.2 billion in 2026 to finalize construction of pipeline projects in Mexico.

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NATURAL GAS PIPELINES – BUSINESS RISKS

The following are risks specific to our Natural Gas Pipelines business. Refer to page 94 for information about general risks related to TC Energy as a whole, including other operational, safety and financial risks, as well as our approach to risk management.

Production levels within supply basins

The NGTL System and our pipelines downstream depend largely on supply from the WCSB. Columbia Gas and its connecting pipelines largely depend on Appalachian supply. We continue to monitor any changes in our customers' natural gas production plans and how these may impact our existing assets and new project schedules. There is competition amongst pipelines to connect to major basins. An overall decrease in production and/or increased competition for supply could reduce throughput on our connected pipelines that, in turn, could negatively impact overall revenues generated. The WCSB and Appalachian basins are two of the most prolific and cost-competitive basins in North America and have considerable natural gas reserves. However, the amount actually produced depends on many variables including the price of natural gas and natural gas liquids, basin-on-basin competition, pipeline and gas-processing tolls, demand within the basin, changes in policy and regulations and the overall value of the reserves, including liquids content.

Market access

We compete for market share with other natural gas pipelines. New supply basins are being developed closer to markets we have historically served and may reduce the throughput and/or distance of haul on our existing pipelines and impact revenues. New markets, including those created by LNG export facilities developed to access global natural gas demand, can lead to increased revenues through higher utilization of existing facilities and/or demand for new infrastructure. The long-term competitiveness of our pipeline systems and the avoidance of bypass pipelines will depend on our ability to adapt to changing flow patterns by offering competitive transportation services to the market. As part of our annual strategic planning process, we evaluate the resilience of our asset portfolio over a range of potential energy supply and demand outcomes.

Competition for greenfield pipeline expansion

We face competition from other pipeline companies seeking to invest in greenfield natural gas pipeline development opportunities. This competition could result in fewer available projects that meet our investment hurdles or projects that proceed with lower overall financial returns. While renewable deployments are expected to garner an increasing portion of future energy needs, including in the power generation sector, aggregate natural gas demand across all sectors, including LNG exports, is still projected to grow under the most aggressive renewable deployment forecasts. The reliability of natural gas is an important factor in the successful wide-scale deployment of renewables with more intermittent capabilities.

Demand for pipeline capacity

Demand for pipeline capacity ultimately drives the sale of pipeline transportation services and is impacted by supply and market competition, variations in economic activity, weather variability, natural gas pipeline and storage competition, energy conservation, as well as demand for and prices of alternative sources of energy. Renewal of expiring contracts and the opportunity to charge a competitive toll depends on the overall demand for transportation service. A decrease in the level of demand for our pipeline transportation services could adversely impact revenues, although overall utilization of our pipeline capacity continues to grow and warrant further investment and expansion.

Commodity prices

The cyclical supply and demand nature of commodities and related pricing can have a secondary impact on our business where our shippers may choose to accelerate or delay certain projects. This can impact the timing of demand for transportation services and/or new natural gas pipeline infrastructure. Disruptions in the energy supply chain can result in price volatility and a decline in natural gas prices that could impact our shippers' financial condition and their ability to meet their transportation service cost obligations.

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Regulatory risk

Decisions and evolving policies by regulators and other government authorities, including changes in regulation, can impact the approval, timing, construction, operation and financial performance of our natural gas pipelines. There is a risk that decisions are delayed or are not favourable and could therefore adversely impact construction costs, in-service dates, anticipated revenues and the opportunity to further invest in our systems. There is also risk of a regulator disallowing recovery of a portion of our costs, now or at some point in the future.

The regulatory approval process for larger infrastructure projects, including the time it takes to receive a decision, could be delayed or lead to an unfavourable decision due to evolving public opinion and government policy related to natural gas pipeline infrastructure development. If regulatory decisions are subsequently challenged in courts, this could result in further impacts to project costs and schedule delays.

Increased scrutiny of construction and operations processes by the regulator or other enforcing agencies has the potential to delay construction, increase operating costs or require additional capital investment. There is a risk of an adverse impact to income if these costs are not fully recoverable and/or reduce the competitiveness of tolls charged to customers.

We continuously manage these risks by monitoring legislative and regulatory developments and decisions to determine the possible impact on our natural gas pipelines business and developing rate, facility and tariff applications that account for and mitigate these risks where possible.

Governmental risk

Shifts in government policy or changes in government can impact our business. More complex regulatory processes, broader consultation requirements, more restrictive emissions and/or carbon pricing policies and changes to environmental regulations can impact our operations and opportunities for continued growth. We are committed to working with all levels of government to ensure our business benefits and risks are understood and mitigation strategies are implemented.

Construction and operations

Constructing and operating our pipelines to ensure transportation services are provided safely and reliably is essential to the success of our business. Interruptions in our pipeline operations impacting throughput capacity may result in reduced revenues and can affect corporate reputation, as well as customer and public confidence in our operations. We manage this by investing in a highly skilled workforce, hiring third-party inspectors during construction, operating prudently, monitoring our pipeline systems continuously, using risk-based preventive maintenance programs and making effective capital investments. We use pipeline inspection equipment to regularly check the integrity of our pipelines and repair or replace sections when necessary.     We also calibrate meters regularly to ensure accuracy and employ robust reliability and integrity programs to maintain compression equipment and safe and reliable operations.

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Power and Energy Solutions

The Power and Energy Solutions business consists of power generation, non-regulated natural gas storage assets, as well as emerging technologies that can provide lower-carbon solutions for our customers and industry.

Our Power and Energy Solutions business includes approximately 4,650 MW of generation powered by nuclear, natural gas, wind and solar. These generation assets are generally supported by long-term contracts. Our Canadian power infrastructure assets are located in Alberta, Ontario, Québec and New Brunswick while our U.S. power infrastructure assets are located in Texas. Additionally, we have approximately 400 MW of PPAs in Canada and approximately 350 MW of PPAs in the U.S. from wind and solar facilities.

We also own and operate approximately 118 Bcf of non-regulated natural gas storage capacity in Alberta.

Strategy

Our strategy is to maximize the value of our existing portfolio through maintaining safety and operational excellence while enhancing the life cycle and reliability of our assets and expanding profit margins through cost efficiency and revenue enhancement. Our business is anchored by nuclear generation and designed for scalable, low-risk growth that adapts to evolving energy needs. By leveraging our expertise across natural gas and power, we capture additional value through commercial marketing and system optimization, while maximizing availability of our cogeneration fleet. In the long term, we believe there will be a growing need for a reliable supply of resources as the energy mix evolves. We are positioning ourselves to play an important role in decarbonizing energy sources and will continue to build expertise and capabilities in emerging technologies and markets that offer commercial frameworks consistent with TC Energy’s value proposition of low risk, solid growth and repeatable performance.

Recent highlights

•Bruce Power completed planned outages on Units 2 and 5 in 2025

•Bruce Power received verification of the Unit 5 MCR final cost and schedule estimate from the IESO on April 2, 2025.

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UNDERSTANDING OUR POWER AND ENERGY SOLUTIONS BUSINESS

Canadian Power

Canadian Power Generation & Marketing

We own and operate approximately 1,200 MW of power supply in Canada, excluding our investment in Bruce Power. In Alberta we own five facilities: four natural gas-fired cogeneration and one solar. We exercise a disciplined operating strategy to maximize revenues. Our marketing group sells uncommitted power while also buying and selling power and natural gas to maximize earnings. To reduce commodity price exposure associated with uncontracted power, we sell a portion of this output in forward sales markets when acceptable contract terms are available while the remainder is retained to be sold in the spot market or under short-term forward arrangements. The objective of this strategy is to maintain adequate power supply to fulfill our sales obligations if we have unexpected plant outages and enable us to capture opportunities to increase earnings in periods of high spot prices.

Bruce Power

Bruce Power is a nuclear power generation facility located near Tiverton, Ontario and is comprised of eight nuclear units with a combined capacity of approximately 6,580 MW. Bruce Power leases the facilities from OPG, has no spent fuel risk and will return the facilities to OPG for decommissioning at the end of the lease. We have a 48.3 per cent equity interest in Bruce Power.

Results from Bruce Power will fluctuate primarily due to units being offline for the MCR program and the frequency, scope and duration of planned and unplanned maintenance outages.

Through a long-term agreement with the IESO, Bruce Power is progressing a series of incremental life-extension investments to extend the operating life of the facility to 2064. This agreement represents an extension and material amendment to the earlier agreement that led to the refurbishment of Units 1 and 2 at the site. Under the amended agreement, which took economic effect in 2016, Bruce Power began investing in life extension activities for Units 3 through 8 to support the long-term refurbishment programs, known as the Asset Management program. Investment in the Asset Management program is designed to result in near-term life extensions of each of the six units up to the planned major refurbishment outages and beyond. The Asset Management program includes the one-time refurbishment or replacement of systems, structures or components that are not within the scope of the MCR program, which focuses on the actual replacement of the key, life-limiting reactor components. The MCR program is designed to add at least 35 years of operational life to each of the six units.

The Unit 6 MCR, the first of the six-unit MCR life extension program, was completed in third quarter 2023. The Unit 3 MCR and Unit 4 MCR, which are the second and third unit in the MCR program, commenced in first quarter 2023 and 2025, with expected completion dates in 2026 and 2028, respectively. The Unit 5 MCR final cost and schedule estimate was verified by the IESO on April 2, 2025. The Unit 5 MCR is expected to commence in fourth quarter 2026 with a return to service in early 2030. Investments in the remaining two units' MCR programs are expected to continue through 2033. Future MCR investments will be subject to discrete decisions for each unit with specified off-ramps available for Bruce Power and the IESO.

Along with the MCR life extension program, Bruce Power’s Project 2030 has a goal of achieving site peak output (capability) of 7,000 MW by 2033 in support of the province of Ontario's climate change targets and future clean energy needs. Project 2030 is focused on continued asset optimization, innovation and leveraging new technology to increase site capability. Project 2030 is being implemented in three stages with the first two stages and Stage 3a fully approved for execution. The program commenced in 2019 with a site capability of 6,430 MW and closed out 2025 at approximately 6,580 MW; a net gain of approximately 150 MW. Upon completion of Stage 1, 2 and 3a, the site is projected to reach 6,840 MW. All three stages are being implemented in parallel to the MCR program.

As part of the life extension and refurbishment agreement, Bruce Power receives a uniform contract price for all units which includes certain flow-through items such as fuel and lease expense recovery. The contract also provides for payment if the IESO requests a reduction in Bruce Power’s generation to balance the supply of and demand for, electricity and/or manage other operating conditions of the Ontario power grid. The amount of the reduction is considered deemed generation, for which Bruce Power is paid the contract price.

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The contract price is subject to adjustments for the return of and on capital invested at Bruce Power under the Asset Management and MCR programs, along with various other pricing adjustments that allow for a better matching of revenues and costs over the long term. As part of the amended agreement, Bruce Power is also required to share operating cost efficiencies with the IESO for better than planned performance. These efficiencies are reviewed every three years and paid out on a monthly basis over the subsequent three-year period. No operating cost efficiencies for the 2025 to 2027 period have been provided for at December 31, 2025 and no operating cost efficiencies were realized for the 2019 to 2024 period.

Bruce Power is a global supplier of Cobalt-60, a medical isotope used in the sterilization of medical equipment and to         treat certain types of cancer. Cobalt-60 is produced during Bruce Power’s generation of electricity, harvested during certain         planned maintenance outages and provided for medical use in the treatment of brain tumours and breast cancer. In addition, Bruce Power harvests Lutetium-177, a medical isotope used in the treatment of prostate cancer and neuroendocrine tumours. Lutetium-177 is generated and harvested while Bruce Power is generating electricity. Isotope production includes a partnership with the Saugeen Ojibway Nation, on whose traditional territory the Bruce Power facilities are located. Furthermore,         Bruce Power has committed to building a hot cell facility in Bruce County, for the purposes of streamlining the supply chain for the short-lived Lutetium-177 to ensure it reaches cancer patients around the world in a timely fashion.

Power Purchase Agreements

We have approximately 400 MW of wind and solar generation PPAs and associated environmental attributes in Alberta. These PPAs allow us to generate incremental earnings by offering renewable power products to our customers.

U.S. Power

Power Generation & Marketing

We own approximately 300 MW of wind generation located in Texas which operate in the Electric Reliability Council of Texas (ERCOT) and Southwest Power Pool (SPP) markets. A portion of this power generation is sold under a long-term, fixed price contract.

Our U.S. Power and emissions commercial trading and marketing business optimizes the value of our assets and leverages physical and financial products in the power and environmental markets with a focus on risk management.

Power Purchase Agreements

We have approximately 350 MW of wind generation PPAs and associated environmental attributes in the U.S. These PPAs allow us to generate incremental earnings by offering renewable power products to our customers.

Other Energy Solutions

Canadian Natural Gas Storage

Our Canadian natural gas storage business helps balance seasonal and short-term supply and demand while also adding flexibility to the delivery of natural gas to markets in Alberta and the rest of North America. Market volatility creates arbitrage opportunities and our natural gas storage facilities also give us and our customers the ability to capture value from short-term price movements. The natural gas storage business is affected by changes in seasonal natural gas price spreads which are generally determined by the differential in natural gas prices between the traditional summer injection and winter withdrawal seasons. In addition, the business may be affected by pipeline restrictions in Alberta which limit the ability to capture price differentials.

Our natural gas storage business contracts with third parties, typically participants in the Alberta and interconnected gas markets, for a fixed fee to provide natural gas storage services on a short, medium and/or long-term basis.

We also enter proprietary natural gas storage transactions which include a forward purchase of our own natural gas to be injected into storage and a simultaneous forward sale of natural gas for withdrawal at a later period, typically during the winter withdrawal season. By matching purchase and sales volumes on a back-to-back basis, we lock in future positive margins, effectively eliminating our exposure to changes in natural gas prices for these transactions.

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Power and Energy Solutions assets currently have a combined power generation capacity, net to TC Energy, of 4,652 MW.    We operate each facility except for Bruce Power.

						Generating  capacity (MW)												Type of fuel						Description						Ownership
Power assets
1						Bruce Power1						3,180						nuclear						Eight operating reactors in Tiverton, Ontario. Bruce Power leases the nuclear facilities from OPG.						48.3		%
2						Bécancour						550						natural gas						Cogeneration plant in Trois-Rivières, Québec. Power generation has been suspended since 2008 although we continue to receive PPA capacity payments while generation is suspended.						100		%
3						Mackay River						207						natural gas						Cogeneration plant in Fort McMurray, Alberta.						100		%
4						Fluvanna2						155						wind						Wind farm located near Scurry County, Texas.						100		%
5						Blue Cloud2						148						wind						Wind farm located near Bailey County, Texas.						100		%
6						Bear Creek						100						natural gas						Cogeneration plant in Grande Prairie, Alberta.						100		%
7						Carseland						95						natural gas						Cogeneration plant in Carseland, Alberta.						100		%
8						Grandview						90						natural gas						Cogeneration plant in Saint John, New Brunswick.						100		%
9						Saddlebrook Solar						81						solar						Hybrid solar generation facility near Aldersyde, Alberta.						100		%
10						Redwater						46						natural gas						Cogeneration plant in Redwater, Alberta.						100		%
Canadian non-regulated natural gas storage
11						Crossfield						68 Bcf												Underground facility connected to the NGTL System near Crossfield, Alberta.						100		%
12						Edson						50 Bcf												Underground facility connected to the NGTL System near Edson, Alberta.						100		%
Under construction
Other energy solutions
13						Lynchburg												RNG						RNG production facility in Lynchburg, Tennessee.						30		%

1Our share of power generation capacity.

2TC Energy owns 100 per cent of the Class B Membership Interests and has a tax equity investor that owns 100 per cent of the Class A Membership Interests, to which a percentage of earnings, tax attributes and cash flows are allocated under the provisions of each tax equity agreement.

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SIGNIFICANT EVENTS

Bruce Power Life Extension

Bruce Power received verification of the Unit 5 MCR final cost and schedule estimate from the IESO on April 2, 2025. The Unit 5 MCR is expected to commence in fourth quarter 2026 with a return to service in early 2030.

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FINANCIAL RESULTS

The following is a reconciliation of comparable EBITDA and comparable EBIT (our non-GAAP measures) to segmented earnings (losses) (the most directly comparable GAAP measure). Refer to page 22 for more information on non-GAAP measures we use.

year ended December 31
(millions of $)						2025						2024						2023
Bruce Power1						733						890						680
Canadian Power						181						273						334
Natural Gas Storage and other2						94						51						6
Comparable EBITDA						1,008						1,214						1,020
Depreciation and amortization						(113)						(101)						(92)
Comparable EBIT						895						1,113						928
Specific items:
Power and Energy Solutions impairment charges						(110)						(36)						—
Bruce Power unrealized fair value adjustments						30						8						7
Risk management activities						(42)						17						69
Segmented earnings (losses)						773						1,102						1,004

1Includes our share of equity income from Bruce Power.

2Includes non-controlling interest in the Texas Wind Farms, which comprises Class A Membership Interests. Refer to the Corporate - Financial results section for additional information.

Power and Energy Solutions segmented earnings decreased by $329 million in 2025 compared to 2024 and increased by

$98 million in 2024 compared to 2023 and included the following specific items, which have been excluded from our calculation of comparable EBITDA and comparable EBIT:

•a pre-tax impairment charge in 2025 of $110 million (2024 – $36 million) for certain Power and Energy Solutions projects following our decision to discontinue development along with updated forecast assumptions as we refocus our Power and Energy Solutions strategy

•our proportionate share of Bruce Power's unrealized gains and losses on funds invested for post-retirement benefits and risk management activities

•unrealized gains and losses from changes in the fair value of derivatives used to reduce commodity exposures.

Comparable EBITDA for Power and Energy Solutions decreased by $206 million in 2025 compared to 2024 primarily due to the net effect of:

•lower Bruce Power contributions from reduced generation, mainly attributable to the Unit 4 MCR and higher operating costs, partially offset by a higher contract price. Refer to the Bruce Power section for additional information

•decreased Canadian Power results primarily from lower realized power prices

•increased Natural Gas Storage and other contributions reflecting lower business development costs, partially offset by decreased realized Alberta natural gas storage spreads in first quarter 2025 and reduced contributions from our U.S. marketing business.

Comparable EBITDA for Power and Energy Solutions increased by $194 million in 2024 compared to 2023 primarily due to the net effect of:

•higher contributions from Bruce Power primarily due to higher generation resulting from fewer outage days in 2024 and a higher contract price, partially offset by increased operating expenses and higher depreciation expense. Additional financial and operating information on Bruce Power is provided below

•increased Natural Gas Storage and other results primarily due to higher realized Alberta natural gas storage spreads and higher contributions from our U.S. marketing business, partially offset by increased business development costs in 2024

•decreased Canadian Power financial results primarily from lower realized power prices, partially offset by lower natural gas fuel costs.

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Depreciation and amortization

Depreciation and amortization increased by $12 million in 2025 compared to 2024 following the in-service of maintenance projects and increased by $9 million in 2024 compared to 2023 primarily due to the acquisition of the Texas Wind Farms in the first half of 2023.

Bruce Power results

Bruce Power results reflect our proportionate share. Comparable EBITDA and comparable EBIT are non-GAAP measures. Refer to page 22 for more information on non-GAAP measures we use. The following is our proportionate share of the components of comparable EBITDA and comparable EBIT.

year ended December 31
(millions of $, unless otherwise noted)						2025						2024						2023
Items included in comparable EBITDA and comparable EBIT are comprised of:
Revenues1						2,112						2,242						1,941
Operating expenses						(1,000)						(984)						(917)
Depreciation and other						(379)						(368)						(344)
Comparable EBITDA and comparable EBIT2						733						890						680
Bruce Power – other information
Plant availability3,4						91		%				92		%				92		%
Planned outage days4						152						160						106
Unplanned outage days						44						32						62
Sales volumes (GWh)5						19,126						22,209						20,447
Realized power price per MWh6						$109						$100						$94

1Net of amounts recorded to reflect operating cost efficiencies shared with the IESO, if applicable.

2Represents our 48.3 per cent ownership interest and internal costs supporting our investment in Bruce Power. Excludes unrealized gains and losses on funds invested for post-retirement benefits and risk management activities.

3The percentage of time the plant was available to generate power, regardless of whether it was running.

4Excludes MCR outage days.

5Sales volumes include deemed generation, if applicable.

6Calculation based on actual and deemed generation. Realized power price per MWh includes realized gains and losses from contracting activities and cost flow-through items. Excludes unrealized gains and losses on contracting activities and non-electricity revenues.

Planned maintenance in 2025 was completed on Unit 5 in first quarter and on Unit 2 in fourth quarter. Planned maintenance in 2024 was completed in second quarter on Units 5 to 8. A planned outage on Unit 4 was completed in second quarter 2023 and on Unit 8 in fourth quarter 2023.

On January 31, 2025, Unit 4 was removed from service to commence its MCR program, with a return to service expected in 2028.

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OUTLOOK

Comparable EBITDA

Power and Energy Solutions comparable EBITDA in 2026 is expected to be higher than 2025 primarily due to increased Bruce Power equity income with the expected return to service of Unit 3 in early third quarter 2026 following its MCR outage, a higher contract price, and a reduction in non-MCR planned outage days. These positive factors are expected to be partially offset by the commencement of the Unit 5 MCR outage in fourth quarter 2026. Contributions from Canadian Power are expected to be lower due to decreased generation and higher natural gas prices, partially offset by increased Alberta power prices. Natural Gas Storage and other earnings are expected to be consistent with 2025.

Planned maintenance at Bruce Power in 2026 is scheduled on Unit 8 in the first quarter and on Unit 1 in the third quarter. Excluding the MCR programs for Units 3, 4, and 5, average plant availability for 2026 is expected to be in the low-90 per cent range.

Capital expenditures

We incurred $0.9 billion of capital expenditures in 2025, primarily for our share of Bruce Power's Unit 3 and 4 MCR and Asset Management programs, along with maintenance capital projects across the segment. For 2026, we expect a similar level of capital investment, approximately $1.0 billion, mainly allocated to our share of Bruce Power's Unit 4 and Unit 5 MCR and Asset Management programs.

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BUSINESS RISKS

The following are risks specific to our Power and Energy Solutions business. Refer to page 94 for information about general risks related to TC Energy as a whole, including other operational, safety and financial risks, as well as our approach to risk management.

Fluctuating power and natural gas market prices

Much of the physical power generation and fuel used in our power operations is currently exposed to commodity price volatility. These exposures are partially mitigated through long-term contracts and hedging activities including selling and purchasing power and natural gas in forward markets. As contracts expire, new contracts are entered into at prevailing market prices.

Our two eastern Canadian natural gas-fired assets are fully contracted and not materially impacted by fluctuating spot power and natural gas prices. As the contracts on these assets expire it is uncertain if we will be able to re-contract on similar terms and may face future commodity exposure.

Our natural gas storage business is subject to fluctuating seasonal natural gas price spreads which are generally determined by the differential in natural gas prices between the traditional summer injection and winter withdrawal seasons. In addition, the business may be affected by pipeline restrictions in Alberta which limit the ability to capture price differentials.

Plant availability

Operating our plants to ensure services are provided safely and reliably as well as optimizing and maintaining their availability are essential to the continued success of our Power and Energy Solutions business. Unexpected outages or extended planned outages at our power plants can increase maintenance costs as well as lower plant output, revenues and margins. We may also have to buy power or natural gas on the spot market to meet our delivery obligations. We manage this risk by investing in a highly skilled workforce, operating prudently, running comprehensive risk-based preventive maintenance programs and making effective capital investments.

Regulatory

We operate in Canada and the U.S. in both regulated and deregulated power markets. These markets are subject to various federal, provincial and state regulations. As power markets evolve, there is the potential for regulatory bodies to implement new rules that could negatively affect us as a generator and marketer of electricity. These may be in the form of market rule or market design changes, changes in the interpretation and application of market rules by regulators, price caps, emission controls, emissions costs, cost allocations to generators and out-of-market actions taken by others to build excess generation, all of which may negatively affect the price of power. In addition, our development projects rely on an orderly permitting process and any disruption to that process can have negative effects on project schedules and costs. We are an active participant in formal and informal regulatory proceedings and take legal action where required.

Compliance

Market rules, regulations and operating standards apply to our power business based on the jurisdictions in which they operate. Our trading and marketing activities may be subject to fair competition and market conduct requirements as well as specific rules that apply to physical and financial transactions in deregulated markets. Similarly, our generators may be subject to specific operating and technical standards relating to maintenance activities, generator availability and delivery of power and power-related products. While significant efforts are made to ensure we comply with all applicable statutory requirements, situations including unforeseen operational challenges, lack of rule clarity and the ambiguous and unpredictable application of requirements by regulators and market monitors occasionally arise and create compliance risk. Deemed contravention of these requirements may result in mandatory mitigation activities, monetary penalties, imposition of operational limitations, or
even prosecution.

Weather

Significant changes in temperature and weather, including the potential impacts of climate change, have many effects on our business, ranging from the impact on demand, availability and commodity prices, to efficiency and output capability. Extreme temperature and weather can affect market demand for power and natural gas and can lead to significant price volatility, as well as restrict the availability of natural gas and power if demand is higher than supply. Fluctuations in seasonal weather patterns or temperature can affect the efficiency and production of our natural gas-fired power plants.

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Competition

We face various competitive forces that impact our existing assets and prospects for growth. For instance, our existing power plants will compete over time with new power capacity. New supply could come in several forms including supply that employs more efficient power generation technologies or additional supply from regional power transmission interconnections. We also face competition from other power companies in Canada and the U.S., as well as in the development of greenfield power plants. Traditional and non-traditional participants are entering the growing lower-carbon economy in North America and, as a result, we face competition in building lower-carbon energy solutions.

Execution and capital costs

We make substantial capital commitments developing power generation infrastructure based on the assumption that these assets will deliver an attractive return on investment. While we carefully consider the scope and expected costs of our capital projects, we are exposed to execution and capital cost overrun risk which may impact our return on these projects. We mitigate this risk by implementing comprehensive project governance and oversight processes and through the structuring of engineering, procurement and construction contracts with reputable counterparties.

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Corporate

SIGNIFICANT EVENTS

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.

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FINANCIAL RESULTS

The following is a reconciliation of comparable EBITDA and comparable EBIT (our non-GAAP measures) to segmented earnings (losses) (the most directly comparable GAAP measure). Refer to page 22 for more information on non-GAAP measures we use.

year ended December 31
(millions of $)						2025						2024						2023
Comparable EBITDA						(14)						(63)						(73)
Depreciation and amortization						—						(5)						(6)
Comparable EBIT						(14)						(68)						(79)
Specific items:
Third-party settlement						—						(34)						—
Focus Project costs						—						(24)						(65)
NGTL System ownership transfer costs						—						(10)						—
Segmented earnings (losses)						(14)						(136)						(144)

In 2025, Corporate segmented losses were $14 million compared to $136 million and $144 million in 2024 and 2023, respectively, and included the following specific items which have been excluded from our calculation of comparable EBITDA and comparable EBIT:

•a pre-tax expense of $34 million (US$25 million) in 2024 related to a non-recurring third-party settlement

•a pre-tax charge of $24 million recorded in 2024 (2023 – $65 million) related to Focus Project costs

•a pre-tax charge of $10 million in 2024 related to the NGTL System ownership transfer.

Comparable EBITDA for Corporate included shared costs in 2024 and 2023 related to TC Energy's corporate services and governance functions that were not allocated to discontinued operations in accordance with U.S. GAAP.

Depreciation and amortization

Depreciation and amortization for 2024 and 2023 included depreciation related to TC Energy's corporate services and governance functions that were not allocated to discontinued operations in accordance with U.S. GAAP.

OTHER INCOME STATEMENT ITEMS

Interest expense

year ended December 31
(millions of $)			2025						2024						2023
Interest expense on long-term debt and junior subordinated notes
Canadian dollar-denominated			(816)						(856)						(895)
U.S. dollar-denominated			(1,716)						(1,855)						(1,692)
Foreign exchange impact			(683)						(685)						(592)
			(3,215)						(3,396)						(3,179)
Other interest and amortization expense			(204)						(147)						(261)
Capitalized interest			10						191						187
Interest expense allocated to discontinued operations			—						176						287
Interest expense included in comparable earnings			(3,409)						(3,176)						(2,966)
Specific items:
Net gain on debt extinguishment			—						228						—
Risk management activities			2						(71)						—
Interest expense			(3,407)						(3,019)						(2,966)

TC Energy Management's discussion and analysis 2025 | 67

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Interest expense increased by $388 million in 2025 compared to 2024 and increased by $53 million in 2024 compared to 2023. The following specific items have been removed from our calculation of interest expense included in comparable earnings:

•pre-tax net gain on debt extinguishment of $228 million was recorded related to the purchase and cancellation of certain senior unsecured notes and medium term notes and the retirement of outstanding callable notes in October 2024

•unrealized gains and losses on derivatives used to manage our interest rate risk. Refer to the Other information - Financial risks and financial instruments sections for additional information.

Interest expense included in comparable earnings in 2025 increased by $233 million compared to 2024 primarily due to the net effect of:

•lower capitalized interest due to the declared commercial in-service of the Coastal GasLink pipeline in fourth quarter 2024

•no interest expense allocated to discontinued operations in 2025

•long-term debt issuances and maturities, including lower interest expense resulting from TCPL’s cash tender offers completed in fourth quarter 2024

•increased levels of short-term borrowing.

Interest expense included in comparable earnings in 2024 increased by $210 million compared to 2023 mainly due to the net effect of:

•long-term debt issuances and maturities

•interest expense allocated to discontinued operations for nine months in 2024 compared to a full year in 2023. Refer to the Discontinued operations section for additional information

•the foreign exchange impact from a weaker U.S. dollar on translation of U.S. dollar-denominated interest expense

•reduced levels of short-term borrowing.

Refer to the Financial condition section for additional information.

Allowance for funds used during construction

year ended December 31
(millions of $)						2025						2024						2023
Canadian dollar-denominated						51						34						102
U.S. dollar-denominated						284						546						350
Foreign exchange impact						118						204						123
Allowance for funds used during construction						453						784						575

AFUDC decreased by $331 million in 2025 compared to 2024. The increase in Canadian dollar-denominated AFUDC is primarily related to NGTL System expansion projects. The decrease in U.S. dollar-denominated AFUDC is primarily due to the completion of the Southeast Gateway pipeline in second quarter 2025 and the suspension of AFUDC on the south section of the Villa de Reyes pipeline in first quarter 2025 due to ongoing construction delays on the project pending the resolution of outstanding stakeholder issues, partially offset by capital expenditures on our U.S. natural gas pipeline projects.

AFUDC increased by $209 million in 2024 compared to 2023. The decrease in Canadian dollar-denominated AFUDC is primarily related to NGTL System expansion projects placed in service in 2024. The increase in U.S. dollar-denominated AFUDC is primarily due to capital expenditures on the Southeast Gateway pipeline project and U.S. natural gas pipeline projects in 2024, partially offset by the suspension of AFUDC on the assets under construction for the Tula pipeline project due to the delay of an FID and placing the lateral section of Villa de Reyes pipeline in service in August 2023.

68 | TC Energy Management's discussion and analysis 2025

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Foreign exchange gains (losses), net

year ended December 31
(millions of $)						2025						2024						2023
Foreign exchange gains (losses), net included in comparable earnings						96						(85)						118
Specific items:
Foreign exchange gains (losses), net – intercompany loan1						(149)						204						(44)
Risk management activities						210						(266)						246
Foreign exchange gains (losses), net						157						(147)						320

1     Includes non-controlling interest. Refer to Net (income) loss attributable to non-controlling interests for additional information.

Foreign exchange gains (losses), net, in 2025 changed by $304 million compared to 2024 and changed by $467 million in 2024 compared to 2023. The following specific items have been removed from our calculation of Foreign exchange gains (losses), net included in comparable earnings:

•unrealized foreign exchange gains and losses on the peso-denominated intercompany loan between TCPL and TGNH beginning in second quarter 2023

•unrealized gains and losses from changes in the fair value of derivatives used to manage our foreign exchange risk. Refer to the Other information – Financial risks and Financial instruments sections for additional information.

Foreign exchange gains (losses), net included in comparable earnings in 2025 changed by $181 million compared to 2024. The change was primarily due to the net effect of:

•risk management activities used to manage our foreign exchange exposure to net liabilities in Mexico and to U.S. dollar‑denominated income

•foreign exchange losses in 2025 compared to foreign exchange gains in 2024 on the revaluation of our peso-denominated net monetary liabilities to U.S. dollars

•a net realized gain in second quarter 2024 on the partial repayment of the peso-denominated intercompany loan between TCPL and TGNH.

Foreign exchange gains (losses), net included in comparable earnings in 2024 changed by $203 million compared to 2023. The change was primarily due to the net effect of:

•risk management activities used to manage our foreign exchange exposure to net liabilities in Mexico and to U.S. dollar‑denominated income

•foreign exchange gains in 2024 compared to foreign exchange losses in 2023 on the revaluation of our peso-denominated net monetary liabilities to U.S. dollars

•a net realized gain in second quarter 2024 on the partial repayment of the peso-denominated intercompany loan between TCPL and TGNH.

Interest income and other

year ended December 31
(millions of $)						2025						2024						2023
Canadian dollar-denominated						49						87						62
U.S. dollar-denominated						112						172						156
Foreign exchange impact						44						65						54
Interest income and other						205						324						272

Interest income and other decreased by $119 million in 2025 compared to 2024 primarily due to the net effect of:

•lower interest earned on Canadian and U.S. dollar-denominated short-term investments

•increased insurance-related provisions

•higher investment income and the change in fair value of other restricted investments.

Interest income and other increased by $52 million in 2024 compared to 2023 primarily due to the net effect of:

•higher interest earned on Canadian dollar‑denominated short-term investments

•decreased insurance-related provisions.

TC Energy Management's discussion and analysis 2025 | 69

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Income tax (expense) recovery

year ended December 31
(millions of $)						2025						2024						2023
Income tax (expense) recovery included in comparable earnings						(1,112)						(772)						(890)
Specific items:
Power and Energy Solutions impairment charges						25						9						—
Foreign exchange gains (losses), net – intercompany loan						(13)						10						—
Expected credit loss provision on net investment in leases   and certain contract assets in Mexico						24						(7)						(25)
Gain on sale of PNGTS						—						(116)						—
Revaluation of deferred tax balances						—						(96)						—
Net gain on debt extinguishment						—						(50)						—
Gain on sale of non-core assets						—						15						—
Third-party settlement						—						8						—
Focus Project costs						—						6						17
NGTL System ownership transfer costs						—						(32)						—
Coastal GasLink impairment charge						—						—						157
Bruce Power unrealized fair value adjustments						(7)						(2)						(2)
Risk management activities						(55)						105						(99)
Income tax (expense) recovery						(1,138)						(922)						(842)

Income tax expense in 2025 increased by $216 million compared to 2024 and increased by $80 million in 2024 compared to 2023.

In addition to the income tax impacts on other specific items referenced elsewhere in this MD&A, Income tax (expense) recovery also includes the following specific items, which have been removed from our calculation of Income tax (expense) recovery included in comparable earnings:

2024

•a deferred income tax expense of $96 million resulting from the revaluation of remaining deferred tax balances following the Spinoff Transaction.

2023

•a $157 million income tax recovery related to the impairment of our equity investment in Coastal GasLink LP.

Income tax expense included in comparable earnings in 2025 increased by $340 million compared to 2024 primarily due to Mexico foreign exchange exposure and higher flow-through income taxes.

Income tax expense included in comparable earnings in 2024 decreased by $118 million compared to 2023 primarily due to Mexico foreign exchange exposure and lower earnings subject to income tax, partially offset by lower foreign income tax rate differentials and higher flow-through income taxes.

Refer to the Foreign exchange section for additional information on our Mexico foreign exchange exposure.

70 | TC Energy Management's discussion and analysis 2025

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Net (income) loss attributable to non-controlling interests

year ended December 31			Non-Controlling Interests Ownership at  December 31, 2025						2025						2024						2023
(millions of $)
Columbia Gas and Columbia Gulf1			40		%				(631)						(571)						(143)
TGNH2			13.01		%				(50)						(48)						—
Texas Wind Farms3			100		%				38						29						38
PNGTS4			nil						—						(30)						(41)
Net (income) loss attributable to non-controlling interests included in comparable earnings									(643)						(620)						(146)
Specific item:
Foreign exchange (gains) losses, net – intercompany loan									60						(61)						—
Expected credit loss provision on net investment in leases									8						—						—
Net (income) loss attributable to non-controlling interests									(575)						(681)						(146)

1In October 2023, we completed the sale of a 40 per cent non-controlling equity interest in Columbia Gas and Columbia Gulf to Global Infrastructure Partners.

2In second quarter 2024, the CFE became a partner in TGNH with a 13.01 per cent equity interest in TGNH. Refer to the Mexico Natural Gas Pipelines – Significant events section for additional information.

3Tax 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. We own 100 per cent of the Class B Membership Interests.

4The sale of PNGTS was completed in August 2024.

Net income attributable to non-controlling interests decreased by $106 million in 2025 compared to 2024 and increased by     $535 million in 2024 compared to 2023 and included the following specific items which have been excluded from our calculation of Net (income) loss attributable to non-controlling interests included in comparable earnings:

•the non-controlling interest portion of the unrealized foreign exchange gains and losses on the TGNH peso-denominated intercompany loan payable to TCPL

•the expected credit loss provision related to the TGNH net investment in leases.

Net income attributable to non-controlling interests included in comparable earnings increased by $23 million in 2025 compared to 2024. The increase is primarily due to higher net income recognized from the Columbia Gas and Columbia Gulf assets, the net impact of higher EBITDA and lower AFUDC in TGNH following the Southeast Gateway pipeline's completion in second quarter 2025, the full year impact of the 13.01 per cent TGNH non-controlling equity interest sale to the CFE, which was completed in second quarter 2024 and the overall impact of foreign exchange. This was partially offset by the divestiture of PNGTS in third quarter 2024.

Net income attributable to non-controlling interests included in comparable earnings increased by $474 million in 2024 compared to 2023 primarily due to the sale of a 40 per cent non-controlling equity interest in Columbia Gas and Columbia Gulf to Global Infrastructure Partners in fourth quarter 2023 and the 13.01 per cent non-controlling equity interest in TGNH to the CFE, which was completed in second quarter 2024.

Preferred share dividends

year ended December 31
(millions of $)						2025						2024						2023
Preferred share dividends						(119)						(104)						(93)

Preferred share dividends increased by $15 million in 2025 compared to 2024 and increased by $11 million in 2024 compared to 2023 primarily due to the redemption of preferred shares in 2025, dividend rate resets on and conversions of certain series of preferred shares in 2025 and 2024. Refer to Note 24, Preferred shares, of our 2025 Consolidated financial statements for additional information.

TC Energy Management's discussion and analysis 2025 | 71

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Foreign exchange

Foreign exchange related to U.S. dollar-denominated operations

Certain of our businesses generate all or most of their earnings in U.S. dollars and since we report our financial results in Canadian dollars, changes in the value of the U.S. dollar against the Canadian dollar directly affect our comparable EBITDA and may also impact comparable earnings. As our U.S. dollar-denominated operations continue to grow, this exposure increases.
A portion of the U.S. dollar-denominated comparable EBITDA exposure is naturally offset by U.S. dollar-denominated amounts below comparable EBITDA within Depreciation and amortization, Interest expense and other income statement line items.
A portion of the remaining exposure is actively managed on a rolling forward basis up to three years using foreign exchange derivatives; however, the natural exposure beyond that period remains. The net impact of the U.S. dollar movements on comparable earnings during the year ended December 31, 2025, after considering natural offsets and economic hedges, was not significant.

The components of our financial results denominated in U.S. dollars are set out in the table below, including our U.S. Natural Gas Pipelines and Mexico Natural Gas Pipelines operations. Comparable EBITDA is a non-GAAP measure.

Pre-tax U.S. dollar-denominated income and expense items - from continuing operations

year ended December 31
(millions of US$)						2025						2024						2023
Comparable EBITDA
U.S. Natural Gas Pipelines						3,506						3,294						3,248
Mexico Natural Gas Pipelines						981						730						596
						4,487						4,024						3,844
Depreciation and amortization						(812)						(764)						(758)
Interest expense on long-term debt and junior subordinated notes						(1,716)						(1,855)						(1,692)
Interest income and other						112						172						156
Interest expense allocated to discontinued operations						—						125						189
Allowance for funds used during construction						284						546						350
Net (income) loss attributable to non-controlling interests included in comparable earnings and other						(466)						(481)						(156)
						1,889						1,767						1,933
Average exchange rate – U.S. to Canadian dollars						1.40						1.37						1.35

Foreign exchange related to Mexico Natural Gas Pipelines

Changes in the value of the Mexican peso against the U.S. dollar can affect our comparable earnings as a portion of our Mexico Natural Gas Pipelines' monetary assets and liabilities are peso-denominated, while our financial results are denominated in U.S. dollars for our Mexico operations. These peso-denominated balances are revalued to U.S. dollars, creating foreign exchange gains and losses that are included in Income (loss) from equity investments, Foreign exchange (gains) losses, net and Net income (loss) attributable to non-controlling interests in the Consolidated statement of 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 from equity investments and Income tax expense. This exposure increases as our U.S. dollar‑denominated net monetary liabilities grow.

The above exposures are managed using foreign exchange derivatives, although some unhedged exposure remains. The impacts of the foreign exchange derivatives are recorded in Foreign exchange (gains) losses, net in the Consolidated statement of income. Refer to the Other information – Financial risks and Financial instruments sections for additional information.

72 | TC Energy Management's discussion and analysis 2025

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The period end exchange rates for one U.S. dollar to Mexican pesos were as follows:

December 31, 2025						18.00
December 31, 2024						20.87
December 31, 2023						16.91

A summary of the impacts of transactional foreign exchange gains and losses from changes in the value of the Mexican peso against the U.S. dollar and associated derivatives is set out in the table below:

year ended December 31
(millions of $)						2025						2024						2023
Comparable EBITDA – Mexico Natural Gas Pipelines1						(80)						115						(83)
Foreign exchange gains (losses), net included in comparable earnings						140						(53)						224
Income tax (expense) recovery included in comparable earnings						(89)						110						(133)
Net (income) loss attributable to non-controlling interests included in comparable earnings2						7						(11)						—
						(22)						161						8

1Includes the foreign exchange impacts from the Sur de Texas joint venture recorded in Income (loss) from equity investments in the Consolidated statement
of income.

2Represents the non-controlling interest portion related to TGNH. Refer to the Corporate - Financial results section for additional information.

TC Energy Management's discussion and analysis 2025 | 73

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Financial condition

We strive to maintain financial strength and flexibility in all parts of the economic cycle. We rely on our operating cash flows to sustain our business, pay dividends and fund a portion of our growth. In addition, we access capital markets and engage in portfolio management activities to meet our financing needs and to manage our capital structure and credit ratings. More information on how our credit ratings can impact our financing costs, liquidity and operations is available in our Annual Information Form available on SEDAR+ (www.sedarplus.ca).

We believe we have the financial capacity to fund our existing capital program through predictable and growing cash flows from continuing operations, access to capital markets, portfolio management activities, joint ventures, asset-level financing, cash
on hand and substantial committed credit facilities. Annually, in the fourth quarter, we renew and extend our credit facilities as required.

Financial Plan

Our capital program is comprised of approximately $21 billion of secured projects, as well as our projects under development, which are subject to key corporate and regulatory approvals. As discussed throughout this Financial condition section, our capital program is expected to be financed through our growing internally-generated cash flows and a combination of other funding options which may include:

•senior debt

•hybrid securities

•preferred shares

•asset divestitures and capital rotation

•project financing

•potential involvement of strategic or financial partners.

In addition, we may access additional funding options, as deemed appropriate, including common shares issued from treasury under our DRP and discrete common equity issuances.

Balance sheet analysis - from continuing operations

At December 31, 2025, excluding discontinued operations, our current assets totaled $6.1 billion and current liabilities amounted to $9.8 billion, leaving us with a working capital deficit of $3.7 billion compared to $4.8 billion at December 31, 2024. Our working capital deficiency is considered to be in the normal course of business and is managed through:

•our ability to generate predictable and growing cash flows from operations

•a total of $7.8 billion of TCPL committed revolving credit facilities, of which $7.2 billion of short-term borrowing capacity remains available, net of $0.6 billion backstopping outstanding commercial paper balances, and arrangements for a further $2.0 billion of demand credit facilities, of which $1.3 billion remains available as of December 31, 2025

•additional $2.1 billion committed revolving credit facilities at certain of our subsidiaries and affiliates, of which $1.5 billion of short-term borrowing capacity remains available as of December 31, 2025, net of $0.6 billion backstopping outstanding commercial paper balances

•our access to capital markets, including through securities issuances, incremental credit facilities, capital rotation and DRP, if deemed appropriate.

Our total assets from continuing operations at December 31, 2025 were $118.6 billion compared to $117.9 billion at December 31, 2024 reflecting our 2025 capital spending program, equity investments and working capital, partially offset by a weaker U.S. dollar at December 31, 2025 compared to December 31, 2024 on translation of our U.S. dollar-denominated assets.

At December 31, 2025 our total liabilities from continuing operations were $81.7 billion, compared to $79.6 billion at December 31, 2024 due to the net effect of movements in debt, working capital and a weaker U.S. dollar at December 31, 2025 compared to December 31, 2024 on translation of our U.S. dollar-denominated liabilities.

74 | TC Energy Management's discussion and analysis 2025

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Consolidated capital structure - from continuing operations

The following table summarizes the components of our capital structure for continuing operations.

at December 31												Percentage of total												Percentage  of total
(millions of $, unless otherwise noted)						2025												2024
Notes payable						1,200						2		%				387						1		%
Long-term debt, including current portion						46,792						48		%				47,931						49		%
Cash and cash equivalents						(168)						—						(801)						(1)		%
						47,824						50		%				47,517						49		%
Junior subordinated notes						12,094						12		%				11,048						11		%
Preferred shares						2,255						2		%				2,499						3		%
Common shareholders' equity						25,040						26		%				25,093						26		%
Non-controlling interests						9,604						10		%				10,768						11		%
						96,817						100		%				96,925						100		%

Provisions of various trust indentures, credit arrangements and other agreements with certain of our subsidiaries can restrict those subsidiaries' ability and, in certain cases, our ability to declare and pay dividends or make distributions under certain circumstances. In the opinion of management, these provisions do not currently restrict our ability to declare or pay dividends. These trust indentures and credit arrangements also require us to comply with various affirmative and negative covenants and maintain certain financial ratios. We were in compliance with all of our financial covenants at December 31, 2025.

Cash flows1,2

The following tables summarize our consolidated cash flows.

year ended December 31
(millions of $)						2025						2024						2023
Net cash provided by operations						7,346						7,696						7,268
Net cash (used in) provided by investing activities						(6,458)						(6,909)						(12,287)
Net cash (used in) provided by financing activities						(1,516)						(3,874)						8,093
						(628)						(3,087)						3,074
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

1    Includes continuing and discontinued operations.

2    Includes nine months of Liquids Pipelines earnings in 2024 and a full year of earnings in 2023. Refer to the Discontinued operations section for additional information.

TC Energy Management's discussion and analysis 2025 | 75

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Cash provided by operating activities1,2

year ended December 31
(millions of $)						2025						2024						2023
Net cash provided by operations						7,346						7,696						7,268
Increase (decrease) in operating working capital						503						(199)						(207)
Funds generated from operations						7,849						7,497						7,061
Specific items:
South Bow settlement						147						—						—
Liquids Pipelines business separation costs, net of current income tax						—						185						40
Current income tax (recovery) expense on sale of PNGTS and non-core assets						—						148						—
Third-party settlement, net of current income tax						—						26						—
Focus Project costs, net of current income tax						—						21						54
NGTL System ownership transfer costs						—						10						—
Current income tax (recovery) expense on risk management activities						—						9						—
Current income tax (recovery) expense on Keystone XL asset impairment charge and other						—						(3)						(14)
Current income tax (recovery) expense on Keystone regulatory decisions						—						(3)						53
Current income tax (recovery) expense on disposition of equity interest3						—						—						736
Milepost 14 insurance expense						—						—						36
Keystone XL preservation and other, net of current income tax						—						—						14
Comparable funds generated from operations						7,996						7,890						7,980

1    Includes continuing and discontinued operations.

2    Includes nine months of Liquids Pipelines earnings in 2024 and a full year of earnings in 2023. Refer to the Discontinued operations section for additional information.

3    Current income tax expense related to applying an approximate 24 per cent tax rate to the tax gain on sale of a 40 per cent non-controlling equity interest in Columbia Gas and Columbia Gulf. This is offset by a corresponding deferred tax recovery resulting in no net impact to tax expense.

Net cash provided by operations

Net cash provided by operations decreased by $350 million in 2025 compared to 2024 primarily due to the timing of working capital changes, partially offset by higher funds generated from operations.

Net cash provided by operations increased by $428 million in 2024 compared to 2023 primarily due to higher funds generated from operations.

Comparable funds generated from operations

Comparable funds generated from operations, a non-GAAP measure, helps us assess the cash generating ability of our businesses by excluding the timing effects of working capital changes, as well as the cash impact of our specific items.

Comparable funds generated from operations increased by $106 million in 2025 compared to 2024 primarily due to higher comparable EBITDA and risk management activities used to manage our foreign exchange exposure to net liabilities in Mexico and to U.S. dollar‑denominated income, partially offset by lower distributions from our equity investments.

Comparable funds generated from operations decreased by $90 million in 2024 compared to 2023 primarily due to lower comparable earnings, partially offset by increased distributions from our equity investments.

76 | TC Energy Management's discussion and analysis 2025

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Cash (used in) provided by investing activities1

year ended December 31
(millions of $)						2025						2024						2023
Capital spending2
Capital expenditures						(5,270)						(6,308)						(8,007)
Capital projects in development						(16)						(50)						(142)
Contributions to equity investments						(1,051)						(1,546)						(4,149)
						(6,337)						(7,904)						(12,298)
Other distributions from equity investments						5						549						23
Proceeds from sales of assets, net of transaction costs						—						791						33
Acquisitions, net of cash acquired						—						—						(307)
Loans to affiliate (issued) repaid, net						—						—						250
Deferred amounts and other						(126)						(345)						12
Net cash (used in) provided by investing activities						(6,458)						(6,909)						(12,287)

1    Includes continuing and discontinued operations.

2    Capital spending reflects cash flows associated with our Capital expenditures, Capital projects in development and Contributions to equity investments. For the year ended December 31, 2024, Contributions to equity investments were net of Other distributions from equity investments of $3.1 billion in the Canadian Natural Gas Pipelines segment. Refer to Note 5, Segmented information, Note 10, Equity investments and Note 11, Loans with affiliates, of our 2025 Consolidated financial statements for additional information.

Net cash used in investing activities decreased from $6.9 billion in 2024 to $6.5 billion in 2025 primarily as a result of decreased capital spending in 2025, partially offset by proceeds from sale of assets in 2024.

Net cash used in investing activities decreased from $12.3 billion in 2023 to $6.9 billion in 2024 primarily as a result of decreased capital spending and lower contributions to equity investments primarily related to Coastal GasLink LP and in part by higher proceeds from the sales of assets and distributions from equity investments.

Capital spending1

The following table summarizes capital spending by segment.

year ended December 31
(millions of $)						2025						2024						2023
Canadian Natural Gas Pipelines						1,405						2,100						6,184
U.S. Natural Gas Pipelines						3,457						2,575						2,660
Mexico Natural Gas Pipelines						522						2,228						2,292
Power and Energy Solutions						922						824						1,080
Corporate						31						50						33
						6,337						7,777						12,249
Discontinued operations						—						127						49
						6,337						7,904						12,298

1Capital spending reflects cash flows associated with our Capital expenditures, Capital projects in development and Contributions to equity investments. For the year ended December 31, 2024, Contributions to equity investments were net of Other distributions from equity investments of $3.1 billion in the Canadian Natural Gas Pipelines segment. Refer to Note 5, Segmented information, Note 10, Equity investments and Note 11, Loans with affiliates, of our 2025 Consolidated financial statements for additional information.

TC Energy Management's discussion and analysis 2025 | 77

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Capital expenditures

Capital expenditures in 2025 were incurred primarily for the advancement of the Columbia Gas and ANR projects, the NGTL System expansion as well as maintenance capital expenditures. Lower capital expenditures in 2025 compared to 2024 reflect the completion of the Southeast Gateway pipeline in second quarter 2025, partially offset by increased spending on ANR projects.

Capital projects in development

Costs incurred during 2025 on Capital projects in development were attributable to spending on projects in the Power and Energy Solutions segment.

Contributions to equity investments

Contributions to equity investments decreased in 2025 compared to 2024 mainly due to lower funds advanced to Coastal GasLink LP through the subordinated loan agreement.

Contributions to equity investments decreased in 2024 compared to 2023 mainly due to lower funds advanced to Coastal GasLink LP through the subordinated loan agreement.

On December 17, 2024, following the declared commercial in-service of the pipeline, Coastal GasLink LP repaid the     $3,147 million balance owing to us under the subordinated loan agreement. Our share of equity contributions required to fund Coastal GasLink LP's repayment of the outstanding loan balance amounted to $3,137 million. The Contributions to equity investments and Other distributions from equity investments with respect to these activities are presented above on a net basis, although they are reported on a gross basis in our Consolidated statement of cash flows. Refer to Note 11, Loans with affiliates, of our 2025 Consolidated financial statements for additional information.

Other distributions from equity investments

Other distributions from equity investments decreased in 2025 compared to 2024 mainly due to distributions from Millennium as a result of its debt financing program in 2024, as well as lower return of capital from our equity investment in Iroquois.

Other distributions from equity investments increased in 2024 compared to 2023 mainly due to distributions from Millennium as a result of its debt financing program in 2024.

Proceeds from sales of assets

In 2024, TC Energy and its partner, Northern New England Investment Company, Inc., a subsidiary of Énergir, completed the sale of PNGTS to a third party. Our share of the proceeds was $743 million (US$546 million), net of transaction costs.

In 2024, we also completed the sale of other non-core assets for gross proceeds of $48 million.

In 2023, we completed the sale of a 20.1 per cent equity interest in Port Neches Link LLC to its joint venture partner,         Motiva Enterprises, for gross proceeds of $33 million (US$25 million). As part of the Spinoff Transaction on October 1, 2024, our remaining interest in Port Neches Link LLC was transferred to South Bow.

Acquisitions

In 2023, we acquired 100 per cent of the Class B Membership Interests in the Fluvanna Wind Farm located in Scurry County, Texas for US$99 million, before post-closing adjustments. We also acquired 100 per cent of the Class B Membership Interests in the Blue Cloud Wind Farm located in Bailey County, Texas for US$125 million, before post-closing adjustments.

Loans to affiliate

In 2023, loans to affiliate (issued) repaid, net, represent issuances and repayments on the subordinated demand revolving credit facility and the subordinated loan agreement that we entered with Coastal GasLink LP to provide additional liquidity and funding to the Coastal GasLink project.

78 | TC Energy Management's discussion and analysis 2025

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Cash (used in) provided by financing activities1

year ended December 31
(millions of $)						2025						2024						2023
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						(6,116)						(9,273)						(3,772)
Junior subordinated notes issued, net of issue costs						2,545						1,465						—
Dividends and distributions paid						(4,550)						(4,807)						(3,052)
Common shares issued, net of issue costs						104						88						4
Preferred shares redeemed						(250)						—						—
Contributions from non-controlling interests						—						21						—
Cash received from factoring arrangement						351						—						—
Loan from affiliate						111						—						—
Disposition of equity interest, net of transaction costs						—						419						5,328
Cash transferred to South Bow, net of debt settlements						—						(244)						—
Gains (losses) on settlement of financial instruments						—						27						—
Net cash (used in) provided by financing activities						(1,516)						(3,874)						8,093

1    Includes continuing and discontinued operations.

Net cash used in financing activities decreased by $2.4 billion in 2025 compared to 2024 primarily due to lower repayments of long-term debt and higher issuances of junior subordinated notes and notes payable, as well as lower dividends and distributions paid in 2025, partially offset by lower issuances of long-term debt.

Net cash provided by financing activities decreased by $12.0 billion in 2024 compared to 2023 primarily due to lower issuances and higher repayments of long-term debt, the receipt of the $5.3 billion (US$3.9 billion) proceeds in 2023 upon sale of a     40 per cent non-controlling equity interest in Columbia Gas and Columbia Gulf, as well as higher dividends and distributions paid in 2024, partially offset by net issuances of notes payable in 2024 compared to net repayments in 2023 and junior subordinated notes issued in 2024.

The principal transactions reflected in our financing activities are discussed in further detail below.

TC Energy Management's discussion and analysis 2025 | 79

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Long-term debt issued

The following table outlines significant long-term debt issuances in 2025.

(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

%

COLUMBIA PIPELINES HOLDING COMPANY LLC

November 2025

Senior Unsecured Notes

November 2032

US 750

5.00

%

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

%

Long-term debt retired/repaid

The following table outlines significant long-term debt retired/repaid in 2025.

(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

%

NOVA GAS TRANSMISSION LTD.

May 2025

Medium Term Notes

87

8.90

%

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

Senior Unsecured Term Loan

US 677

Floating

On February 5, 2026, TCPL retired $241 million of medium term notes bearing interest at a fixed rate of 8.29 per cent.

80 | TC Energy Management's discussion and analysis 2025

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Junior subordinated notes issued

The following table outlines significant junior subordinated notes issued in 2025:

(millions of Canadian $, unless otherwise noted)

Company

Issue date

Type

Maturity date

Amount

Interest rate

TRANSCANADA PIPELINES LIMITED

October 2025

Junior Subordinated Notes

November 2085

US 370

6.25

%

August 2025

Junior Subordinated Notes

February 2056

1,000

5.20

%

1

February 2025

Junior Subordinated Notes

June 2065

US 750

7.00

%

2

1    Fixed rate of interest per year until February 15, 2031, and resetting every five years thereafter, subject to a rate-reset minimum.

2    Fixed rate of interest per year until June 1, 2030, and resetting every five years thereafter.

Junior subordinated notes repaid/retired

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). 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. Refer to Note 20, Junior subordinated notes, of our 2025 Consolidated financial statements for additional information.

For more information about long-term debt and junior subordinated notes issued and long-term debt repaid in 2025, 2024 and 2023, refer to Note 19, Long-term debt and Note 20, Junior subordinated notes, of our 2025 Consolidated financial statements.

Dividend reinvestment plan

Under the 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.

Commencing with the dividends declared on July 27, 2023, common shares purchased under TC Energy's DRP are acquired on the open market at 100 per cent of the weighted average purchase price.

TC Energy Management's discussion and analysis 2025 | 81

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Share information

at February 6, 2026
Common Shares			issued and outstanding
			1.0 billion
Preferred Shares			issued and outstanding			convertible to
Series 1			18.4 million			Series 2 preferred shares
Series 2			3.6 million			Series 1 preferred shares
Series 3			11.7 million			Series 4 preferred shares
Series 4			2.3 million			Series 3 preferred shares
Series 5			14.0		million	Series 6 preferred shares
Series 7			24 million			Series 8 preferred shares
Series 9			16.7 million			Series 10 preferred shares
Series 10			1.3 million			Series 9 preferred shares
Options to buy common shares			outstanding			exercisable
			1.9 million			1.4 million

On January 16, 2026, 109,800 Series 5 preferred shares were elected for conversion, on a one-for-one basis, into Series 6 preferred shares and 1,089,726 Series 6 preferred shares were elected for conversion, on a one-for-one basis, into Series 5 preferred shares. As the total number of Series 6 preferred shares tendered for conversion would have resulted in less than one million Series 6 preferred shares outstanding on the conversion date, all remaining outstanding Series 6 preferred shares were automatically converted into Series 5 preferred shares and no Series 5 preferred shares were converted into Series 6 preferred shares. As a result, on January 30, 2026, 1,929,407 Series 6 preferred shares were converted, on a one-for-one basis, into 1,929,407 Series 5 preferred shares and Series 6 preferred shares were delisted from the TSX at the close of markets on         January 30, 2026.

On November 28, 2025, we 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, as previously declared on November 4, 2025.

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.

For more information on preferred shares, refer to Note 24, Preferred shares, of our 2025 Consolidated financial statements.

82 | TC Energy Management's discussion and analysis 2025

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Dividends

year ended December 31						2025						2024						2023
Dividends declared
per common share1						$3.40						$3.7025						$3.72
per Series 1 preferred share						$1.23475						$0.86975						$0.86975
per Series 2 preferred share						$1.20576						$1.68134						$1.62659
per Series 3 preferred share						$0.7245						$0.4235						$0.4235
per Series 4 preferred share						$1.04576						$1.52046						$1.46703
per Series 5 preferred share						$0.48725						$0.48725						$0.48725
per Series 6 preferred share						$1.06655						$1.55132						$1.55993
per Series 7 preferred share						$1.49625						$1.36613						$0.97575
per Series 9 preferred share						$1.27						$1.02288						$0.9405
per Series 10 preferred share						$1.26905						$0.39807						—
per Series 11 preferred share						$0.62831						$0.83775						$0.83775

1Dividends declared in fourth quarter 2024 and thereafter reflect TC Energy's proportionate allocation following the Spinoff Transaction.

Commencing with the dividends payable on January 31, 2025 to shareholders of record at the close of business on     December 31, 2024, the amounts reflect TC Energy’s proportionate allocation following the Spinoff Transaction. Refer to our 2024 Annual Report for additional information.

Our Board of Directors have declared a quarterly dividend on our outstanding common shares of $0.8775 per common share for the quarter ending March 31, 2026, which equates to an annual dividend of $3.51 per common share.

Credit facilities

We have several committed credit facilities that support our commercial paper programs and provide short-term liquidity for general corporate purposes. In addition, we have demand credit facilities that are also used for general corporate purposes, including issuing letters of credit and providing additional liquidity.

At February 6, 2026, total committed revolving and demand credit facilities were $11.8 billion. These unsecured credit facilities included the following:

(billions of Canadian $, unless otherwise noted)

Borrower

Description

Matures

Total facilities

Unused capacity

1

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

TCPL

Supports commercial paper program and for general corporate purposes

December 2030

3.0

2.3

TCPL / TCPL USA

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

December 2026

US 1.0

US 0.7

TCPL / TCPL USA

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

December 2028

US 2.5

US 2.2

Columbia Pipelines Holding Company LLC2

Supports commercial paper program and general corporate purposes of the borrower

December 2028

US 1.5

US 1.1

Demand senior unsecured revolving credit facilities:

TCPL / TCPL USA

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

Demand

2.0

3

1.2

3

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

2Columbia Pipelines Holding Company LLC is a partially owned subsidiary of TC Energy with 40 per cent non-controlling interest.

3Or the U.S. dollar equivalent.

TC Energy Management's discussion and analysis 2025 | 83

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Contractual obligations

Our contractual obligations include our notes payable, long-term debt and junior subordinated notes, operating leases, purchase obligations and other liabilities incurred in our business such as cash contributions to the employee pension and post-retirement benefit plans.

Payments due (by period)

at December 31, 2025			Total						< 1 year						1 - 3 years						4 - 5 years						> 5 years
(millions of $)
Notes payable			1,200						1,200						—						—						—
Long-term debt and junior subordinated notes1			59,145						1,545						8,318						5,882						43,400
Operating leases2			509						73						129						122						185
Purchase obligations and other3			4,650						1,091						976						564						2,019
			65,504						3,909						9,423						6,568						45,604

1Excludes issuance costs and fair value adjustments.

2Includes future payments for corporate offices, various premises, services, equipment, land and lease commitments from corporate restructuring. Some of our operating leases include the option to renew the agreement for one to 25 years.

3Includes $17 million related to the transfer of pension assets to South Bow. Refer to the Obligations - pension and other post-retirement benefit plans section for additional information.

Notes payable

Total notes payable outstanding at December 31, 2025 was $1.2 billion (2024 – $387 million).

Long-term debt and junior subordinated notes

At December 31, 2025, we had $46.8 billion (2024 – $47.9 billion) of long-term debt and $12.1 billion (2024 – $11.0 billion) of junior subordinated notes.

We attempt to ladder the maturity profile of our debt. The weighted-average maturity of our long‑term debt and junior subordinated notes, excluding call features is approximately 19 years.

At December 31, 2025, scheduled interest payments related to our long-term debt and junior subordinated notes were as follows:

at December 31, 2025			Total						< 1 year						1 - 3 years						4 - 5 years						> 5 years
(millions of $)
Long-term debt			29,434						2,387						4,496						3,875						18,676
Junior subordinated notes			44,193						742						1,618						1,677						40,156
			73,627						3,129						6,114						5,552						58,832

Purchase obligations

We have purchase obligations that are transacted at market prices and in the normal course of business, including long-term natural gas transportation and purchase arrangements.

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.

We have entered into PPAs with solar and wind-power generating facilities ranging from 2026 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 in 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.

84 | TC Energy Management's discussion and analysis 2025

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At December 31, 2025, payments for purchase obligations and other were as follows:

at December 31, 2025			Total						< 1 year						1 - 3 years						4 - 5 years						> 5 years
(millions of $)
Canadian Natural Gas Pipelines
Transportation by others1			181						41						77						45						18
Transportation by others - TQM1,2			2,574						152						317						316						1,789
Capital spending3			115						115						—						—						—
U.S. Natural Gas Pipelines
Transportation by others1			598						144						249						91						114
Capital spending3			569						311						180						78						—
Mexico Natural Gas Pipelines
Capital spending3			36						36						—						—						—
Power and Energy Solutions
Capital spending3			114						78						28						6						2
Other			190						26						40						28						96
Corporate
Capital spending3			3						3						—						—						—
South Bow pension plan assets held in trust4			17						17						—						—						—
Other			253						168						85						—						—
			4,650						1,091						976						564						2,019

1Demand rates are subject to change. The contractual obligations in the table are based on demand volumes only and exclude variable charges incurred when volumes flow.

2Includes 100 per cent of the contracted obligation for the Canadian Mainline to transport volumes for its shippers utilizing the TQM pipeline to 2042, which we have a 50 per cent ownership interest in. The cost of the contracts flow through to the Canadian Mainline shippers and is determined based on the revenue requirement outlined in the TQM settlement agreement.

3    Amounts are primarily for expenditures for capital projects. Amounts are estimates and are subject to variability based on timing of construction and project requirements.

4    Related to the transfer of pension assets to South Bow. Refer to the Obligations - pension and other post-retirement benefit plans section for additional information.

TC Energy Management's discussion and analysis 2025 | 85

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GUARANTEES

Sur de Texas

We and our partner on the Sur de Texas pipeline, IEnova Infraestructura Marina Holding B.V. (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. The guarantee has terms that can be renewed in June 2026, with the annual option to extend for one year periods ending in 2053.

At December 31, 2025, our share of potential exposure under the Sur de Texas pipeline guarantees was estimated to be         $78 million with a carrying amount of less than $1 million.

Bruce Power

We and our 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. The Bruce Power guarantee has a term that can be renewed in December 2027 and is extendable for any number of successive two-year periods, with a final renewal period of three years ending in 2065.

At December 31, 2025, our share of the potential exposure under the Bruce Power guarantee was estimated to be $88 million with no carrying amount.

Other jointly-owned entities

We and our partners in certain other jointly-owned entities have also guaranteed (jointly, severally, jointly and severally, or exclusively) the financial performance of these entities. Such agreements include guarantees and letters of credit which are primarily related to delivery of natural gas. The guarantees have terms ranging to 2032.

Our share of the potential exposure under these assurances was estimated at December 31, 2025 to be approximately $54 million with a carrying amount of $1 million. In certain cases, if we make a payment that exceeds our ownership interest, the additional amount must be reimbursed by our partners.

OBLIGATIONS – PENSION AND OTHER POST-RETIREMENT BENEFIT PLANS

In 2025, we made no funding contributions to our defined benefit pension plans (DB Plans), $8 million for other post-retirement benefit plans and $72 million for the savings plan and defined contribution plans. Total letters of credit provided for the funding of solvency requirements to the Canadian DB plan at December 31, 2025 was nil (2024 – $111 million; 2023 – $244 million).

In 2026, we do not expect to make any contributions to the DB Plans, $8 million of funding contributions for other post-retirement benefit plans and $76 million for the savings plans and defined contribution pension plans. We do not expect to issue additional letters of credit to the Canadian DB Plan for the funding of solvency requirements.

The net benefit cost for our DB Plans and other post-retirement plans decreased to $11 million in 2025 from $19 million in 2024 primarily due to decrease service costs in the Canadian retirement plan.

South Bow - transition of pension assets

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 our Consolidated balance sheet. The remaining South Bow pension assets will be adjusted to fair value on the date of transfer, which is expected mid-2026. As at     December 31, 2024, the assets related to the U.S. DB Plan were fully transferred to South Bow.

86 | TC Energy Management's discussion and analysis 2025

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Future net benefit costs and the amount we will need to contribute to fund our plans will depend on a range of factors including:

•interest rates

•actual returns on plan assets

•changes to actuarial assumptions and plan design

•actual plan experience versus projections

•amendments to pension plan regulations and legislation.

We do not expect future increases in the level of funding needed to maintain our plans to have a material impact on our liquidity or financial condition.

TC Energy Management's discussion and analysis 2025 | 87

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Discontinued operations

On October 1, 2024, TC Energy completed the spinoff of its Liquids Pipelines business into the new public company, South Bow. Upon completion of the Spinoff Transaction, the Liquids Pipelines business was accounted for as a discontinued operation.

Agreements

Pursuant to the Spinoff Transaction, TC Energy and South Bow have 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 imposes certain restrictions on both TC Energy and South Bow in order to preserve the tax-free status of the spinoff and allocates tax liabilities in the event the Spinoff Transaction is not tax-free.

The Separation Agreement sets 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.

In September 2025, we reached an agreement with South Bow with respect to liabilities we indemnified South Bow for under the Separation Agreement, releasing us from those liabilities. Inclusive of the recognition of the settlement, a net after-tax loss from discontinued operations of $183 million was recorded for the year ended December 31, 2025 and has been excluded from our calculation of comparable measures from discontinued operations. Payments related to the settlement commenced in fourth quarter 2025 and will be completed in 2026.

In June 2025, we received $24 million related to certain recoveries under the Separation Agreement with South Bow. At this time, we also revised our estimate of our share of future recoveries, resulting in a $29 million impairment charge, which has been included in Net income (loss) from discontinued operations, net of tax in the Consolidated statement of income and excluded from our calculation of comparable measures from discontinued operations.

For additional information regarding the agreement, incidents occurring prior to the Spinoff Transaction and separation costs, refer to Note 4, Discontinued operations, of our 2025 Consolidated financial statements and our 2024 Annual Report.

Presentation of Discontinued Operations

Upon completion of the Spinoff Transaction, the Liquids Pipelines business was accounted for as discontinued operations. Our presentation of discontinued operations includes revenues and expenses directly attributable to the Liquids Pipelines business.

Prior years' amounts present the Liquids Pipelines business as discontinued operations.

88 | TC Energy Management's discussion and analysis 2025

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RESULTS FROM DISCONTINUED OPERATIONS1

year ended December 31
(millions of $, except per share amounts)						2025						2024						2023
Segmented earnings (losses) from discontinued operations						(245)						716						1,039
Interest expense						—						(218)						(297)
Interest income and other						28						21						(30)
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
Net income (loss) per common share from discontinued operations – basic						($0.20)						$0.38						$0.60

1    Represents nine months of Liquids Pipelines earnings in 2024 and a full year of earnings in 2023.

Net loss from discontinued operations, net of tax in 2025 was $212 million or $0.20 per common share (2024 – net income of $395 million or $0.38 per common share; 2023 – net income of $612 million or $0.60 per common share), a decrease of         $607 million or $0.58 per common share compared to 2024 and a decrease of $217 million or $0.22 per common share in 2024 compared to 2023.

NON-GAAP MEASURES

This MD&A references non-GAAP measures, which are described on page 22. These measures do not have any standardized meaning as prescribed by GAAP and therefore may not be comparable to similar measures presented by other entities.

The following specific items were recognized in Net income (loss) from discontinued operations, net of tax and were excluded from comparable earnings from discontinued operations:

2025

•a pre-tax charge of $188 million primarily related to the liabilities we indemnified South Bow for under the Separation Agreement

•a pre-tax impairment charge of $29 million related to our estimate of Keystone XL contractual recoveries.

2024

•a pre-tax charge of $197 million from Liquids Pipelines business separation costs related to the Spinoff Transaction, of which $173 million was recognized in segmented earnings (losses) from discontinued operations, $42 million was recorded in interest expense and $18 million was recorded in interest income

•a pre-tax expense of $37 million related to our estimate of potential incremental costs resulting from the Milepost 14 incident. This amount represents our 86 per cent share pursuant to the indemnity provisions in the Separation Agreement

•a pre-tax expense of $21 million related to Keystone XL asset disposition and termination activities

•a pre-tax charge of $12 million as a result of the FERC Administrative Law Judge decision on Keystone in respect of a     tolling-related complaint pertaining to amounts recognized in prior periods.

2023

•a pre-tax charge of $67 million as a result of the FERC Administrative Law Judge decision on Keystone in respect of a     tolling-related complaint pertaining to amounts recognized in prior periods, which consists of a one-time pre-tax charge     of $57 million and included accrued pre-tax carrying charges of $10 million

•a pre-tax charge of $40 million from Liquids Pipelines business separation costs related to the Spinoff Transaction

•a pre-tax accrued insurance expense of $36 million related to the Milepost 14 incident

•pre-tax preservation and other costs of $18 million related to the preservation and storage of the Keystone XL pipeline project assets

•a pre-tax recovery of $4 million related to the net impact of a U.S. minimum tax recovery on the 2021 Keystone XL asset impairment charge and other and a gain on the sale of Keystone XL project assets, offset partially by adjustments to the estimate for contractual and legal obligations related to termination activities.

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Reconciliation of net income (loss) from discontinued operations, net of tax to comparable earnings from discontinued operations1

year ended December 31
(millions of $, except per share amounts)						2025						2024						2023
Net income (loss) from discontinued operations, net of tax						(212)						395						612
Specific items (pre tax):
South Bow settlement2						188						—						—
Keystone XL asset impairment charge and other						29						21						(4)
Liquids Pipelines business separation costs						—						197						40
Milepost 14 incremental costs						—						37						—
Keystone regulatory decisions						—						12						67
Milepost 14 insurance expense						—						—						36
Keystone XL preservation and other						—						—						18
Risk management activities						—						(67)						34
Taxes on specific items						(5)						(30)						(47)
Comparable earnings from discontinued operations						—						565						756
Net income (loss) per common share from discontinued operations						($0.20)						$0.38						$0.60
Specific items (net of tax)						0.20						0.16						0.14
Comparable earnings per common share from discontinued operations						—						$0.54						$0.74

1    Represents nine months of Liquids Pipelines earnings in 2024 and a full year of earnings in 2023.

2    A pre-tax charge of $188 million for the year ended December 31, 2025 primarily resulting from the resolution reached in September 2025 under the Separation Agreement with South Bow.

90 | TC Energy Management's discussion and analysis 2025

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Comparable EBITDA to comparable earnings - from discontinued operations1

Comparable EBITDA from discontinued operations represents segmented earnings (losses) from discontinued operations adjusted for the specific items described above and excludes charges for depreciation and amortization.

year ended December 31
(millions of $, except per share amounts)												2024						2023
Comparable EBITDA from discontinued operations												1,145						1,516
Depreciation and amortization												(253)						(332)
Interest expense included in comparable earnings2												(176)						(287)
Interest income and other included in comparable earnings3												3						6
Income tax (expense) recovery included in comparable earnings4												(154)						(147)
Comparable earnings from discontinued operations												565						756
Comparable earnings per common share from discontinued operations												$0.54						$0.74

1    Represents nine months of Liquids Pipelines earnings in 2024 and a full year of earnings in 2023.

2    Excludes pre-tax Liquids Pipelines business separation costs of $42 million related to interest expense on the South Bow debt issuance in third quarter 2024 and carrying charges of $10 million for the year ended December 31, 2023 as a result of a pre-tax charge related to the FERC Administrative Law Judge decision on Keystone in respect of a tolling-related complaint pertaining to amounts recognized in prior periods.

3    Excludes pre-tax income of $18 million for the year ended December 31, 2024 related to the net impact of interest income on proceeds from the South Bow debt issuance on August 28, 2024, which were held in escrow and insurance provisions as well as a $36 million pre-tax insurance expense recorded in 2023 related to the Milepost 14 incident.

4    Excludes the impact of income taxes related to the specific items mentioned above as well as a $14 million U.S. minimum tax recovery in 2023 on the     Keystone XL asset impairment charge and other related to the termination of the Keystone XL pipeline project.

Comparable EBITDA from discontinued operations

Comparable EBITDA from discontinued operations was $371 million lower in 2024 compared to 2023 primarily due to the net effect of:

•nine months of Liquids Pipelines earnings included in 2024 compared to a full year of Liquids Pipelines earnings in 2023

•higher contracted and uncontracted volumes across the Keystone Pipeline System in 2024

•lower contributions from the liquids marketing business due to lower realized margins.

Comparable earnings from discontinued operations

Comparable earnings from discontinued operations in 2024 were $191 million or $0.20 per common share lower than in 2023, and were primarily due to the impact of nine months of Liquids Pipelines business earnings in 2024 compared to a full year
in 2023.

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FINANCIAL RESULTS - 2024 and 20231

The following is a reconciliation of comparable EBITDA from discontinued operations and comparable EBIT from discontinued operations (our non-GAAP measures) to segmented earnings (losses) from discontinued operations (the most directly comparable GAAP measure). Refer to page 22 for more information on non-GAAP measures we use.

For information on 2025 comparable measures from discontinued operations refer to page 89.

year ended December 31
(millions of $)												2024						2023
Keystone Pipeline System												1,098						1,453
Intra-Alberta pipelines2												52						70
Other												(5)						(7)
Comparable EBITDA from discontinued operations												1,145						1,516
Depreciation and amortization												(253)						(332)
Comparable EBIT from discontinued operations												892						1,184
Specific items (pre tax):
Liquids Pipelines business separation costs												(173)						(40)
Milepost 14 incremental costs												(37)						—
Keystone XL asset impairment charge and other												(21)						4
Keystone regulatory decisions												(12)						(57)
Keystone XL preservation and other												—						(18)
Risk management activities												67						(34)
Segmented earnings (losses) from discontinued operations												716						1,039

1    Represents nine months of Liquids Pipelines earnings in 2024 and a full year of earnings in 2023.

2    Intra-Alberta pipelines includes Grand Rapids and White Spruce.

Segmented earnings from discontinued operations decreased by $323 million in 2024 compared to 2023 and included the specific items mentioned in the table above, which have been excluded from our calculation of comparable EBITDA from discontinued operations and comparable EBIT from discontinued operation. Refer to page 89 for additional information.

A stronger U.S. dollar in 2024 and 2023 had a positive impact on the Canadian dollar equivalent segmented earnings from our U.S. operations.

Depreciation and amortization

Depreciation and amortization was $79 million lower in 2024 compared to 2023 due to nine months of Liquids Pipelines operations in 2024 compared to a full year of Liquids Pipelines operations in 2023.

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Interest expense1

year ended December 31
(millions of $)												2024						2023
Interest expense included in comparable earnings from discontinued operations												(176)						(287)
Specific items:
Liquids Pipelines business separation costs												(42)						—
Keystone regulatory decisions												—						(10)
Interest expense from discontinued operations2												(218)						(297)

1    Represents nine months of Liquids Pipelines allocated interest expense in 2024 and a full year of allocated interest expense in 2023.

2    We have elected to allocate a portion of the interest expense incurred at the corporate level to discontinued operations. Refer to our 2024 Annual Report for
additional information.

Interest expense included in comparable earnings from discontinued operations decreased by $111 million in 2024 compared to 2023 due to nine months of interest expense included in 2024 compared to a full year in 2023.

Interest income and other1

year ended December 31
(millions of $)												2024						2023
Interest income and other included in comparable earnings from discontinued operations												3						6
Specific items:
Liquids Pipelines business separation costs												18						—
Milepost 14 insurance expense												—						(36)
Interest income and other from discontinued operations												21						(30)

1    Represents nine months of Liquids Pipelines earnings in 2024 and a full year of earnings in 2023.

Interest income and other included in comparable earnings from discontinued operations was generally consistent 2024 compared to 2023.

Income tax (expense) recovery1

year ended December 31
(millions of $)												2024						2023
Income tax (expense) recovery included in comparable earnings from discontinued operations												(154)						(147)
Specific items:
Liquids Pipelines business separation costs												30						6
Milepost 14 incremental costs												9						—
Keystone XL asset impairment charge and other												5						14
Keystone regulatory decisions												2						15
Keystone XL preservation and other												—						4
Risk management activities												(16)						8
Income tax (expense) recovery from discontinued operations												(124)						(100)

1    Represents nine months of Liquids Pipelines earnings in 2024 and a full year of earnings in 2023.

Income tax expense included in comparable earnings from discontinued operations increased by $7 million in 2024 compared to 2023 primarily due to lower foreign income tax rate differentials largely offset by lower earnings.

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Other information

RISK OVERSIGHT AND ENTERPRISE RISK MANAGEMENT

Risk management is embedded in all activities at TC Energy and is integral to the successful operation of our business. Our strategy ensures that risks and related exposures are aligned with our business objectives and risk tolerances. We achieve this through a centralized Enterprise Risk Management (ERM) program, which systematically identifies and assesses risks that could materially impact our strategic objectives.

The ERM program addresses risks related to executing our business strategies and supports practices for identifying and monitoring emerging risks. Specifically, the ERM framework offers a comprehensive process for risk identification, analysis, evaluation and mitigation. It also ensures ongoing monitoring and reporting to the Board of Directors, CEO, Executive         Vice-Presidents and the Chief Risk Officer.

Board and Committee Oversight

Our Board of Directors retains general oversight over all enterprise risks. Annually, the Board reviews the enterprise risk register and receives quarterly updates on emerging risks and their management and mitigation in accordance with TC Energy’s risk appetite and tolerances. Additionally, the Board receives detailed presentations on enterprise risks quarterly, with specific themes addressed during regular financial updates and strategic meetings. Special presentations are also delivered as needed or upon request.

The Governance Committee of our Board oversees the ERM program, ensuring comprehensive oversight of our risk management activities. In addition, other Board committees oversee specific risk types within their mandates:

•the Human Resources Committee oversees executive resourcing, organizational capabilities and compensation risk to ensure human and labour policies and remuneration practices align with our overall business strategy

•the HSSE Committee oversees operational, major project execution, health, safety, sustainability and environmental risks, including climate-related risks

•the Audit Committee oversees management's role in mitigating financial risk, including market risk, insurance risk, counterparty credit risk and cybersecurity risk.

Executive Leadership and Risk Management

Our Executive Leadership team is responsible for developing and implementing risk management plans and actions, with effective risk management reflected in their compensation. Each identified enterprise risk has a governance owner from the executive leadership team. Risk execution is overseen by an accountable business unit President or Senior Vice-President. These risk owners provide in-depth risk reviews to the Board annually.

Segment-Specific Risks

Key segment-specific financial, health, safety and environment-related risks are covered in their respective sections of this MD&A. Further, our Report on Sustainability provides information on our approach to sustainability, including the oversight of sustainability-related risks and opportunities.

Enterprise Risk Monitoring and Key Risk Indicators

Risks related to our key enterprise risk themes are continuously monitored through our ERM program. The program includes a network of emerging risk liaisons strategically positioned across the organization, responsible for identifying potential enterprise-level risks and reporting them quarterly to the Board of Directors.

Additionally, as part of our ongoing commitment to enhancing the ERM program, we employ Key Risk and Performance Indicators (KRIs) to monitor risk events that could impact our strategic objectives. These KRIs provide quantifiable metrics, objective rationale and meaningful trends for each enterprise risk, helping to inform the annual in-depth review of enterprise risks conducted by the Board.

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Operational risk

Across North America, TC Energy manages a vast natural gas transmission network that includes numerous facilities, gas storage reservoirs and power-generation plants. Operational risks include the potential for significant ruptures or failures, especially in regions where pipelines traverse populated areas. Key factors contributing to these risks include integrity threats such as corrosion, cracking and manufacturing defects and third-party damage. Additionally, aging infrastructure and the potential for extreme weather conditions and other external forces further increase the likelihood of significant ruptures or operational failures.

The consequences of a significant rupture or operational failure can be severe and multifaceted. Potential impacts include loss of human life or severe injuries, environmental damage and extensive operational disruptions. Financial repercussions are also considerable, encompassing costs related to incident response, repairs, fines and penalties. Furthermore, such incidents can lead to incremental regulatory enforcement and reputational harm, which may strain customer relationships and jeopardize future projects.

To ensure the safe and reliable operation of its assets, TC Energy employs a robust Operational Management System, TOMS, that integrates comprehensive risk management and asset integrity practices. Current measures include a quantitative operational risk assessment process, integrity management programs and advanced inline inspection technologies. We also conduct failure investigations and root cause analyses to drive continuous improvement. Governance and oversight by senior management, along with an Emergency Management Program, ensure preparedness and effective response to potential incidents. TOMS standards, processes and procedures are continually improved based on lessons learned from internal and external incidents, as well as collaborative work with industry peers and regulators.

Regulatory risk

TC Energy operates in a highly regulated industry across North America, requiring various permits and approvals from federal, state, provincial and local government agencies. The regulatory landscape is highly complex, with overlapping and sometimes conflicting requirements from various levels of government. Changes in government can further introduce uncertainty and delays in obtaining necessary permits. Additionally, opposition groups can influence regulatory decisions through organized protests, legal challenges and negative media campaigns.

Failure to obtain or maintain regulatory approvals for energy infrastructure projects can lead to substantial financial and operational consequences. These include delays or cancellations of critical projects, increased operating costs due to additional compliance requirements and disruptions to existing infrastructure. Financial impacts also encompass lost development costs, reduced investor confidence and higher capital costs. Moreover, negative publicity and public opposition can damage our reputation, erode public trust and hinder our ability to operate effectively. These challenges can ultimately affect our competitive position and ability to meet growth objectives.

To address this risk, we have implemented several monitoring and mitigation strategies. These include proactive efforts to monitor the evolving regulatory environment, engage in strategic advocacy across all levels of government, cultivate enduring trust and alignment with stakeholders and respond promptly to emerging issues and concerns. These activities are designed to secure necessary approvals to support our growth objectives and mitigate potential delays and disruptions.

Access to capital at a competitive cost

We require significant capital in the form of debt and equity to finance our growth projects and manage maturing debt obligations. It is essential that we secure this capital at costs lower than the returns on our investments. Deterioration in market conditions, changes in investor and lender sentiment, geopolitical instability, higher interest rates and persistent inflation could adversely affect our access to and cost of capital. Additionally, factors such as investor ESG exclusionary screening, capacity limitations in capital markets and economic uncertainties can further compound these risks, potentially leading to higher borrowing costs and constrained growth.

A higher cost of capital can negatively impact our ability to deliver attractive returns on investments and inhibit both
short- and long-term growth. This could adversely affect our earnings and undermine the viability of capital projects. Additionally, higher costs can negatively impact investor confidence, the reported value of assets and liabilities and our overall financial performance.

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TC Energy employs a comprehensive strategy to monitor and mitigate these risks. Current mitigations include maintaining a high-quality and diversified banking syndicate, proactive engagement with lenders and credit rating agencies and balancing issuance strategies across multiple capital markets. We also actively manage our foreign exchange risk through hedging strategies and maintain a balanced debt portfolio to manage interest rate exposure. Ongoing mitigations involve developing new lending relationships and enhancing engagement with ESG-focused investors. Additionally, TC Energy continuously monitors government policies and industry developments to proactively address potential influences on capital flows.

Capital allocation

To remain competitive, TC Energy must provide essential energy infrastructure services in both supply and demand areas, offering solutions that appeal to our customers, while maintaining alignment with our strategic objectives. Capital allocation challenges include balancing investments to defend our existing footprint and service our customer base, investing in the highest-return, lowest-risk opportunities within our discretionary annual net capital limit and shaping the capital program to optimally utilize available capital.

Inefficient capital allocation can lead to the misallocation of financial resources to projects that do not align with our strategic objectives, increase exposure to high-risk projects and reduce financial performance. Additionally, failure to adapt to changing energy supply and demand fundamentals, including those related to lower-carbon forms of energy, may result in reputational damage, regulatory risks and the potential for stranded assets. Diversifying capital into emerging or alternative energy businesses before technologies, commercial models, and regulatory frameworks have matured also poses risk. Overall, these risks can cause strategic misalignment and diminish shareholder value.

We have a rigorous governance process to maintain capital allocation discipline. We limit annual net capital expenditures and high-grade our project development pipeline for purposes of pursuing lower risk and higher value opportunities. We also conduct analyses to confirm the resilience of the supply and demand markets we serve as part of our strategic reviews and regularly monitor industry trends and regulatory developments. Continuous improvements to the capital allocation process include enhanced investment review and due diligence, as well as conducting long-term scenario analyses to understand the portfolio effects of capital allocation choices.

Capital recovery risk

Capital recovery risk pertains to the challenge of both earning an acceptable return on invested capital and recovering the initial investment. This risk arises from potential misalignment between deal structures and our risk preferences, leading to capital exposure. Key contributors include inadequate risk assessments, difficulties in stakeholder collaboration, unforeseen changes in project scope or environment, financial constraints, macroeconomic volatility, counterparty risk, regulatory risk and evolving public policy. Collectively, these factors threaten our financial stability and strategic objectives.

The inability to recover a return on capital can lead to unexpected capital expenditures, significant financial losses and reduced returns. It can erode trust and credibility with partners, investors, regulators and other key stakeholders. Additionally, poorly structured deals may divert management’s focus from core business activities to address arising issues, further impacting operational efficiency. The broader consequences include potential damage to our reputation and investor confidence, which are crucial for sustaining long-term growth and stability and preserving shareholder value.

TC Energy employs a robust due diligence process that includes comprehensive risk assessments and detailed contract negotiations. Continuous monitoring of risk exposures and mitigation measures is conducted throughout the lifecycle of each deal, high-grading our project development pipeline to the lowest-risk, highest-value opportunities. Proactive engagement with counterparties and strategic partnerships helps manage and share risks effectively. Depreciation is recovered through regulated pipeline rates, allowing us to accelerate or decelerate the return of capital from our assets. Additionally, we leverage our diversified asset base and long-term contracts to stabilize cash flows and reduce exposure to market volatility.

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Project execution

Investing in large infrastructure projects requires significant capital commitments and carries considerable project execution risks. Potential shortages of skilled labour and expertise, supply chain lead times and disruptions and increasing project and regulatory complexity are among these risks. Collectively, these factors can lead to cost overruns, schedule delays, suboptimal project performance and increased safety vulnerabilities, ultimately impacting our financial performance, reputation and strategic growth.

Failure to effectively manage these risks can result in significant financial and operational consequences. Cost overruns and schedule delays can undermine the profitability and feasibility of projects, leading to increased contractual claims and disputes. Additionally, inadequate project execution can damage our reputation, reduce investor confidence and hinder future growth opportunities.

To help mitigate these risks, our Project Delivery System is integrated with our capital allocation process and is aligned with TOMS, optimizing project execution for safe, timely and on-budget performance. We develop projects to a sufficient maturity level to fully understand scope, cost, schedule and execution risk prior to sanctioning. This approach enables us to identify and consult stakeholders and proactively address project-specific constraints and risks. Commercial contracts are structured to recover development costs and minimize the impact of potential cost overruns, explicitly sharing execution risk where warranted. Additionally, we leverage project financing and partner involvement to manage capital at risk.

Talent risk

TC Energy's success hinges on attracting, retaining and developing a talented workforce with a deep understanding of the energy industry, geopolitical environment and various regulatory regimes across North America. Key talent-related risks include the loss of critical personnel, difficulties in securing and retaining talent in a highly competitive market and health and wellness issues that could impact workforce productivity.

Failure to manage talent-related risk can lead to several adverse outcomes, including a decline in employee morale and engagement, resulting in reduced productivity, efficiency and quality of work. High resignation rates, particularly among top talent, can disrupt operations and continuity, leading to increased recruitment and training costs. The organization may also face reputational damage if perceived as failing to address employee concerns, impacting its ability to attract and retain future talent. Furthermore, operational disruptions and a disengaged workforce can pose health and safety risks, ultimately affecting our overall performance and strategic execution.

To mitigate these risks, TC Energy employs a comprehensive talent risk management framework to assess needs and prioritize initiatives. We focus on employee development, engagement and well-being to foster a positive work environment and retain top talent. Our competitive approach to pay for performance promotes fairness and transparency in compensation practices, while our succession planning process ensures a steady pipeline of talented individuals are prepared to assume critical roles. Regular employee engagement surveys help us translate employee input into meaningful action and improvements. Additionally, we have integrated inclusion and equal opportunity initiatives into our talent management strategies and implemented a hybrid work schedule to offer greater flexibility. Collectively, this approach promotes employee retention, minimizes the impact of potential talent losses and guides targeted development actions.

Enterprise security

Ensuring the security of our stakeholders, staff and our assets is paramount to maintaining the safety and reliability of our operations. Security risks encompass potential cyberattacks on industrial control systems and corporate digital assets, unauthorized data disclosures and physical attacks on our infrastructure. These risks are heightened by the increasing sophistication of cyber tactics, rising geopolitical tensions and the critical nature of our business.

A security incident can result in the misuse or disruption of critical information and functions, cause damage to our assets and potentially lead to safety and/or environmental incidents. Resulting service interruptions may have cascading effects on supply chains, customer relationships and strategic goals. Additionally, such incidents can harm our reputation and trigger regulatory enforcement actions or litigation, negatively impacting our operations and/or financial position.

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TC Energy maintains an enterprise security program that encompasses both cyber and physical security. Our program is based on standards, assurance and risk management combining prevention and mitigation activities. Our preventative efforts include deploying advanced security technology, defining secure processes, implementing enhanced security measures for high-risk staff or facilities and delivering cyber and physical security awareness programs. Our mitigative activities include proactive monitoring and response to potential security incidents. We also maintain and regularly test incident response plans to manage and mitigate the impact of potential security incidents, including cyberattacks. To further mitigate potential risks, we maintain insurance coverage against cyber and physical security incidents. To mitigate risks associated with third-party vendors and suppliers, we conduct vendor risk assessments, which includes evaluations of security standards, contractual safeguards and ongoing monitoring.

We collaborate with government security agencies, law enforcement and industry to stay informed and be proactive on evolving threats. Our prevention and mitigation strategies for both cyber and physical security are regularly reviewed and updated to align with regulatory and industry standards. The status of our enterprise security program is reported to the Audit Committee quarterly.

TC Energy remains committed to continually improving our security posture and adapting to the ever-evolving threat landscape. By prioritizing security and investing in technologies and practices, we strive to protect our stakeholders, staff, assets, operations and ensure the long-term sustainability of our business.

Climate-related risks

Our business, operations, financial condition and performance may be impacted by both the physical risks associated with climate change and the transition risks arising from the global transition to a lower-carbon economy. Climate-related risks, including changes to climate policy and related developments, may intersect with and influence the enterprise risks outlined above. Therefore, these risks are systematically considered and assessed as part of our risk management framework.

We periodically conduct climate scenario analysis to support our strategic planning and risk management processes. This allows us to assess the resiliency of our business strategy and strengthen our understanding of potential climate-related risks and opportunities across various energy transition pathways. We do not assign probabilities to these scenarios, nor do we consider them to be forecasts or expected outcomes.

Physical Risks

Physical climate hazards caused by climate change can be either event-driven (acute), with immediate, severe impacts, or gradual (chronic), resulting from persistent, long-term shifts in climate patterns. The frequency and severity of climate hazards, particularly acute weather events, are difficult to predict. Climate hazards vary greatly across different geographical regions depending on weather patterns, topography and proximity to bodies of water. Many of our natural gas pipeline assets are underground, inherently reducing the exposure to certain types of climate hazards. Exposure to physical climate hazards could have significant financial implications, such as unexpected costs resulting from direct damage to our assets, additional costs for preventative measures, loss of revenues due to business interruption, or indirect effects such as value chain disruption.

If our exposure to climate hazards intensifies, we can implement preventative measures to enhance the resilience of our assets, tailoring these measures to the nature of the hazard and the characteristics of each asset. Additionally, our emergency response plans focus on quickly and effectively responding to severe weather events to minimize impacts. As a further risk mitigation measure, we maintain insurance coverage to reduce the financial impact associated with damage to our assets due to extreme weather events. However, insurance does not cover all events in all circumstances and we may experience an increase in insurance premiums and deductibles, or a decrease in available coverage for our assets in areas subject to severe weather.

Transition Risks

Transition risks arise from the global shift toward a lower-carbon economy, and include policy, legal, technological, market and reputational risks. These risks may involve changes in energy supply and demand trajectories, the pace and reliability of technological advancements, changes in decarbonization policies and regulations and stakeholder perceptions of our role in the transition to a lower-carbon economy.

Financial implications could include asset impairments due to new or amended climate-related regulations, reduced demand for fossil fuels, challenges in permitting projects and limited access to and/or increased cost of capital. Our financial performance could also be impacted by shifting consumer demands, insolvency of our significant customers and the development and deployment of new technologies.

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In the medium term, these risks would be partially mitigated through our low-risk business model, whereby much of our earnings are underpinned by regulated cost-of-service arrangements and/or long-term contracts with credit-worthy counterparties. Regulators also often permit accelerated depreciation of regulated assets, allowing faster recovery of asset value and helping offset potential terminal value risk if climate policies shorten asset life.

A shift to a lower-carbon economy could also present substantial investment opportunities in emerging energy markets and technologies. Our existing capabilities in lower-carbon energy generation, including nuclear power and energy storage technologies, could enable us to capitalize on new lower-carbon energy opportunities. Our pipeline network across North America also provides an extensive footprint of linear infrastructure that could be leveraged to transport emerging clean fuels like hydrogen and renewable natural gas, as well as to facilitate the transportation of captured carbon emissions for sequestration.

Additional information on our climate strategy and climate-related risks and opportunities can be found in the climate-related disclosures section of our annual Report on Sustainability.

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Health, safety, sustainability and environmental matters

The Board's HSSE Committee oversees operational risk, major project execution risk, occupational and process safety, sustainability, security of personnel, environmental and climate change-related risks, as well as monitoring development and implementation of systems, programs and policies relating to HSSE matters through regular reporting from management.     We use an integrated management system that establishes a framework for managing these risks and is used to capture, organize, document, monitor and improve our related policies, standards and procedures.

TC Energy's Operational Management System, TOMS, leverages industry best practices and standards and incorporates applicable regulatory requirements. TOMS governs health, safety, environment and operational integrity matters at TC Energy. It is applicable across Canada, the U.S. and Mexico throughout the lifecycle of our assets and employs a continuous improvement cycle. The TOMS framework leverages continuous improvement through an annual management review process. This ensures the ongoing effectiveness of our overarching management system and supports a tiered assurance structure across all business units. The TC Energy assurance model is designed to provide effective management of health, safety, environmental and operational integrity risks. Lessons learned are consistently shared and applied across our system where applicable. Additionally, any findings or insights from periodic audits conducted by our external regulators are also shared across the elements of our management system to ensure continuous improvement.

The HSSE Committee reviews performance and operational risk management. It receives updates and reports on:

•overall HSSE corporate governance

•operational performance

•asset integrity

•significant occupational safety and process safety incidents

•occupational and process safety performance metrics

•occupational health, safety and industrial hygiene, which includes physical and mental health, as well as psychological safety

•emergency preparedness, incident response and evaluation

•environment, including biodiversity and land reclamation

•developments in and compliance with, applicable legislation and regulations, including those related to climate and the environment

•prevention, mitigation and management of risks related to HSSE matters, including climate policy or business interruption risks, such as pandemics, which may adversely impact TC Energy

•sustainability matters, including social, environmental and climate-related risks and opportunities, as well as related         non-regulatory public disclosures such as our annual Report on Sustainability, our Reconciliation Action Plan and updates on the progression of our commitments.

There are two separate committees that report to the Board HSSE Committee:

•a Sustainability Management Committee, comprised of senior leaders and heads of business units from across the company, that provides strategic direction on sustainability-related matters and fosters cross-functional collaboration across the organization

•Safety and TOMS Advisory Committee (STAC), comprised of senior project and operations leaders, oversees governance and decision-making for TOMS and safety initiatives, while assuming an enterprise-wide role to oversee and guide health, safety, environment and operational integrity. In 2025, governance accountability transitioned from the Operating Committee to the relevant business leadership teams, business unit-specific operating committees and STAC.

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Health, safety and asset integrity

The safety of our employees, contractors and the public, the integrity of our pipelines and our power and energy solutions infrastructure, are a top priority. All assets are designed, constructed, commissioned, operated and maintained with full consideration given to safety and integrity and are placed in service only after all necessary requirements, both regulatory and internal, have been satisfied.

In 2025, we spent approximately $2.0 billion (2024 – $2.0 billion) for pipeline integrity on the natural gas pipelines we operate, which includes expenditures related to our modernization program within our U.S. Natural Gas Pipelines business. Pipeline integrity spending will fluctuate based on the results of on-going risk assessments conducted on our pipeline systems and evaluations of information obtained from recent inspections, incidents and maintenance activities.

Under the approved regulatory models in Canada, non-capital pipeline integrity expenditures on CER-regulated natural gas pipelines are generally treated on a flow-through basis and, as a result, fluctuations in these expenditures generally have no impact on our earnings. Non-capital pipeline integrity expenditures on our U.S. natural gas pipelines are primarily treated as operations and maintenance expenditures and are typically recoverable through tolls approved by FERC. Under regulatory rules in Mexico, non-capital pipeline integrity expenditures and those under lease accounting are treated primarily as operating and maintenance expenses and are generally recovered through our tolls.

Spending associated with process safety and integrity is used to minimize risk to employees, contractors, the public, equipment and the surrounding environment and also prevent disruptions to serving the energy needs of our customers.

As described in the Risk oversight and enterprise risk management section above, we have a set of procedures in place to manage our response to natural disasters, which include catastrophic events such as forest fires, tornadoes, earthquakes, floods, volcanic eruptions and hurricanes. The procedures, which are included in our Emergency, Business Continuity and Security element of TOMS, are designed to help protect the health and safety of our employees and contractors, minimize risk to the public and limit the potential for adverse effects on the environment. We are committed to protecting the health and safety of all individuals involved in our activities. Occupational health, safety and industrial hygiene provides comprehensive strategies for health promotion and protection. We are committed to delivering effective programs that:

•reduce the human and financial impact of illness and injury

•ensure fitness for work

•strengthen worker resiliency

•build organizational capacity by focusing on individual wellbeing, health education, leader support and improved working conditions to sustain a productive workforce

•increase mental wellbeing awareness, provide various health and wellness supports and training to employees and leaders, measure the success of programs and improve psychological safety

•foster a strong safety culture by building human and organizational performance to strengthen our cultural defenses and develop error-tolerant systems to better protect our people.

Environmental risk, compliance and liabilities

Through the implementation of TOMS, TC Energy proactively and systematically manages environmental hazards and risks throughout the lifecycle of our assets. Project plans are communicated with stakeholders and Indigenous communities, as applicable and engagement with these groups informs the environmental assessments and protection plans. Project environmental assessments include field studies that examine existing natural resources, biodiversity and land use along our proposed project footprint, such as vegetation, soils, wildlife, water resources, wetland and protected areas. We consider the information collected during environmental assessments and where sensitive habitats or areas of high biodiversity value are identified, we apply the biodiversity mitigation hierarchy and avoid those areas, as practicable. Where those areas cannot be avoided, we minimize our disturbance, restore and reclaim the disturbed area and provide offsets where required. To conserve and protect the environment during construction, information gathered for an environmental impact assessment is used to develop project-specific environmental protection plans. Whenever the potential exists for a proposed facility or pipeline to interact with water resources, we conduct evaluations to understand the full nature and extent of the interactions. When we temporarily use water to test the integrity of our pipelines, we adhere to strict regulatory requirements and ensure water meets applicable water quality standards before it is discharged or disposed of and when our construction activities involve crossing waterbodies, we implement protection measures to avoid or minimize potential adverse effects.

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Our primary sources of risk related to the environment include:

•evolving regulations and compliance requirements, alongside rising costs associated with environmental impacts

•product releases with potential environmental impact

•use, storage and disposal of chemicals and hazardous materials

•natural disasters and other catastrophic events, including those related to climate change, which may impact our operations.

Our assets are subject to federal, state, provincial and local environmental statutes and regulations governing environmental protection, including air and GHG emissions, water quality, species at risk, wastewater discharges and waste management. Operating our assets requires obtaining and complying with a wide variety of environmental registrations, licenses, permits and other approvals and requirements. Failure to comply could result in administrative, civil or criminal penalties, remedial requirements, or orders affecting future operations.

TOMS includes requirements for us to continually monitor our facilities for compliance with all material legal and regulatory environmental requirements across all jurisdictions where we operate. We also comply with all material legal and regulatory permitting requirements in our project routing and development. We routinely monitor proposed changes to environmental policy, legislation and regulation. Where the risks are uncertain or have the potential to affect our ability to effectively operate our business, we comment on proposals independently or through industry associations.

We are not aware of any material outstanding orders, claims or lawsuits against us related to releasing or discharging any material into the environment.

Compliance obligations can result in significant costs associated with installing and maintaining pollution controls, fines and penalties resulting from any failure to comply and potential limitations on operations. Remediation obligations can result in significant costs associated with the investigation and remediation of contaminated properties and with damage claims arising from the contamination of properties.

The timing and complete extent of future expenditures related to environmental matters is difficult to estimate
accurately because:

•environmental laws and regulations and their interpretations and enforcement change

•new claims can be brought against our existing or discontinued assets

•our pollution control and clean-up cost estimates may change, especially when our current estimates are based on preliminary site investigations or agreements

•new contaminated sites may be found or what we know about existing sites could change

•where there is potentially more than one responsible party involved in litigation, we cannot estimate our joint and several liability with certainty.

At December 31, 2025, accruals related to these obligations totaled $6 million (2024 – $8 million) representing the estimated amount we will need to manage our currently known material environmental liabilities. We believe we have considered all necessary contingencies and established appropriate reserves for environmental liabilities; however, a risk exists that unforeseen matters may arise requiring us to set aside additional amounts. We adjust reserves regularly to account for changes in liabilities.

Climate policy and related regulation

We own assets and have business interests in a number of regions subject to GHG emissions regulations, including GHG emissions management and carbon pricing policies. In 2025, we incurred $194 million (2024 – $141 million) of expenses under existing carbon pricing programs. Across North America, there are a variety of new and evolving climate policy developments at the federal, regional, state and provincial levels. We actively monitor, participate in the regulatory review process as appropriate and submit formal comments to regulators as initiatives are undertaken and as policies are implemented. We support transparent, investment-conducive climate policies that promote environmentally and economically responsible natural resource development through market-driven and economically efficient outcomes. Our assets in certain geographies are currently subject to GHG regulations. While near-term government policy objectives may influence the pace of GHG regulations, we expect that the number of our assets subject to GHG regulations will continue to increase over time and across our footprint. Changes in regulations may often result in higher operating costs, other expenses or capital expenditures, which are generally recoverable through established cost-recovery mechanisms.

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Jurisdictional policies

This section describes the most relevant existing and emerging policies affecting our business, emphasizing legislative and regulatory impacts.

In the U.S., we have seen significant policy shifts under the current administration. In January 2025, several Executive Orders directed agency heads to use all available legal authority to enhance U.S. energy production, transportation and consumption, and to focus on energy production and utilization (“energy dominance”). Additionally, in March 2025, the U.S. Environmental Protection Agency (USEPA) outlined a list of plans, including changes to some USEPA programs, and the intent for administrative reconsideration of many rules promulgated under the previous administration that have now started to advance through the regulatory process. Substantial uncertainty exists with respect to future implementation of these rules and the scope of the USEPA’s jurisdiction more generally. Depending upon the outcome of certain rulemakings and associated litigation challenging new rules, TC Energy could face increased project delays. We continue to monitor these potential regulatory changes to determine our compliance obligations and potential costs.

Existing policies

•Carbon pricing policies (multi-jurisdictional): While carbon pricing exists in several jurisdictions where we operate, its applicability to our assets and associated compliance costs vary substantially. Carbon pricing policies with significant impact on our business include the following:

◦Canada – Alberta’s Technology Innovation and Emissions Reduction (TIER) program represents our largest compliance costs in Canada. For our regulated Canadian natural gas pipelines within the province, we recover these costs through tolls. For our Power and Energy Solutions assets, we recover a portion of these costs through market pricing and hedging activities

◦U.S. – certain GTN compressor facilities are subject to the Washington Cap-and-Invest Program. GTN’s compliance costs are driven by total facility emissions, and GTN is authorized to recover these costs through its rates over time

•Clean Electricity Regulations (Canada): In 2024, Environment and Climate Change Canada (ECCC) published the final Clean Electricity Regulations (CERs) to transition Canada’s electricity system to net-zero electricity by 2050. The CERs mandate an annual GHG emissions limit based on 65 tonnes CO2/GWh for fossil fuel power generation units with a capacity of 25 MW or more starting in 2035 and zero tonnes CO2/GWh in 2050. Concerns persist on the CERs’ potential effect on energy affordability and reliability in certain provinces given the regulations limited compliance flexibilities. We continue to evaluate the operational and financial impact on TC Energy cogeneration plants. The Canada-Alberta Memorandum of Understanding (MOU), signed in November 2025, signals the CERs would be suspended in Alberta pending a new carbon pricing agreement.     If a regulatory exemption is reached for the province, this would remove the requirement to comply with the CERs for most of TC Energy’s cogeneration facilities

•Endangerment Finding (U.S.): In July 2025, the USEPA released a proposal to rescind the 2009 Endangerment Finding         (the Finding), which found that GHG emissions pose a threat to public health and welfare. The Finding has been the basis for subsequent GHG regulations. While rescinding the Finding would not automatically invalidate existing GHG regulations for the oil and gas sector, the USEPA has indicated that it plans to separately review related current standards. TC Energy has consistently complied with various regulations stemming from the Finding. We continue to monitor the USEPA’s proposed regulatory changes; however, the impacts of these proposed changes cannot be determined at this time

•Greenhouse Gas Reporting Program (GHGRP) (U.S.): In 2024, the USEPA finalized changes to the GHGRP for how oil and gas sources tally and report their methane emissions (Subpart W). These changes add new reporting sources, modify calculation and reporting methodologies, and drive more granular data collection. Subsequently, in September 2025, USEPA issued a draft rule that announced it found no obligation under the Clean Air Act to collect GHG data and no statutory benefit. In the proposal, USEPA proposes to eliminate reporting obligations for all GHGRP subparts, except Subpart W (non-combustion GHG emissions from the Petroleum & Natural Gas Systems), which would be suspended until the Reporting Year 2034. The potential elimination or significant overhaul of the GHGRP could potentially have indirect implications for state-level reporting frameworks, voluntary industry reporting and compliance strategies and overall transparency of emissions data. Certain states may elect to implement GHG reporting programs in the absence of a federal framework, which could increase administrative burden and complicate cross-jurisdictional reporting for our industry. TC Energy supported industry group comments advocating for retention of the GHGRP. Additionally, in November 2024, USEPA finalized its rule to implement the Inflation Reduction Act’s Waste Emission Charge, which would apply a fee to certain oil and gas facilities that report methane emissions of more than 25,000 metric tons of carbon dioxide equivalent per year to the GHGRP. However, in March 2025, Congress prohibited USEPA from collecting the Waste Emissions Charge until 2034. As a result of the pending changes to the GHGRP, substantial uncertainty exists with respect to future implementation of the Waste Emissions Charge

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•Good Neighbor Rule (U.S.): The USEPA “Good Neighbor Rule” (the Rule) as finalized in March 2023, set new limits for emissions of nitrogen oxides (NOx) from reciprocating internal combustion engines by May 2026. The Rule was stayed in its entirety by the U.S. Supreme Court in June 2024 pending a complete review by the U.S. Circuit Court of Appeals for the D.C. Circuit (the “D.C. Circuit Court”). In March 2025, the USEPA Administrator announced the intention to reconsider numerous pending, proposed and final rules and policies, including “ending” the Rule. The USEPA subsequently stated it plans to reconsider the Rule and conduct a new rulemaking process in 2026. As a result, the D.C. Circuit has placed the litigation challenging the existing Rule in abeyance to allow the USEPA to reconsider and propose the new rule. On January 28, 2026, the USEPA announced the first of a two-step plan to reconsider the Rule, issuing a proposal to reverse prior State Implementation Plan disapprovals in the eight states that were subject to the Rule. If finalized as proposed, the Rule would no longer apply in several states where TC Energy operates assets subject to the Rule. The USEPA indicated that it will take secondary action in the near term to address the states that remain subject to the Rule. We continue to monitor and assess the USEPA’s proposed regulatory changes

•Methane-specific regulations (multi-jurisdictional): In all three countries where TC Energy operates, there are regulations to reduce methane emissions from the oil and gas industry. Though requirements vary by jurisdiction, they generally focus on eliminating fugitive emissions through leak detection and repair programs and reducing vented emissions from equipment. The regulations in each country is discussed below:

◦Canada – The ECCC Regulations Respecting Reduction in the Release of Methane and Certain Volatile Organic Compounds took effect in 2020 and aimed to reduce the oil and gas sector’s methane emission by 40 to 45 per cent below 2012 levels by 2025. Several provinces enacted their own methane regulations that took the place of the federal regulations for provincially regulated assets through equivalency agreements. Our Canadian natural gas pipeline assets are subject to either the federal or British Columbia requirements, while our Alberta natural gas storage assets are subject to the Alberta requirements. In December 2025, ECCC published amendments to strengthen these regulations. This is part of Canada’s newest commitment to reduce the oil and gas sector methane emissions by at least 75 per cent below 2012 levels by 2030. The amendments introduce a risk-based approach for the detection and repair of fugitive emissions, prohibit all venting with specific exceptions, and offer an alternative performance-based approach using continuous monitoring. The amendments take effect on January 1, 2028, with phased requirements through 2030. While our Canadian natural gas pipeline assets have a mature leak detection and repair program and vent management approach to meet current regulations, compliance with these amendments will impose additional costs to our operations. We will continue to refine our internal emissions management strategies and update our compliance plans for our Canadian natural gas pipeline assets to align with the regulatory changes

◦U.S. – In 2023, the USEPA finalized a rule that amended and supplemented the New Source Performance Standards – Subpart OOOO series of volatile organic compound and methane emissions regulations for the oil and natural gas industry. The rule, collectively referred to as the “Methane Rule,” set performance standards for new, modified, or reconstructed sources after December 6, 2022 (OOOOb) and established emission guidelines (EGs) for existing sources prior to December 6, 2022 (OOOOc). Affected U.S. natural gas compressor stations would be required to comply with the Methane Rule, and the costs of compliance are anticipated to be incorporated into new and modified facilities moving forward. The OOOOc standards would apply to a larger number of existing facilities, but impacts will be subject to the requirements of state EG proposals and actual compliance deadlines, which will vary based on state and/or location and have not yet been issued. In July 2025, USEPA issued an interim final rule (IFR) that extends several compliance deadlines under both OOOOb and OOOOc. The IFR also indicates that the USEPA may introduce further substantive changes to the Methane Rule through a separate reconsideration process. These extensions give operators and states more practical timelines for associated implementation and planning but also provide USEPA with time to proceed with announced plans for reconsideration of the Methane Rule. Certain states, such as New York, Pennsylvania, Maryland and California, have independently enacted their own methane emissions regulations. TC Energy is closely monitoring these developments as applicable to our business

◦Mexico – In 2018, the Agencia de Seguridad, Energía y Ambiente (ASEA) released the Guidelines for the Prevention and Control of Methane Emissions from the Hydrocarbon Sector to reduce the sector’s methane emissions by 40 to 45 per cent by 2025. Per the guidelines’ requirements, TC Energy developed and has implemented a Program for the Comprehensive Prevention and Control of Methane Emissions (PPCIEM) for our Mexican facilities since 2020

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•Onshore Natural Gas Pipelines Standard (Mexico): In September 2025, ASEA replaced NOM-007-ASEA-2016 with     NOM-020-ASEA-2024 to regulate the design, construction, operation and maintenance of onshore natural gas transmission pipelines. The standard, which will take effect February 28, 2026, adds incremental requirements with respect to operations, maintenance, inspections, documentation and audits to renew and maintain permits. We are currently updating our pipeline design and construction processes accordingly. We do not anticipate this standard to have a material impact on our business in Mexico

•Sustainability-related disclosure requirements (multi-jurisdictional): Various sustainability disclosure requirements (including climate-related topics) are being issued in jurisdictions in which we operate. We continue to monitor these developments and progress our sustainability-related disclosures to reflect new and anticipated requirements. Our enterprise-wide sustainability-related disclosures, including a dedicated Climate-related disclosures section, can be found in our annual Report on Sustainability

◦U.S. – California's senate bill (SB) -253 and SB-261 require certain U.S. companies doing business in California to disclose their GHG emissions and climate-related financial risks, respectively. Entities within the scope of SB-261 must prepare a climate-related financial risk report by January 1, 2026; however, enforcement of SB-261 has been halted while litigation is ongoing in federal court. Applicability to TC Energy is under evaluation

◦Mexico – the Normas de Información de Sostenibilidad (NIS) requires the disclosure of 30 sustainability indicators across environmental, social and governance topics for fiscal years beginning on or after January 1, 2025. These requirements will apply to certain TC Energy Mexican entities as part of compliance with financial standards.

Anticipated policies

•Carbon Pricing (Canada): In December 2025, ECCC released a discussion paper on potential updates to strengthen the federal carbon pricing benchmark on industrial emissions, which sets the minimum requirements for provincial systems. In general, these systems require regulated facilities to reduce their emissions below an intensity baseline which leads to credit generation or compliance obligations. The proposed updates include changes to coverage and scope, certain compliance pathways and public reporting requirements. They are intended to ensure industrial carbon pricing systems are more consistent, efficient and effective across the country. TC Energy currently operates under several carbon pricing systems subject to the federal backstop. We will monitor these developments, evaluate potential impacts and engage with ECCC, as appropriate

•New Energy Policy Considerations (Mexico): In late 2025, Mexico published the New Energy Policy Considerations as part of its broader energy policy framework, which includes the Energy Sector Program 2025-2030 (PROSENER) and other official documents. The energy policy framework influences the country’s implementation of climate policies, long-term view of natural gas, and integration of social objectives. It also signals the development of additional regulations. PROSENER specifically proposes additional emission reductions (including methane) through greater energy efficiency, technological innovation, and the construction and modernization of new energy infrastructure. We will continue monitoring these policy developments and provide feedback to the respective government departments, as appropriate

•Oil and Gas Emissions Cap (Canada): In 2024, ECCC published the draft Oil and Gas Sector Greenhouse Gas Emissions Cap Regulations. The draft regulations introduce a cap-and-trade system as of 2030 to reduce GHG emissions from the oil and gas sector, covering upstream activities and LNG production. Although transmission pipelines are excluded from the draft regulations, there is a possibility of cascading effects and unintended consequences to our Canadian natural gas pipelines business. The draft regulations were set to be finalized in 2025, but under the Canada-Alberta MOU signed in November 2025, the Government of Canada has committed to not implementing them

•TIER Updates (Alberta, Canada): In December 2025, the Government of Alberta issued an Order in Council introducing an additional compliance pathway that will recognize certain on-site emissions reduction investments for up to 90 per cent of compliance obligations and allowing facilities that are below the regulatory emissions threshold and currently participate in the TIER emission program to opt-out of paying into the TIER fund or retire TIER compliance instruments. The Canada-Alberta MOU signed in November 2025 signals additional changes may be proposed to TIER's carbon price, price escalation, and performance benchmarks. Since these changes are likely to impact the carbon credit market, their effects may have different impacts on our Alberta-based Canadian natural gas pipelines and Power and Energy Solutions assets. We will continue to monitor and evaluate the operational and financial impacts as details of the new carbon pricing agreement with the Government of Canada are made available.

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Financial risks

We are exposed to various financial risks and have strategies, policies and limits in place to manage the impact of these risks on our earnings, cash flows and, ultimately, shareholder value.

Risk management strategies, policies and limits are designed to ensure our risks and related exposures are in line with our business objectives and risk tolerance. Our risks are managed within limits that are established by our Board of Directors, implemented by senior management and monitored by our risk management, internal audit and business segment groups. Our Board of Directors' 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

We construct and invest in energy infrastructure projects, purchase and sell commodities, issue short- and long-term debt, including amounts in foreign currencies and invest in foreign operations. Certain of these activities expose us to market risk from changes in commodity prices, foreign exchange rates and interest rates, which may affect our earnings, cash flows and the value of our financial assets and liabilities. We assess contracts used to manage market risk to determine whether all, or a portion, meet the definition of a derivative.

Derivative contracts used 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 our exposure to market risk resulting from commodity price risk management activities in our non-regulated businesses:

•in our natural gas marketing business, we enter into natural gas transportation and storage contracts, as well as natural gas purchase and sale agreements. We manage our exposure on these contracts using financial instruments and hedging activities to offset market price volatility

•in our power business, we manage 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 our non-regulated natural gas storage business, our 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 or 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 our asset base and/or re-contract with our shippers and customers as contractual agreements expire.

Interest rate risk

We utilize both short- and long-term debt to finance our operations which exposes us to interest rate risk. We typically pay fixed rates of interest on our long-term debt and floating rates on short-term debt including our commercial paper programs and amounts drawn on our credit facilities. A small portion of our long-term debt bears interest at floating rates. In addition, we are exposed to interest rate risk on financial instruments and contractual obligations containing variable interest rate components. We actively manage our interest rate risk using interest rate derivatives.

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Foreign exchange risk

Certain of our businesses generate all or most of their earnings in U.S. dollars and since we report our financial results in Canadian dollars, changes in the value of the U.S. dollar against the Canadian dollar directly affect our comparable EBITDA and may also impact comparable earnings.

A portion of our Mexico Natural Gas Pipelines' monetary assets and liabilities are peso-denominated, while our Mexico operations' financial results are denominated in U.S. dollars. Therefore, changes in the value of the Mexican peso against the U.S. dollar can affect our comparable earnings. 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) in the Consolidated statement of income.

We actively manage a portion of our foreign exchange risk using foreign exchange derivatives. Refer to the Foreign exchange section for additional information.

We hedge a portion of our net investment in foreign operations (on an after-tax basis) with U.S. dollar-denominated debt and cross-currency interest rate swaps as appropriate.

Counterparty credit risk

We have exposure to counterparty credit risk in a number of areas including:

•cash and cash equivalents

•accounts receivable

•available-for-sale assets

•fair value of derivative assets

•net investment in leases and certain contract assets in Mexico.

At times, our 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 our 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 of our operations

•the competitive position of our assets and the demand for our services

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

We review 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. We use historical credit loss and recovery data, adjusted for our judgment regarding current economic and credit conditions, along with reasonable and supportable forecasts to determine if any impairment should be recognized in Plant operating costs and other. At December 31, 2025 and 2024, we had no significant credit risk concentrations, with the exception of the CFE, which represents approximately 33 per cent of gross exposure. Gross exposure is measured as the unmitigated full-term contract revenue exposure discounted in accordance with each contract’s discount rate, as applicable. At this time, there were no significant amounts past due or impaired. We recorded a pre-tax expense of $83 million for the year ended December 31, 2025 on the expected credit loss provision before tax recognized on TGNH net investment in leases and certain contract assets in Mexico (2024 – $22 million recovery). During 2025, we completed the Southeast Gateway pipeline and recognized a net investment in sales-type lease. Other than the expected credit loss provision noted above, we had no significant credit losses at December 31, 2025 and 2024. Refer to Note 27, Risk management and financial instruments, of our 2025 Consolidated financial statements for additional information.

We have significant credit and performance exposure to financial institutions that hold cash deposits and provide committed credit lines and letters of credit that help manage our exposure to counterparties and provide liquidity in commodity, foreign exchange and interest rate derivative markets. Our portfolio of financial sector exposure consists primarily of highly-rated investment grade, systemically important financial institutions.

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Liquidity risk

Liquidity risk is the risk that we will not be able to meet our financial obligations as they come due. We manage our liquidity risk by continuously forecasting our cash flows and ensuring we have adequate cash balances, cash flows from operations, committed and demand credit facilities and access to capital markets to meet our operating, financing and capital expenditure obligations under both normal and stressed economic conditions. Refer to the Financial Condition section for additional information.

Legal proceedings

TC Energy and its subsidiaries are subject to various legal proceedings, arbitrations and actions arising in the normal course of business. We assess all legal matters on an ongoing basis, including those of our equity investments to determine if they meet the requirements for disclosure or accrual of a contingent loss. Refer to Note 30, Commitments, contingencies and guarantees, of our 2025 Consolidated financial statements for additional information.

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CONTROLS AND PROCEDURES

We meet Canadian and U.S. regulatory requirements for disclosure controls and procedures, internal control over financial reporting and related CEO and CFO certifications.

Disclosure controls and procedures

Under the supervision and with the participation of management, including our President and CEO and our CFO, we carried     out quarterly evaluations of the effectiveness of our disclosure controls and procedures, including for the year ended         December 31, 2025, as required by the Canadian securities regulatory authorities and by the SEC. Based on this evaluation, our President and CEO and our CFO have concluded that the disclosure controls and procedures are effective in that they are designed to ensure that the information we are required to disclose in reports we file with or send to securities regulatory authorities is recorded, processed, summarized and reported accurately within the time periods specified under Canadian and U.S. securities laws.

Management’s report on internal control over financial reporting

We are responsible for establishing and maintaining adequate internal control over financial reporting, which is a process designed by, or under the supervision of, our President and CEO and our CFO and effected by our Board of Directors, management and other personnel, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with GAAP.

Under the supervision and with the participation of management, including our President and CEO and our CFO, an evaluation of the effectiveness of the internal control over financial reporting was conducted as of December 31, 2025, based on the criteria described in “Internal Control – Integrated Framework” issued in 2013 by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this assessment, management determined that, as of December 31, 2025, the internal control over financial reporting was effective.

Our internal control over financial reporting as of December 31, 2025 has been audited by KPMG LLP, an independent registered public accounting firm, as stated in their attestation report which is included in our 2025 Consolidated financial statements.

CEO and CFO certifications

Our President and CEO and our CFO have attested to the quality of the public disclosure in our fiscal 2025 reports filed with Canadian securities regulators and the SEC and have filed certifications with them.

Changes in internal control over financial reporting

There were no changes during the year covered by this annual report that had or are reasonably likely to have a material impact on our internal control over financial reporting.

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CRITICAL ACCOUNTING ESTIMATES

In preparing our Consolidated financial statements, we are 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. We use the most current information available and exercise careful judgment in making these estimates and assumptions.

Certain estimates and judgments have a material impact where the assumptions underlying these accounting estimates relate to matters that are highly uncertain at the time the estimate or judgment is made or are subjective. Refer to Note 2, Accounting policies, of our 2025 Consolidated financial statements for additional information.

Sales-type leases

We determined that the Southeast Gateway pipeline is classified as a sales-type lease between TGNH and the CFE. Under a     sales-type lease, we derecognize the underlying asset and record 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.

To record the net investment in lease, we were required to prepare an estimate of the fair value of the Southeast Gateway pipeline on the lease commencement date. 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, we 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. We 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.

Impairment of goodwill

We test goodwill for impairment annually or more frequently if events or changes in circumstances lead us to believe it might be impaired. We can initially assess qualitative factors which include, but are not limited to, macroeconomic conditions, industry and market considerations, cost factors, historical and forecasted financial results, or events specific to that reporting unit. If we conclude that it is not more likely than not that the fair value of the reporting unit is greater than its carrying value, we will then perform a quantitative goodwill impairment test. We can elect to proceed directly to the quantitative goodwill impairment test for any reporting unit. If the quantitative goodwill impairment test is performed, we compare 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.

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.

We determine the fair value of a reporting unit based on our projections of future cash flows, which involves making estimates and assumptions about transportation rates, market supply and demand, growth opportunities, output levels, competition from other companies, operating costs, regulatory changes, discount rates and earnings and other multiples.

The estimated fair value in excess of the carrying value was less than 10 per cent on our Great Lakes reporting unit at the date of our last quantitative goodwill impairment test. Any future reductions in cash flow forecasts or adverse changes in other key assumptions could result in a future impairment of our goodwill balance.

Qualitative goodwill impairment indicators

As part of the annual goodwill impairment assessment at December 31, 2025, we evaluated qualitative factors impacting the     fair value of the underlying reporting units for all reporting units other than the Columbia reporting unit, which is described below. It was determined that it was more likely than not that the fair value of these reporting units exceeded their carrying amounts, including goodwill.

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Columbia

We 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 following the Columbia Gas Settlement. To determine fair value, we used a discounted cash flow model incorporating projections of our 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.

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FINANCIAL INSTRUMENTS

With the exception of Long-term debt and Junior subordinated notes, our derivative and non-derivative financial instruments are recorded on the balance sheet at fair value unless they were entered into and continue to be held for the purpose of receipt or delivery in accordance with our normal purchase and sales exemptions and are documented as such. In addition, fair value accounting is not required for other financial instruments that qualify for certain accounting exemptions.

Derivative instruments

We use derivative instruments to reduce volatility associated with fluctuations in commodity prices, interest rates and foreign exchange rates. Derivative instruments, including those that qualify and are designated for hedge accounting treatment, are recorded at fair value. 

The majority of derivative instruments that are not designated or do not qualify for hedge accounting treatment have been entered into as economic hedges to manage our exposure to market risk and are classified as held-for-trading. Changes in the fair value of held-for-trading derivative instruments are recorded in net income in the period of change. This may expose us to increased variability in reported operating results since the fair value of the held-for-trading 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 us. 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 presentation of the fair value of derivative instruments is as follows:

at December 31
(millions of $)						2025						2024
Other current assets						438						347
Other long-term assets						161						122
Accounts payable and other						(380)						(507)
Other long-term liabilities						(149)						(209)
						70						(247)

Anticipated timing of settlement of derivative instruments

The anticipated timing of settlement of derivative instruments assumes constant commodity prices, interest rates and foreign exchange rates. Settlements will vary based on the actual value of these factors at the date of settlement.

at December 31, 2025						Total fair value						< 1 year						1 - 3 years						4 - 5 years						> 5 years
(millions of $)
Derivative instruments held for trading						116						41						64						31						(20)
Derivative instruments in hedging relationships						(46)						16						30						(76)						(16)
						70						57						94						(45)						(36)

112 | TC Energy Management's discussion and analysis 2025

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Unrealized and realized gains (losses) on derivative instruments

The following summary does not include hedges of our net investment in foreign operations.

year ended December 31
(millions of $)						2025						2024						2023
Derivative Instruments Held for Trading1
Unrealized gains (losses) in the year
Commodities						25						(71)						132
Foreign exchange						210						(266)						246
Interest rate						—						(71)						—
Realized gains (losses) in the year
Commodities						(10)						199						192
Foreign exchange						142						(152)						155
Interest rate						8						29						—
Derivative Instruments in Hedging Relationships2
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).

For further details on our non-derivative and derivative financial instruments, including classification assumptions made in the calculation of fair value and additional discussion of exposure to risks and mitigation activities, refer to Note 27, Risk management and financial instruments, of our 2025 Consolidated financial statements.

TC Energy Management's discussion and analysis 2025 | 113

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RELATED PARTY TRANSACTIONS

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 LP

We hold a 35 per cent equity interest in Coastal GasLink LP and operate the Coastal GasLink pipeline.

We have a subordinated loan agreement with Coastal GasLink LP under which we advance non-revolving interest-bearing     loans subject to floating market-based rates. In December 2024, following the commercial in-service of the pipeline,         Coastal GasLink LP repaid the $3,147 million balance outstanding to TC Energy under the subordinated loan agreement. Unused committed capacity available for use by Coastal GasLink LP at December 31, 2025 was $163 million (December 31, 2024 –     $228 million).

We also have a subordinated demand revolving credit facility agreement with Coastal GasLink LP to provide additional short-term liquidity and funding flexibility to projects under construction.

Sur de Texas

We hold a 60 per cent equity interest in a joint venture with 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).

ACCOUNTING CHANGES

For a description of our significant accounting policies and a summary of changes in accounting policies and standards impacting our business, refer to Note 2, Accounting policies, and Note 3, Accounting changes, of our 2025 Consolidated financial statements.

114 | TC Energy Management's discussion and analysis 2025

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QUARTERLY RESULTS

Selected quarterly consolidated financial data

2025
(millions of $, except per share amounts)						Fourth						Third						Second						First
Revenues from continuing operations						4,168						3,704						3,744						3,623
Net income (loss) attributable to common shares						980						609						833						978
from continuing operations						959						813						862						978
from discontinued operations						21						(204)						(29)						—
Comparable earnings1						1,018						805						848						983
from continuing operations						1,018						805						848						983
from discontinued operations						—						—						—						—
Share statistics:
Net income (loss) per common share – basic						$0.94						$0.58						$0.80						$0.94
from continuing operations						$0.92						$0.78						$0.83						$0.94
from discontinued operations						$0.02						($0.20)						($0.03)						—
Comparable earnings per common share1						$0.98						$0.77						$0.82						$0.95
from continuing operations						$0.98						$0.77						$0.82						$0.95
from discontinued operations						—						—						—						—
Dividends declared per common share						$0.85						$0.85						$0.85						$0.85

1Additional information on the most directly comparable GAAP measure can be found on page 22.

2024
(millions of $, except per share amounts)						Fourth						Third						Second						First
Revenues from continuing operations						3,577						3,358						3,327						3,509
Net income (loss) attributable to common shares						971						1,457						963						1,203
from continuing operations						1,069						1,338						804						988
from discontinued operations1						(98)						119						159						215
Comparable earnings2						1,094						1,074						978						1,284
from continuing operations						1,094						894						822						1,055
from discontinued operations1						—						180						156						229
Share statistics:
Net income (loss) per common share – basic						$0.94						$1.40						$0.93						$1.16
from continuing operations						$1.03						$1.29						$0.78						$0.95
from discontinued operations1						($0.09)						$0.11						$0.15						$0.21
Comparable earnings per common share2						$1.05						$1.03						$0.94						$1.24
from continuing operations						$1.05						$0.86						$0.79						$1.02
from discontinued operations1						—						$0.17						$0.15						$0.22
Dividends declared per common share3						$0.8225						$0.96						$0.96						$0.96

1Represents nine months of Liquids Pipelines earnings in 2024.

2Additional information on the most directly comparable GAAP measure can be found on page 22.

3Dividends declared in fourth quarter 2024 and thereafter reflect TC Energy’s proportionate allocation following the Spinoff Transaction. Refer to the Discontinued operations section for additional information.

TC Energy Management's discussion and analysis 2025 | 115

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Factors affecting quarterly financial information by business segment

Quarter-over-quarter revenues and net income fluctuate for reasons that vary across our business segments. In addition to the factors below, our revenues and segmented earnings (losses) are impacted by fluctuations in foreign exchange rates, mainly related to our U.S. dollar-denominated operations and our peso-denominated exposure.

As discussed on page 10 of the About this document section, results of the Liquids Pipelines business were accounted for as a discontinued operation starting October 1, 2024. To allow for a meaningful comparison, discussions throughout the Quarterly results section are based on continuing operations unless otherwise noted. Refer to the Discontinued operations section for additional information.

In our Natural Gas Pipelines business, except for seasonal fluctuations in short-term throughput volumes on U.S. pipelines, quarter-over-quarter revenues and segmented earnings (losses) generally remain relatively stable during any fiscal year. Over the long term, however, they fluctuate because of:

•regulatory decisions

•negotiated settlements with customers

•newly constructed assets being placed in service

•acquisitions and divestitures

•natural gas marketing activities and commodity prices

•developments outside of the normal course of operations

•certain fair value adjustments

•provisions for expected credit losses on net investment in leases and certain contract assets in Mexico.

In Power and Energy Solutions, quarter-over-quarter revenues and segmented earnings are affected by:

•weather

•customer demand

•newly constructed assets being placed in service

•acquisitions and divestitures

•market prices for natural gas and power

•capacity prices and payments

•power marketing and trading activities

•planned and unplanned plant outages

•developments outside of the normal course of operations

•certain fair value adjustments.

Factors affecting financial information by quarter

We calculate comparable measures by adjusting certain GAAP measures for specific items we believe are significant but not reflective of our underlying operations in the period. Except as otherwise described herein, these comparable measures are calculated on a consistent basis from period to period and are adjusted for specific items in each period, as applicable. Refer to page 22 for more information on non-GAAP measures we use.

In fourth quarter 2025, comparable earnings from continuing operations also excluded:

•a pre-tax impairment charge of $110 million for certain Power and Energy Solutions projects following our decision to discontinue development along with updated forecast assumptions as we refocus our Power and Energy Solutions strategy

•pre-tax unrealized foreign exchange losses, net, of $47 million on the peso-denominated intercompany loan between TCPL and TGNH, net of non-controlling interest

•a pre-tax recovery of $4 million on the expected credit loss provision related to TGNH net investment in leases, net of non-controlling interest as well as certain contract assets in Mexico.

116 | TC Energy Management's discussion and analysis 2025

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In third quarter 2025, comparable earnings from continuing operations also excluded:

•pre-tax unrealized foreign exchange gains, net, of $87 million on the peso-denominated intercompany loan between TCPL and TGNH, net of non-controlling interest

•a pre-tax recovery of $12 million on the expected credit loss provision related to TGNH net investment in leases, net of non-controlling interest as well as certain contract assets in Mexico.

In second quarter 2025, comparable earnings from continuing operations also excluded:

•pre-tax unrealized foreign exchange losses, net, of $132 million on the peso-denominated intercompany loan between TCPL and TGNH, net of non-controlling interest

•a pre-tax expense of $93 million on the expected credit loss provision related to TGNH net investment in leases, net of non-controlling interest as well as certain contract assets in Mexico.

In first quarter 2025, comparable earnings from continuing operations also excluded:

•pre-tax unrealized foreign exchange gains, net, of $3 million on the peso-denominated intercompany loan between TCPL and TGNH, net of non-controlling interest

•a pre-tax recovery of $2 million on the expected credit loss provision related to TGNH net investment in leases, net of non-controlling interest as well as certain contract assets in Mexico.

In fourth quarter 2024, comparable earnings from continuing operations also excluded:

•a pre-tax net gain on debt extinguishment of $228 million related to the purchase and cancellation of certain senior unsecured notes and medium term notes and the retirement of outstanding callable notes in October 2024

•pre-tax unrealized foreign exchange gains, net, of $143 million on the peso-denominated intercompany loan between TCPL and TGNH, net of non-controlling interest

•a pre-tax recovery of $3 million on the expected credit loss provision related to TGNH net investment in leases, net of non-controlling interest as well as certain contract assets in Mexico

•a deferred income tax expense of $96 million resulting from the revaluation of remaining deferred tax balances following the Spinoff Transaction

•a pre-tax impairment charge of $36 million for a Power and Energy Solutions project following our decision to discontinue development as we refocus our Power and Energy Solutions strategy

•a pre-tax expense of $9 million related to Focus Project costs.

In third quarter 2024, comparable earnings from continuing operations also excluded:

•a pre-tax gain of $572 million related to the sale of PNGTS which was completed on August 2024

•pre-tax unrealized foreign exchange losses, net, of $52 million on the peso-denominated intercompany loan between TCPL and TGNH, net of non-controlling interest

•a pre-tax expense of $5 million on the expected credit loss provision related to TGNH net investment in leases, net of non-controlling interest as well as certain contract assets in Mexico

•a pre-tax expense of $5 million related to Focus Project costs.

In second quarter 2024, comparable earnings from continuing operations also excluded:

•a pre-tax gain of $48 million related to the sale of non-core assets in U.S. Natural Gas Pipelines and Canadian Natural Gas Pipelines

•pre-tax unrealized foreign exchange losses, net of $3 million on the peso-denominated intercompany loan between TCPL and TGNH, net of non-controlling interest

•a pre-tax recovery of $3 million on the expected credit loss provision related to TGNH net investment in leases, net of non-controlling interest as well as certain contract assets in Mexico

•pre-tax costs of $10 million related to the NGTL System ownership transfer.

In first quarter 2024, comparable earnings from continuing operations also excluded:

•pre-tax unrealized foreign exchange gains, net of $55 million on the peso-denominated intercompany loan between TCPL and TGNH

•a pre-tax recovery of $21 million on the expected credit loss provision related to TGNH net investment in leases and certain contract assets in Mexico

•a pre-tax expense of $34 million related to a non-recurring third-party settlement

•a pre-tax expense of $10 million related to Focus Project costs.

TC Energy Management's discussion and analysis 2025 | 117

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FOURTH QUARTER 2025 HIGHLIGHTS

Consolidated results

three months ended December 31						2025						2024
(millions of $, except per share amounts)
Canadian Natural Gas Pipelines						564						506
U.S. Natural Gas Pipelines						1,110						918
Mexico Natural Gas Pipelines						377						214
Power and Energy Solutions						136						276
Corporate						1						(16)
Total segmented earnings (losses)						2,188						1,898
Interest expense						(873)						(679)
Allowance for funds used during construction						36						233
Foreign exchange gains (losses), net						15						(69)
Interest income and other						58						120
Income (loss) from continuing operations before income taxes						1,424						1,503
Income tax (expense) recovery from continuing operations						(263)						(223)
Net income (loss) from continuing operations						1,161						1,280
Net income (loss) from discontinued operations, net of tax						21						(98)
Net income (loss)						1,182						1,182
Net (income) loss attributable to non-controlling interests						(167)						(183)
Net income (loss) attributable to controlling interests						1,015						999
Preferred share dividends						(35)						(28)
Net income (loss) attributable to common shares						980						971
Net income (loss) per common share – basic						$0.94						$0.94
from continuing operations						$0.92						$1.03
from discontinued operations						$0.02						($0.09)

three months ended December 31						2025						2024
(millions of $)
Amounts attributable to common shares
Net income (loss) from continuing operations						1,161						1,280
Net income (loss) attributable to non-controlling interest						(167)						(183)
Net income (loss) attributable to controlling interests from continuing operations						994						1,097
Preferred share dividends						(35)						(28)
Net income (loss) attributable to common shares from continuing operations						959						1,069
Net income (loss) from discontinued operations, net of tax						21						(98)
Net income (loss) attributable to common shares						980						971

Net income (loss) attributable to common shares from continuing operations decreased by $110 million or $0.11 per common share for the three months ended December 31, 2025 compared to the same period in 2024.

118 | TC Energy Management's discussion and analysis 2025

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Reconciliation of net income (loss) attributable to common shares to comparable earnings - from continuing operations

three months ended December 31						2025						2024
(millions of $, except per share amounts)
Net income (loss) attributable to common shares from continuing operations						959						1,069
Specific items (pre tax):
Power and Energy Solutions impairment charges						110						36
Foreign exchange (gains) losses, net – intercompany loan1						47						(143)
Expected credit loss provision on net investment in leases and certain contract assets in Mexico2						(4)						(3)
Net gain on debt extinguishment3						—						(228)
Focus Project costs4						—						9
Bruce Power unrealized fair value adjustments						(4)						(2)
Risk management activities5						(87)						301
Taxes on specific items6						(3)						55
Comparable earnings from continuing operations						1,018						1,094
Net income (loss) per common share from continuing operations						$0.92						$1.03
Specific items (net of tax)						0.06						0.02
Comparable earnings per common share from continuing operations						$0.98						$1.05

1In 2023, TCPL and TGNH entered into an unsecured revolving credit facility. While the loan receivable and payable eliminate on consolidation, differences in each entity’s reporting currency create a net income impact from revaluing and translating these balances into TC Energy’s reporting currency. As the resulting unrealized foreign exchange gains and losses do not reflect amounts expected to be realized at settlement, we exclude them from comparable measures, net of non‑controlling interest.

2We have recognized an expected credit loss provision related to net investment in leases and certain contract assets in Mexico, which will fluctuate from period to period based on changing economic assumptions and forward-looking information. This provision is an estimate of losses that may occur over the duration of the TSA through 2055. This provision does not reflect losses or cash outflows that were incurred under this lease arrangement in the current period or from our underlying operations, and therefore, we have excluded any unrealized changes, net of non-controlling interest, from comparable measures. Refer to Note 27, Risk management and financial instruments, of our 2025 Consolidated financial statements for additional information.

3In October 2024, TCPL commenced and completed our 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, we retired outstanding callable notes at par. These extinguishments of debt resulted in a pre-tax
net gain of $228 million, primarily due to fair value discounts and unamortized debt issue costs. The net gain on debt extinguishment was recorded in Interest expense in the Consolidated statement of income. Refer to Note 19, Long-term debt, of our 2025 Consolidated financial statements for additional information.

4In 2024 we recognized expenses related to the Focus Project for external consulting and severance, some of which are not recoverable through regulatory and commercial tolling structures.

5						three months ended December 31						2025						2024
						(millions of $)
						U.S. Natural Gas Pipelines						(8)						(37)
						Canadian Power						56						17
						U.S. Power						5						(2)
						Natural Gas Storage						(8)						(20)
						Interest rate						1						(71)
						Foreign exchange						41						(188)
												87						(301)
						Income tax attributable to risk management activities						(21)						72
						Total unrealized gains (losses) from risk management activities						66						(229)
6						Refer to the Corporate - Financial results section for additional information.

TC Energy Management's discussion and analysis 2025 | 119

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Comparable EBITDA to comparable earnings - from continuing operations

Comparable EBITDA from continuing operations represents segmented earnings (losses) adjusted for the specific items described above and excludes charges for depreciation and amortization.

three months ended December 31						2025						2024
(millions of $, except per share amounts)
Comparable EBITDA from continuing operations
Canadian Natural Gas Pipelines						961						851
U.S. Natural Gas Pipelines						1,388						1,200
Mexico Natural Gas Pipelines						397						234
Power and Energy Solutions						217						341
Corporate						1						(7)
Comparable EBITDA from continuing operations						2,964						2,619
Depreciation and amortization						(719)						(639)
Interest expense included in comparable earnings						(874)						(836)
Allowance for funds used during construction						36						233
Foreign exchange gains (losses), net included in comparable earnings						29						(44)
Interest income and other						58						120
Income tax (expense) recovery included in comparable earnings						(266)						(168)
Net (income) loss attributable to non-controlling interests included in comparable earnings						(175)						(163)
Preferred share dividends						(35)						(28)
Comparable earnings from continuing operations						1,018						1,094
Comparable earnings per common share from continuing operations						$0.98						$1.05

120 | TC Energy Management's discussion and analysis 2025

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Comparable EBITDA from continuing operations

Fourth quarter 2025 versus fourth quarter 2024

Comparable EBITDA from continuing operations increased by $345 million for the three months ended December 31, 2025 compared to the same period in 2024 primarily due to the net result of the following:

•increased U.S. dollar-denominated EBITDA from U.S. Natural Gas Pipelines due to an increase in earnings from Columbia Gas as a result of higher transportation rates effective April 1, 2025, incremental earnings from projects placed in service, additional contract sales and higher realized earnings related to our U.S. natural gas marketing business

•increased U.S. dollar-denominated EBITDA from Mexico Natural Gas Pipelines mainly due to higher earnings in TGNH primarily related to the completion of the Southeast Gateway pipeline in second quarter 2025, partially offset by lower equity earnings from Sur de Texas as a result of peso-denominated financial exposure and higher income tax expense mainly related to foreign exchange impacts of U.S dollar-denominated liabilities

•increased EBITDA in Canadian Natural Gas Pipelines mainly due to higher flow-through depreciation and incentive earnings on the NGTL System and Mainline

•decreased Power and Energy Solutions EBITDA mainly attributable to lower net contributions from Bruce Power due to reduced generation primarily resulting from the Unit 4 MCR, partially offset by a higher contract price; and lower realized power prices in Canadian Power, partially offset by lower business development costs

•a negative foreign exchange impact of a weaker U.S. dollar on the Canadian dollar equivalent comparable EBITDA in our U.S. dollar-denominated operations, which was translated at a rate of 1.39 in 2025 versus 1.40 in 2024. Refer to the Foreign exchange section for additional information.

Due to the flow-through treatment of certain costs including depreciation, financial charges and income taxes in our Canadian rate-regulated pipelines, changes in these costs impact our comparable EBITDA despite having no significant effect on net income.

Comparable earnings from continuing operations

Fourth quarter 2025 versus fourth quarter 2024

Comparable earnings decreased by $76 million or $0.07 per common share for the three months ended December 31, 2025 compared to the same period in 2024 primarily due to the net effect of the following:

•changes in comparable EBITDA described above

•lower AFUDC primarily due to the completion of the Southeast Gateway pipeline

•higher income tax expense primarily due to the impact of Mexico foreign exchange exposure and higher flow-through income taxes

•higher depreciation and amortization primarily due to higher depreciation rates on the NGTL System under the 2025-2029 NGTL Settlement and from Columbia Gas as a result of the Columbia Gas Settlement

•lower interest income and other due to an increase in insurance-related provisions and lower interest earned on short-term investments

•higher interest expense due to lower realized gains on derivatives used to manage our interest rate risk, increased levels of short-term borrowing and long-term debt issuances and maturities

•higher net income attributable to non-controlling interests is primarily the result of higher net income recognized from the Columbia Gas and Columbia Gulf assets, partially offset by the net effect of higher tax expense, higher EBITDA and lower AFUDC in TGNH following Southeast Gateway pipeline's completion in second quarter 2025 and the overall impact of foreign exchange

•risk management activities used to manage our foreign exchange exposure to net liabilities in Mexico and to             U.S. dollar-denominated income and the revaluation of our peso-denominated net monetary liabilities to U.S. dollars.

TC Energy Management's discussion and analysis 2025 | 121

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Foreign exchange

Certain of our businesses generate all or most of their earnings in U.S. dollars and, since we report our financial results in Canadian dollars, changes in the value of the U.S. dollar against the Canadian dollar directly affect our comparable EBITDA and may also impact comparable earnings. As our U.S. dollar-denominated operations continue to grow, this exposure increases. A portion of the U.S. dollar-denominated comparable EBITDA exposure is naturally offset by U.S. dollar-denominated amounts below comparable EBITDA within Depreciation and amortization, Interest expense and other income statement line items. A portion of the remaining exposure is actively managed on a rolling forward basis up to three years using foreign exchange derivatives; however, the natural exposure beyond that period remains. The net impact of the U.S. dollar movements on comparable earnings during the three months ended December 31, 2025 after considering natural offsets and economic hedges was not significant.

The components of our financial results denominated in U.S. dollars are set out in the table below, including our U.S. Natural Gas Pipelines and Mexico Natural Gas Pipelines operations. Comparable EBITDA is a non-GAAP measure.

Pre-tax U.S. dollar-denominated income and expense items - from continuing operations

three months ended December 31						2025						2024
(millions of US$)
Comparable EBITDA
U.S. Natural Gas Pipelines						996						859
Mexico Natural Gas Pipelines						285						167
						1,281						1,026
Depreciation and amortization						(211)						(191)
Interest expense on long-term debt and junior subordinated notes						(434)						(440)
Interest income and other						22						51
Allowance for funds used during construction						16						159
Net (income) loss attributable to non-controlling interests included in comparable earnings and other						(127)						(125)
						547						480
Average exchange rate - U.S. to Canadian dollars						1.39						1.40

Foreign exchange related to Mexico Natural Gas Pipelines

Changes in the value of the Mexican peso against the U.S. dollar can affect our comparable earnings as a portion of our Mexico Natural Gas Pipelines monetary assets and liabilities are peso-denominated, while our financial results are denominated in U.S. dollars for our Mexico operations. These peso-denominated balances are revalued to U.S. dollars, creating foreign exchange gains and losses that are included in Income (loss) from equity investments, Foreign exchange (gains) losses, net and Net income (loss) attributable to non-controlling interests in the Consolidated statement of 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 from equity investments and Income tax expense. This exposure increases as our U.S. dollar‑denominated net monetary liabilities grow.

The above exposures are managed using foreign exchange derivatives, although some unhedged exposure remains. The impacts of the foreign exchange derivatives are recorded in Foreign exchange (gains) losses, net in the Consolidated statement of income. Refer to the Financial risks and financial instruments section for additional information.

122 | TC Energy Management's discussion and analysis 2025

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The period end exchange rates for one U.S. dollar to Mexican pesos were as follows:

December 31, 2025						18.00
December 31, 2024						20.87
December 31, 2023						16.91

A summary of the impacts of transactional foreign exchange gains and losses from changes in the value of the Mexican peso against the U.S. dollar and associated derivatives is set out in the table below:

three months ended December 31
(millions of $)						2025						2024
Comparable EBITDA - Mexico Natural Gas Pipelines1						(12)						30
Foreign exchange gains (losses), net included in comparable earnings						36						(21)
Income tax (expense) recovery included in comparable earnings						(13)						27
Net (income) loss attributable to non-controlling interests included in comparable earnings2						—						(3)
						11						33

1Includes the foreign exchange impacts from the Sur de Texas joint venture recorded in Income (loss) from equity investments in the Consolidated statement
of income.

2Represents the non-controlling interest portion related to TGNH. Refer to the Corporate section for additional information.

TC Energy Management's discussion and analysis 2025 | 123

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Highlights by business segment

Canadian Natural Gas Pipelines

Canadian Natural Gas Pipelines segmented earnings increased by $58 million for the three months ended December 31, 2025 compared to the same period in 2024.

Net income for the NGTL System increased by $17 million for the three months ended December 31, 2025 compared to the same period in 2024 primarily due to higher incentive earnings. The NGTL System is currently operating under the 2025-2029 NGTL Settlement, which commenced on January 1, 2025 and includes an approved ROE of 10.1 per cent on 40 per cent deemed common equity. This settlement provides the NGTL System with higher depreciation rates and the opportunity to further increase depreciation rates with an incentive if tolls fall below specified levels, or if growth projects are undertaken. It also includes incentive mechanisms to reduce both physical emissions and emission compliance costs, while also providing incentive for certain operating costs where variances from projected amounts and emissions savings are shared with customers.

Net income for the Canadian Mainline increased by $5 million for the three months ended December 31, 2025 compared to the same period in 2024 mainly due to higher incentive earnings. The Canadian Mainline is operating under the 2021-2026 Mainline Settlement which includes an approved ROE of 10.1 per cent on 40 per cent deemed common equity and an incentive to decrease costs and increase revenues on the pipeline under a beneficial sharing mechanism with our customers.

Comparable EBITDA for Canadian Natural Gas Pipelines increased by $110 million for the three months ended December 31, 2025 compared to the same period in 2024 due to:

•higher flow-through depreciation and income taxes as well as higher incentive earnings on the NGTL System and the Canadian Mainline.

Depreciation and amortization increased by $52 million for the three months ended December 31, 2025 compared to the same period in 2024 primarily reflecting higher depreciation rates on the NGTL System under the 2025-2029 NGTL Settlement and an increase in assets placed in service on the Canadian Mainline.

U.S. Natural Gas Pipelines

U.S. Natural Gas Pipelines segmented earnings increased by $192 million for the three months ended December 31, 2025 compared to the same period in 2024 and included unrealized gains and losses from changes in the fair value of derivatives used in our U.S. natural gas marketing business which has been excluded from our calculation of comparable EBITDA and comparable EBIT.

A weaker U.S. dollar for the three months ended December 31, 2025 had a negative impact on the Canadian dollar equivalent segmented earnings from our U.S. dollar-denominated operations compared to the same period in 2024. Refer to the Foreign exchange section for additional information.

Comparable EBITDA for U.S. Natural Gas Pipelines increased by US$137 million for the three months ended December 31, 2025 compared to the same period in 2024 and was primarily due to the net effect of:

•a net increase in earnings from Columbia Gas as a result of higher transportation rates effective April 1, 2025, pursuant to the Columbia Gas Settlement. Refer to the U.S. Natural Gas Pipelines - Significant events section for additional information

•incremental earnings from projects placed in service, as well as increased earnings from additional contract sales on GTN

•higher realized earnings related to our U.S. natural gas marketing business primarily due to higher margins

•decreased earnings due to higher operational costs, reflective of increased system utilization across our footprint.

Depreciation and amortization increased by US$19 million for the three months ended December 31, 2025 compared to the same period in 2024 primarily due to new projects placed in service and depreciation rate changes as a result of the Columbia Gas Settlement.

124 | TC Energy Management's discussion and analysis 2025

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Mexico Natural Gas Pipelines

Mexico Natural Gas Pipelines segmented earnings increased by $163 million for the three months ended December 31, 2025 compared to the same period in 2024 and included a recovery of $4 million (2024 – recovery of $3 million), on the expected credit loss provision related to the TGNH net investment in leases and certain contract assets in Mexico, which has been excluded from our calculation of comparable EBITDA and comparable EBIT.

A weaker U.S. dollar for the three months and year ended December 31, 2025 had a negative impact on the Canadian dollar equivalent segmented earnings from our U.S. dollar-denominated operations in Mexico compared to the same period in 2024. Refer to the Foreign exchange section for additional information.

Comparable EBITDA for Mexico Natural Gas Pipelines increased by US$118 million for the three months ended December 31, 2025 compared with the same period in 2024, due to the net effect of:

•higher earnings in TGNH due to the completion of the Southeast Gateway pipeline in second quarter 2025

•lower equity earnings from Sur de Texas primarily due to the foreign exchange impacts on the revaluation of
peso-denominated liabilities as a result of a stronger Mexican peso and higher income tax expense mainly related to foreign exchange impacts of U.S. dollar-denominated liabilities. Refer to the Sur de Texas results section for additional information.

Depreciation and amortization was generally consistent for the three months ended December 31, 2025 compared to the same period in 2024. Under sales-type lease accounting, our in-service TGNH pipeline assets are derecognized from     Plant, property and equipment and recorded as a net investment in lease on our Condensed consolidated balance sheet with no depreciation expense being recognized.

Power and Energy Solutions

Power and Energy Solutions segmented earnings decreased by $140 million for the three months ended December 31, 2025 compared to the same period in 2024 and included the following specific items which have been excluded from our calculation of comparable EBITDA and comparable EBIT:

•a pre-tax impairment charge in 2025 of $110 million (2024 - $36 million) for certain Power and Energy Solutions projects following our decision to discontinue development along with updated forecast assumptions as we refocus our Power and Energy Solutions strategy

•our proportionate share of Bruce Power's unrealized gains and losses on funds invested for post-retirement benefits and risk management activities

•unrealized gains and losses from changes in the fair value of derivatives used to reduce commodity exposures.

Comparable EBITDA for Power and Energy Solutions decreased by $124 million for the three months ended December 31, 2025 compared to the same period in 2024 primarily due to the net effect of:

•lower Bruce Power contributions from reduced generation due to the Unit 4 MCR, planned Unit 2 outage in fourth quarter 2025 and increased operating costs, partially offset by a higher contract price. Refer to the Bruce Power results section for additional information

•decreased Canadian Power financial results primarily from lower realized power prices

•increased Natural Gas Storage and other is primarily due to lower business development costs.

Depreciation and amortization generally consistent for the three months ended December 31, 2025 compared to the same period in 2024.

Corporate

Corporate segmented earnings increased by $17 million for the three months ended December 31, 2025 compared to the same period in 2024. Corporate segmented losses included a pre-tax charge of $9 million for the three months ended December 31, 2024 related to Focus Project costs, which has been excluded from our calculation of comparable EBITDA and comparable EBIT.

Comparable EBITDA and EBIT for Corporate increased by $8 million for the three months ended December 31, 2025 compared to the same period in 2024.

TC Energy Management's discussion and analysis 2025 | 125

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QUARTERLY RESULTS - FROM DISCONTINUED OPERATIONS

Factors affecting financial information by quarter

The quarterly results section references non-GAAP measures, which are described on page 22. These measures do not have
any standardized meaning as prescribed by GAAP and therefore may not be comparable to similar measures presented by
other entities.

In fourth quarter 2025, comparable earnings from discontinued operations also excluded:

•a pre-tax recovery of $8 million primarily resulting from the resolution reached in September 2025 under the Separation Agreement with South Bow.

In third quarter 2025, comparable earnings from discontinued operations also excluded:

•a pre-tax charge of $196 million primarily resulting from the resolution reached in September 2025 under the Separation Agreement with South Bow.

In second quarter 2025, comparable earnings from discontinued operations also excluded:

•a pre-tax impairment charge of $29 million related to our estimate of Keystone XL contractual recoveries.

In fourth quarter 2024, comparable earnings from discontinued operations also excluded:

•a pre-tax charge of $85 million from Liquids Pipelines business separation costs related to the Spinoff Transaction, of which     $75 million was recognized in segmented earnings and $10 million in interest income

•a pre-tax expense of $37 million related to our estimate of potential incremental costs resulting from the Milepost 14 incident. This amount represents our 86 per cent share pursuant to the indemnity provisions in the Separation Agreement

•a pre-tax recovery of $3 million as a result of the FERC Administrative Law Judge decision on Keystone in respect of a tolling-related complaint pertaining to amounts recognized in prior periods.

In third quarter 2024, comparable earnings from discontinued operations also excluded:

•a pre-tax charge of $67 million due to Liquids Pipelines business separation costs related to the Spinoff Transaction

•a pre-tax expense of $21 million related to Keystone XL asset disposition and termination activities

•a pre-tax charge of $15 million related to the FERC Administrative Law Judge decision on Keystone in respect of a tolling-related complaint pertaining to amounts recognized in prior periods.

In second quarter 2024, comparable earnings from discontinued operations also excluded:

•a pre-tax charge of $29 million due to Liquids Pipelines business separation costs related to the Spinoff Transaction.

In first quarter 2024, comparable earnings from discontinued operations also excluded:

•a pre-tax charge of $16 million due to Liquids Pipelines business separation costs related to the Spinoff Transaction.

Results from discontinued operations

three months ended December 31						2025						2024
(millions of $, except per share amounts)
Segmented earnings (losses) from discontinued operations						(6)						(109)
Interest income and other						14						(10)
Income (loss) from discontinued operations before income taxes						8						(119)
Income tax (expense) recovery						13						21
Net income (loss) from discontinued operations, net of tax						21						(98)
Net income (loss) per common share from discontinued operations - basic						$0.02						($0.09)

Net income from discontinued operations, net of tax in the three months ended in December 31, 2025 was $21 million or     $0.02 per common share (2024 - net loss of $98 million or loss of $0.09 per common share), an increase of $119 million or $0.11 per common share.

126 | TC Energy Management's discussion and analysis 2025

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Reconciliation of net income (loss) from discontinued operations, net of tax to comparable earnings from discontinued operations

three months ended December 31						2025						2024
(millions of $, except per share amounts)
Net income (loss) from discontinued operations, net of tax						21						(98)
Specific items (pre tax):
South Bow settlement1						(8)						—
Liquids Pipelines business separation costs						—						85
Milepost 14 incremental costs						—						37
Keystone regulatory decisions						—						(3)
Taxes on specific items						(13)						(21)
Comparable earnings from discontinued operations						—						—
Net income (loss) per common share from discontinued operations						$0.02						($0.09)
Specific items (net of tax)						(0.02)						0.09
Comparable earnings per common share from discontinued operations						—						—

1A pre-tax recovery of $8 million for the three months ended December 31, 2025 resulting from the resolution reached in September 2025 under the Separation Agreement with South Bow.

TC Energy Management's discussion and analysis 2025 | 127

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Glossary

Units of measure
Bcf						Billion cubic feet
Bcf/d						Billion cubic feet per day
GWh						Gigawatt hours
km						Kilometres
MMcf/d						Million cubic feet per day
MW						Megawatt(s)
MWh						Megawatt hours
TJ/d						Terajoule per day
General terms and terms related to our operations
CEO						Chief Executive Officer
CFO						Chief Financial Officer
cogeneration facilities						Facilities that produce both electricity and useful heat at the same time
DRP						Dividend Reinvestment and Share Purchase Plan
Empress						A major delivery/receipt point for natural gas near the Alberta/Saskatchewan border
ESG						Environmental, social and governance
FID						Final investment decision
force majeure						Unforeseeable circumstances that prevent a party to a contract from fulfilling it
GHG						Greenhouse gas
HCAs						High-consequence areas
HSSE						Health, safety, sustainability and environment
investment base						Includes rate base, as well as assets under construction
LDC						Local distribution company
LNG						Liquefied natural gas
OM&A						Operating, maintenance and administration
PPA						Power purchase arrangement
rate base						Average assets in service, working capital and deferred amounts used in setting of regulated rates
RNG						Renewable natural gas
TSA						Transportation Service Agreement
TOMS						TC Energy's Operational Management System
WCSB						Western Canadian Sedimentary basin

Accounting terms
AFUDC						Allowance for funds used during construction
U.S. GAAP / GAAP						U.S. generally accepted accounting principles
RRA						Rate-regulated accounting
ROE						Return on common equity
Government and regulatory bodies terms
AER						Alberta Energy Regulator
CER						Canada Energy Regulator
CFE						Comisión Federal de Electricidad (Mexico)
CNE						Comisión Nacional de Energía (Mexico)
CRE						Comisión Reguladora de Energía, or Energy Regulatory Commission (Mexico)
ECCC						Environment and Climate Change Canada
FERC						Federal Energy Regulatory Commission (U.S.)
IESO						Independent Electricity System Operator (Ontario)
IFRS S2						International Financial Reporting Standards S2 Climate-related Disclosures
NYSE						New York Stock Exchange
OBPS						Output Based Pricing System
OPG						Ontario Power Generation
PHMSA						Pipeline and Hazardous Materials Safety Administration
SEC						U.S. Securities and Exchange Commission
SENER						Secretaría de Energía or Mexican Ministry of Energy
TCFD						Task Force on Climate-Related Financial Disclosures
TNFD						Task Force on Nature-related Financial Disclosures
TSX						Toronto Stock Exchange

128 | TC Energy Management's discussion and analysis 2025

EXHIBIT 13.3

Management's Report on Internal Control over Financial Reporting

The consolidated financial statements and Management's Discussion and Analysis (MD&A) included in this Annual Report are the responsibility of the management of TC Energy Corporation (TC Energy or the Company) and have been approved by the Board of Directors of the Company. The consolidated financial statements have been prepared by management in accordance with United States generally accepted accounting principles (GAAP) and include amounts that are based on estimates and judgments. The MD&A is based on the Company's financial results. It compares the Company's financial and operating performance in 2025 to that in 2024, and highlights significant changes between 2024 and 2023. The MD&A should be read in conjunction with the consolidated financial statements and accompanying notes. Financial information contained elsewhere in this Annual Report is consistent with the consolidated financial statements.

Management is responsible for establishing and maintaining adequate internal control over financial reporting for the Company. Management has designed and maintains a system of internal control over financial reporting, including a program of internal audits to carry out its responsibility. Management believes these controls provide reasonable assurance that financial records are reliable and form a proper basis for the preparation of financial statements. The internal control over financial reporting includes management's communication to employees of policies that govern ethical business conduct.

Under the supervision and with the participation of the President and Chief Executive Officer and the Chief Financial Officer, management conducted an evaluation of the effectiveness of its internal control over financial reporting based on the framework in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Management concluded, based on its evaluation, that internal control over financial reporting was effective as of December 31, 2025, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external reporting purposes.

The Board of Directors is responsible for reviewing and approving the consolidated financial statements and MD&A and ensuring that management fulfills its responsibilities for financial reporting and internal control. The Board of Directors carries out these responsibilities primarily through the Audit Committee, which consists of independent, non-management directors. The Audit Committee meets with management at least four times a year and meets independently with internal and external auditors and as a group to review any significant accounting, internal control and auditing matters in accordance with the terms of the Charter of the Audit Committee, which is set out in the Annual Information Form. The Audit Committee's responsibilities include overseeing management's performance in carrying out its financial reporting responsibilities and reviewing the Annual Report, including the consolidated financial statements and MD&A, before these documents are submitted to the Board of Directors for approval. The internal and independent external auditors have access to the Audit Committee without the requirement to obtain prior management approval.

The Audit Committee approves the terms of engagement of the independent external auditors and reviews the annual audit plan, the Auditors' Report and the results of the audit. It also recommends to the Board of Directors the firm of external auditors to be appointed by the shareholders.

The shareholders have appointed KPMG LLP as independent external auditors to express an opinion as to whether the consolidated financial statements present fairly, in all material respects, the Company's consolidated financial position, results of operations and cash flows in accordance with GAAP. The reports of KPMG LLP outline the scope of its examinations and its opinions on the consolidated financial statements and the effectiveness of the Company's internal control over financial reporting.

François L. Poirier President and Chief Executive Officer						Sean O'Donnell Executive Vice-President and Chief Financial Officer
February 12, 2026

TC Energy Consolidated Financial Statements 2025 | 129

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Report of Independent Registered Public Accounting Firm

To the Shareholders and Board of Directors
TC Energy Corporation:

Opinion on the Consolidated Financial Statements

We have audited the accompanying consolidated balance sheets of TC Energy Corporation (the Company) as of December 31, 2025 and 2024, the related consolidated statements of income, comprehensive income, equity, and cash flows for each of the years in the three-year period ended December 31, 2025, and the related notes (collectively, the consolidated financial statements). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2025 and 2024, and the results of operations and its cash flows for each of the years in the three‑year period ended December 31, 2025, in conformity with U.S. generally accepted accounting principles.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company’s internal control over financial reporting as of December 31, 2025, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission, and our report dated February 12, 2026 expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.

Basis for Opinion

These consolidated financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion.

Critical Audit Matters

The critical audit matters communicated below are matters arising from the current period audit of the consolidated financial statements that were communicated or required to be communicated to the audit committee and that: (1) relate to accounts or disclosures that are material to the consolidated financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.

Determination of fair value of the Southeast Gateway pipeline

As discussed in Notes 2 and 9 to the consolidated financial statements, the Company recognized a sales-type lease for the Southeast Gateway pipeline and recorded net investment in lease of $6.6 billion and selling profit or loss of nil upon derecognition of the carrying value of the underlying assets. At lease commencement, the Company recognizes a net investment in lease equal to the present value of the future lease payments and the estimated residual value of the underlying assets discounted at the rate implicit in the lease. The carrying value of the underlying assets is derecognized, with related gains/losses, if any, recognized in the Consolidated statement of income.

We identified the determination of fair value of the Southeast Gateway pipeline as a critical audit matter. The extent of management judgment with regards to certain qualitative factors that support the conclusion that the fair value of the Southeast Gateway pipeline approximated the carrying value of its underlying assets required subjective auditor judgment.     In addition, the audit effort associated with this evaluation required specialized skills and knowledge.

130 | TC Energy Consolidated Financial Statements 2025

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The following are the primary procedures we performed to address this critical audit matter. We evaluated the design and tested the operating effectiveness of certain internal controls related to this critical audit matter. This included controls related to the Company’s determination that the fair value of the Southeast Gateway pipeline approximated the carrying value of its underlying assets. We evaluated the Company’s qualitative assessment of factors that supported the Company’s judgment that the fair value of the underlying assets approximated their carrying value. We evaluated the Company’s forecasted cash flows derived from a market participant’s expected use of the underlying assets to determine an implied rate of return, which was compared to estimated rates of return a market participant would require. In addition, we involved valuation professionals with specialized skills and knowledge, who assisted in:

•evaluating the implied return of the underlying assets by independently developing an expectation for the rate of return a market participant would expect by using publicly available market data for comparable entities; and

•evaluating the implied return of the underlying assets by comparing the implied EBITDA multiple to EBITDA multiples using publicly available market data for comparable entities.

Valuation of goodwill for the Columbia reporting unit

As discussed in Notes 2 and 13 to the consolidated financial statements, the goodwill balance as of December 31, 2025 for the Columbia reporting unit was $10,082 million. The Company performs an annual review for goodwill impairment at the reporting unit level which is one level below the Company’s operating segments. 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 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 the reporting unit was determined by using a discounted cash flow model which requires the use of assumptions related to revenue and capital expenditure projections (collectively, the “key assumptions”). The Company elected to proceed directly to the quantitative goodwill impairment test as of December 31, 2025 for the Columbia reporting unit and determined that the fair value of the Columbia reporting unit, exceeded its carrying value, including goodwill, as of December 31, 2025. We identified the evaluation of the key assumptions used in the valuation of goodwill for the Columbia reporting unit as a critical audit matter. A high degree of auditor judgment was required to evaluate the key assumptions. Minor changes to the key assumptions could have had a significant effect on the Company’s determination of the fair value of the Columbia reporting unit.

The following are the primary procedures we performed to address this critical audit matter. We evaluated the design and tested the operating effectiveness of certain internal controls related to the Company’s determination of the fair value of the Columbia reporting unit and its evaluation of the key assumptions. We compared the Company’s key assumptions used in the prior quantitative goodwill impairment test to actual results to assess the Company’s ability to accurately forecast. We evaluated the Company’s key assumptions in the December 31, 2025 impairment test by comparing them to actual historical results, the outcome of the Columbia Gas Settlement and to assumptions used in industry publications related to North American and global energy consumption and production forecasts.

/s/ KPMG LLP

Chartered Professional Accountants

We have served as the Company's auditor since 1956.

Calgary, Canada

February 12, 2026

TC Energy Consolidated Financial Statements 2025 | 131

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Report of Independent Registered Public Accounting Firm

To the Shareholders and Board of Directors
TC Energy Corporation:

Opinion on Internal Control Over Financial Reporting

We have audited TC Energy Corporation’s (the Company) internal control over financial reporting as of December 31, 2025, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2025, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated balance sheets of the Company as of December 31, 2025 and 2024, the related consolidated statements of income, comprehensive income, equity, and cash flows for each of the years in the three-year period ended December 31, 2025, and the related notes (collectively, the consolidated financial statements), and our report dated February 12, 2026 expressed an unqualified opinion on those consolidated financial statements.

Basis for Opinion

The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management's Report on Internal Control over Financial Reporting included in the Company's Consolidated Financial Statements. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

Definition and Limitations of Internal Control Over Financial Reporting

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/ KPMG LLP

Chartered Professional Accountants

Calgary, Canada

February 12, 2026

132 | TC Energy Consolidated Financial Statements 2025

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Consolidated statement of income

year ended December 31						2025						2024						2023
(millions of Canadian $, except per share amounts)
Revenues (Note 6)
Canadian Natural Gas Pipelines						5,785						5,600						5,173
U.S. Natural Gas Pipelines						7,145						6,339						6,229
Mexico Natural Gas Pipelines						1,450						870						846
Power and Energy Solutions						845						954						1,019
Corporate						14						8						—
						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)						—						—						(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
						8,477						7,985						7,380
Net Gain (Loss) on Sale of Assets (Note 29)						—						620						—
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)
						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)
						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 Common Shares						3,400						4,594						2,829
Amounts Attributable to Common Shares
Net income (loss) from continuing operations						4,306						4,984						2,456
Net income (loss) attributable to non-controlling interests (Note 22)						575						681						146
Net income (loss) attributable to controlling interests from continuing operations						3,731						4,303						2,310
Preferred share dividends						119						104						93
Net income (loss) attributable to common shares from continuing operations						3,612						4,199						2,217
Net income (loss) from discontinued operations, net of tax (Note 4)						(212)						395						612
Net Income (Loss) Attributable to Common Shares						3,400						4,594						2,829
Net Income (Loss) per Common Share - Basic and Diluted (Note 23)
Continuing operations						$3.47						$4.05						$2.15
Discontinued operations						($0.20)						$0.38						$0.60
						$3.27						$4.43						$2.75
Dividends Declared per Common Share						$3.40						$3.7025						$3.72
Weighted Average Number of Common Shares (millions) (Note 23)
Basic						1,040						1,038						1,030
Diluted						1,040						1,038						1,030

The accompanying Notes to the consolidated financial statements are an integral part of these statements.

TC Energy Consolidated Financial Statements 2025 | 133

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Consolidated statement of comprehensive income

year ended December 31			2025			2024			2023
(millions of Canadian $)
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			—			(25)			—
Change in fair value of net investment hedges			1			(18)			17
Change in fair value of cash flow hedges			(22)			35			—
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			—			(6)			—
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

The accompanying Notes to the consolidated financial statements are an integral part of these statements.

134 | TC Energy Consolidated Financial Statements 2025

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Consolidated statement of cash flows

year ended December 31						2025						2024						2023
(millions of Canadian $)
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)						—						—						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)						—						(620)						—
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)						—						791						33
Acquisitions, net of cash acquired (Note 29)						—						—						(307)
Loans to affiliate (issued) repaid, net						—						—						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						—
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)						—						—
Distributions to non-controlling interests and other						(929)						(755)						(173)
Contributions from non-controlling interests						—						21						—
Cash received from factoring arrangement (Note 9)						351						—						—
Loan from affiliate (Note 11)						111						—						—
Disposition of equity interest, net of transaction costs (Note 29)						—						419						5,328
Cash transferred to South Bow, net of debt settlements						—						(244)						—
Gains (losses) on settlement of financial instruments						—						27						—
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

Includes continuing and discontinued operations. Refer to Note 4, Discontinued operations, for additional information related to cash flows from discontinued operations.

The accompanying Notes to the consolidated financial statements are an integral part of these statements.

TC Energy Consolidated Financial Statements 2025 | 135

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Consolidated balance sheet

at December 31									2025						2024
(millions of Canadian $)
ASSETS
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
									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)									—						136
									118,751						118,243
LIABILITIES
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
									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)									—						110
									81,852						79,883
EQUITY
Common shares, no par value (Note 23)									30,218						30,101
Issued and outstanding:			December 31, 2025 – 1,041 million shares
			December 31, 2024 – 1,039 million shares
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
									36,899						38,360
									118,751						118,243

Commitments, Contingencies and Guarantees (Note 30)

Variable Interest Entities (Note 31)

The accompanying Notes to the consolidated financial statements are an integral part of these statements.

On behalf of the Board:

François L. Poirier, Director			Una M. Power, Director

136 | TC Energy Consolidated Financial Statements 2025

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Consolidated statement of equity

year ended December 31						2025						2024						2023
(millions of Canadian $)
Common Shares (Note 23)
Balance at beginning of year						30,101						30,002						28,995
Shares issued:
Exercise of stock options						117						99						4
Dividend reinvestment and share purchase plan						—						—						1,003
Balance at end of year						30,218						30,101						30,002
Preferred Shares (Note 24)
Balance at beginning of year						2,499						2,499						2,499
Redemption of shares						(244)						—						—
Balance at end of year						2,255						2,499						2,499
Additional Paid-In Capital
Balance at beginning of year						—						—						722
Issuance of stock options, net of exercises						(7)						(5)						9
Disposition of equity interest, net of transaction costs (Note 29)						—						(41)						(3,537)
Reclassification of additional paid-in capital deficit to accumulated deficit						7						46						2,806
Balance at end of year						—						—						—
Retained Earnings (Accumulated Deficit)
Balance at beginning of year						(5,241)						(2,997)						819
Net income (loss) attributable to controlling interests						3,519						4,698						2,922
Common share dividends						(3,537)						(3,842)						(3,839)
Preferred share dividends						(117)						(104)						(93)
Spinoff of Liquids Pipelines business (Note 4)						(542)						(2,950)						—
Reclassification of additional paid-in capital deficit to accumulated deficit						(7)						(46)						(2,806)
Balance at end of year						(5,925)						(5,241)						(2,997)
Accumulated Other Comprehensive Income (Loss) (Note 25)
Balance at beginning of year						233						49						955
Other comprehensive income (loss) attributable to controlling interests						(376)						946						(379)
Impact of non-controlling interest (Note 29)						348						(21)						(527)
Spinoff of Liquids Pipelines business (Note 4)						542						(741)						—
Balance at end of year						747						233						49
Equity Attributable to Controlling Interests						27,295						27,592						29,553
Equity Attributable to Non-Controlling Interests
Balance at beginning of year						10,768						9,455						126
Net income (loss) attributable to non-controlling interests (Note 22)						575						681						146
Other comprehensive income (loss) attributable to non-controlling interests						(511)						903						(366)
Disposition of equity and non-controlling interests (Note 29)						(348)						461						9,451
Non-controlling interests on acquisition of Texas Wind Farms (Note 29)						—						—						222
Contributions from non-controlling interests						—						21						—
Distributions declared to non-controlling interests						(880)						(753)						(124)
Balance at end of year						9,604						10,768						9,455
Total Equity						36,899						38,360						39,008

The accompanying Notes to the consolidated financial statements are an integral part of these statements.

TC Energy Consolidated Financial Statements 2025 | 137

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Notes to consolidated financial statements

1. 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.

2. 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.

138 | TC Energy Consolidated Financial Statements 2025

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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.

TC Energy Consolidated Financial Statements 2025 | 139

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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.

140 | TC Energy Consolidated Financial Statements 2025

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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.

TC Energy Consolidated Financial Statements 2025 | 141

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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.

142 | TC Energy Consolidated Financial Statements 2025

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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.

TC Energy Consolidated Financial Statements 2025 | 143

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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).

144 | TC Energy Consolidated Financial Statements 2025

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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.

TC Energy Consolidated Financial Statements 2025 | 145

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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.

146 | TC Energy Consolidated Financial Statements 2025

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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.

TC Energy Consolidated Financial Statements 2025 | 147

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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.

148 | TC Energy Consolidated Financial Statements 2025

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3.  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.

TC Energy Consolidated Financial Statements 2025 | 149

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4.  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.

150 | TC Energy Consolidated Financial Statements 2025

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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

TC Energy Consolidated Financial Statements 2025 | 151

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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

152 | TC Energy Consolidated Financial Statements 2025

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5.  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.

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.

TC Energy Consolidated Financial Statements 2025 | 153

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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.

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.

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.

154 | TC Energy Consolidated Financial Statements 2025

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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.

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.

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.

TC Energy Consolidated Financial Statements 2025 | 155

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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

156 | TC Energy Consolidated Financial Statements 2025

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6. 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.

TC Energy Consolidated Financial Statements 2025 | 157

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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.

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.

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.

158 | TC Energy Consolidated Financial Statements 2025

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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.

7.  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

TC Energy Consolidated Financial Statements 2025 | 159

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8.  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

160 | TC Energy Consolidated Financial Statements 2025

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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.

TC Energy Consolidated Financial Statements 2025 | 161

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9.  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

162 | TC Energy Consolidated Financial Statements 2025

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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.

TC Energy Consolidated Financial Statements 2025 | 163

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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

164 | TC Energy Consolidated Financial Statements 2025

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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.

10.  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.

TC Energy Consolidated Financial Statements 2025 | 165

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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).

166 | TC Energy Consolidated Financial Statements 2025

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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.

TC Energy Consolidated Financial Statements 2025 | 167

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11.  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.

168 | TC Energy Consolidated Financial Statements 2025

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12.  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.

TC Energy Consolidated Financial Statements 2025 | 169

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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.

170 | TC Energy Consolidated Financial Statements 2025

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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.

TC Energy Consolidated Financial Statements 2025 | 171

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13.  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.

172 | TC Energy Consolidated Financial Statements 2025

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14.  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

TC Energy Consolidated Financial Statements 2025 | 173

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15.  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

4

1.3

2.0

4

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).

174 | TC Energy Consolidated Financial Statements 2025

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16.  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

17.  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

TC Energy Consolidated Financial Statements 2025 | 175

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18.  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

176 | TC Energy Consolidated Financial Statements 2025

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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.

TC Energy Consolidated Financial Statements 2025 | 177

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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.

178 | TC Energy Consolidated Financial Statements 2025

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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.

TC Energy Consolidated Financial Statements 2025 | 179

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19.  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.

180 | TC Energy Consolidated Financial Statements 2025

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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

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.

TC Energy Consolidated Financial Statements 2025 | 181

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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

87

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.

182 | TC Energy Consolidated Financial Statements 2025

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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

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.

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.

TC Energy Consolidated Financial Statements 2025 | 183

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20.  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.

184 | TC Energy Consolidated Financial Statements 2025

---

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.

21.  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)

22.  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.

TC Energy Consolidated Financial Statements 2025 | 185

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23.  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

186 | TC Energy Consolidated Financial Statements 2025

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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.

TC Energy Consolidated Financial Statements 2025 | 187

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24.  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.

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.

188 | TC Energy Consolidated Financial Statements 2025

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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.

25.  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)

TC Energy Consolidated Financial Statements 2025 | 189

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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.

190 | TC Energy Consolidated Financial Statements 2025

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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.

TC Energy Consolidated Financial Statements 2025 | 191

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26.  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.

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.

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.

192 | TC Energy Consolidated Financial Statements 2025

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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).

TC Energy Consolidated Financial Statements 2025 | 193

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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		%

194 | TC Energy Consolidated Financial Statements 2025

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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.

TC Energy Consolidated Financial Statements 2025 | 195

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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.

196 | TC Energy Consolidated Financial Statements 2025

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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		%				—						—						—

TC Energy Consolidated Financial Statements 2025 | 197

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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)

198 | TC Energy Consolidated Financial Statements 2025

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27.  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.

TC Energy Consolidated Financial Statements 2025 | 199

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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.

200 | TC Energy Consolidated Financial Statements 2025

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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.

TC Energy Consolidated Financial Statements 2025 | 201

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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.

202 | TC Energy Consolidated Financial Statements 2025

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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.

TC Energy Consolidated Financial Statements 2025 | 203

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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.

204 | TC Energy Consolidated Financial Statements 2025

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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).

TC Energy Consolidated Financial Statements 2025 | 205

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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).

206 | TC Energy Consolidated Financial Statements 2025

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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.

TC Energy Consolidated Financial Statements 2025 | 207

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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.

208 | TC Energy Consolidated Financial Statements 2025

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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.

TC Energy Consolidated Financial Statements 2025 | 209

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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).

28.  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.

210 | TC Energy Consolidated Financial Statements 2025

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29.  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 Consolidated Financial Statements 2025 | 211

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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.

30.  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.

212 | TC Energy Consolidated Financial Statements 2025

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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.

TC Energy Consolidated Financial Statements 2025 | 213

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31.  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

214 | TC Energy Consolidated Financial Statements 2025

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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.

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.

TC Energy Consolidated Financial Statements 2025 | 215

EXHIBIT 23.1

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We consent to the use of:

•our report dated February 12, 2026 on the consolidated financial statements of TC Energy Corporation (the “Company”) which comprise the consolidated balance sheets as at December 31, 2025 and 2024, the related consolidated statements of income, comprehensive income, equity, and cash flows for each of the years in the three-year period ended December 31, 2025, and the related notes, and

•our report dated February 12, 2026 on the effectiveness of the Company’s internal control over financial reporting as of December 31, 2025

each of which is included in the Annual Report on Form 40-F of the Company for the fiscal year ended December 31, 2025.

We also consent to the incorporation by reference of such reports in the:

•Registration Statements No. 333-5916, No. 333-8470, No. 333-9130, No. 333-151736, No. 333-184074, No. 333-227114 and No. 333-237979 on Form S-8 of TC Energy Corporation;

•Registration Statements No. 33-13564 and No. 333-6132 on Form F-3 of TC Energy Corporation;

•Registration Statement No. 333-252123 on Form F-10 of TC Energy Corporation; and

•Registration Statements No. 333-267323 and No. 333-283633 on Form F-10 of TransCanada PipeLines Limited.

/s/ KPMG LLP

Chartered Professional Accountants

February 12, 2026

Calgary, Canada

EXHIBIT 31.1

Certifications

I, François L. Poirier, certify that:

1.I have reviewed this annual report on Form 40-F of TC Energy Corporation;

2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the issuer as of, and for, the periods presented in this report;

4.The issuer's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the issuer and have:

(a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the issuer, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b)Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c)Evaluated the effectiveness of the issuer's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d)Disclosed in this report any change in the issuer's internal control over financial reporting that occurred during the period covered by the annual report that has materially affected, or is reasonably likely to materially affect, the issuer's internal control over financial reporting; and

5.The issuer's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the issuer's auditors and the audit committee of the issuer's board of directors (or persons performing the equivalent functions):

(a)All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the issuer's ability to record, process, summarize and report financial information; and

(b)Any fraud, whether or not material, that involves management or other employees who have a significant role in the issuer's internal control over financial reporting.

Dated February 13, 2026

			/s/ FRANÇOIS L. POIRIER
			François L. Poirier President and Chief Executive Officer

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Certifications

I, François L. Poirier, certify that:

1.I have reviewed this annual report on Form 40-F of TransCanada PipeLines Limited;

2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the issuer as of, and for, the periods presented in this report;

4.The issuer's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the issuer and have:

(a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the issuer, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b)Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c)Evaluated the effectiveness of the issuer's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d)Disclosed in this report any change in the issuer's internal control over financial reporting that occurred during the period covered by the annual report that has materially affected, or is reasonably likely to materially affect, the issuer's internal control over financial reporting; and

5.The issuer's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the issuer's auditors and the audit committee of the issuer's board of directors (or persons performing the equivalent functions):

(a)All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the issuer's ability to record, process, summarize and report financial information; and

(b)Any fraud, whether or not material, that involves management or other employees who have a significant role in the issuer's internal control over financial reporting.

Dated February 13, 2026

			/s/ FRANÇOIS L. POIRIER
			François L. Poirier President and Chief Executive Officer

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EXHIBIT 31.2

Certifications

I, Sean P. O'Donnell, certify that:

1.I have reviewed this annual report on Form 40-F of TC Energy Corporation;

2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the issuer as of, and for, the periods presented in this report;

4.The issuer's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the issuer and have:

(a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the issuer, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b)Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c)Evaluated the effectiveness of the issuer's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d)Disclosed in this report any change in the issuer's internal control over financial reporting that occurred during the period covered by the annual report that has materially affected, or is reasonably likely to materially affect, the issuer's internal control over financial reporting; and

5.The issuer's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the issuer's auditors and the audit committee of the issuer's board of directors (or persons performing the equivalent functions):

(a)All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the issuer's ability to record, process, summarize and report financial information; and

(b)Any fraud, whether or not material, that involves management or other employees who have a significant role in the issuer's internal control over financial reporting.

Dated February 13, 2026

			/s/ SEAN P. O'DONNELL
			Sean P. O'Donnell Executive Vice-President, Strategy and Corporate Development and Chief Financial Officer

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Certifications

I, Sean P. O'Donnell, certify that:

1.I have reviewed this annual report on Form 40-F of TransCanada PipeLines Limited;

2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the issuer as of, and for, the periods presented in this report;

4.The issuer's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the issuer and have:

(a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the issuer, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b)Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c)Evaluated the effectiveness of the issuer's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d)Disclosed in this report any change in the issuer's internal control over financial reporting that occurred during the period covered by the annual report that has materially affected, or is reasonably likely to materially affect, the issuer's internal control over financial reporting; and

5.The issuer's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the issuer's auditors and the audit committee of the issuer's board of directors (or persons performing the equivalent functions):

(a)All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the issuer's ability to record, process, summarize and report financial information; and

(b)Any fraud, whether or not material, that involves management or other employees who have a significant role in the issuer's internal control over financial reporting.

Dated February 13, 2026

			/s/ SEAN P. O'DONNELL
			Sean P. O'Donnell Executive Vice-President, Strategy and Corporate Development and Chief Financial Officer

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EXHIBIT 32.1

TC ENERGY CORPORATION

450 – 1st Street S.W.

Calgary, Alberta, Canada

T2P 5H1

CERTIFICATION OF CHIEF EXECUTIVE OFFICER

UNDER SECTION 906 OF SARBANES-OXLEY ACT OF 2002

I, François L. Poirier, the Chief Executive Officer of TC Energy Corporation (the "Company"), in compliance with 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, hereby certify, in connection with the Company's Annual report as filed on Form 40‑F for the fiscal year ended December 31, 2025 with the Securities and Exchange Commission (the "Report"), that:

1.The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

2.The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

			/s/ FRANÇOIS L. POIRIER
			François L. Poirier Chief Executive Officer
			February 13, 2026

1 of 2

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TRANSCANADA PIPELINES LIMITED

450 – 1st Street S.W.

Calgary, Alberta, Canada

T2P 5H1

CERTIFICATION OF CHIEF EXECUTIVE OFFICER

UNDER SECTION 906 OF SARBANES-OXLEY ACT OF 2002

I, François L. Poirier, the Chief Executive Officer of TransCanada PipeLines Limited (the "Company"), in compliance with 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, hereby certify, in connection with TC Energy Corporation's Annual report as filed on Form 40-F for the fiscal year ended December 31, 2025 with the Securities and Exchange Commission (the "Report"), that:

1.The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

2.The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

			/s/ FRANÇOIS L. POIRIER
			François L. Poirier Chief Executive Officer
			February 13, 2026

2 of 2

EXHIBIT 32.2

TC ENERGY CORPORATION

450 – 1st Street S.W.

Calgary, Alberta, Canada

T2P 5H1

CERTIFICATION OF CHIEF FINANCIAL OFFICER

UNDER SECTION 906 OF SARBANES-OXLEY ACT OF 2002

I, Sean P. O'Donnell, the Chief Financial Officer of TC Energy Corporation (the "Company"), in compliance with 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, hereby certify, in connection with the Company's Annual report as filed on Form 40-F for the fiscal year ended December 31, 2025 with the Securities and Exchange Commission (the "Report"), that:

1.The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

2.The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

			/s/ SEAN P. O'DONNELL
			Sean P. O'Donnell Chief Financial Officer
			February 13, 2026

1 of 2

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TRANSCANADA PIPELINES LIMITED

450 – 1st Street S.W.

Calgary, Alberta, Canada

T2P 5H1

CERTIFICATION OF CHIEF FINANCIAL OFFICER

UNDER SECTION 906 OF SARBANES-OXLEY ACT OF 2002

I, Sean P. O'Donnell, the Chief Financial Officer of TransCanada PipeLines Limited (the "Company"), in compliance with 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, hereby certify, in connection with TC Energy Corporation's Annual report as filed on Form 40-F for the fiscal year ended December 31, 2025 with the Securities and Exchange Commission (the "Report"), that:

1.The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

2.The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

			/s/ SEAN P. O'DONNELL
			Sean P. O'Donnell Chief Financial Officer
			February 13, 2026

2 of 2

UNCONTROLLED IF PRINTED DOCUMENT CLASSIFICATION: INTERNAL ID: 119865992 LAST REVIEWED: 2023/11/07 STATUS: APPROVED 2023/11/07 EFFECTIVE DATE: 2023/12/01 1 Policy. EXHIBIT 97.1 Incentive compensation recoupment and holdback policy. Purpose and scope The purpose of this Policy is to provide direction for the process of recouping Erroneously Awarded Compensation in order to satisfy the requirements of the NYSE Listing Standards and Rule 10D-1 as adopted by the U.S. SEC to implement Section 954 of the Dodd-Frank Wall Street Reform and Consumer Protection Act of 2010. This Policy will operate in addition to any legal requirements that may apply to the Company and its Employees, officers and directors. This Policy is in addition to any other action or remedy available to the Company against such individuals under applicable law, policy or contract, up to and including termination of employment and/or legal action for breach of fiduciary duty or fraud. This Policy applies to all Covered Executives of TC Energy Corporation and their beneficiaries, heirs, executors, administrators or other legal representatives. Policy 1 Recoupment event 1.1 If TC Energy Corporation is required to prepare a Restatement, then, as determined by the Human Resources Committee, the Covered Executive’s Incentive-Based Compensation will be subject to forfeiture, recovery and recoupment, subject to the following: a) This Policy applies to Incentive-Based Compensation received by a Covered Executive: (i) on or after October 2, 2023, (ii) after beginning services as a Covered Executive, and any subsequent changes in a Covered Executive’s employment status, including retirement or termination of employment, do not affect the Company’s rights to recoup Erroneously Awarded Compensation pursuant to this Policy, and (iii) if the Covered Executive served as a Covered Executive at any time during the performance period for such Incentive-Based Compensation. b) The amount to be forfeited or recouped will equal the Erroneously Awarded Compensation. The Human Resources Committee will take actions necessary to recoup the Erroneously Awarded Compensation reasonably promptly following a Restatement. Where the amount of Erroneously Awarded Compensation is not subject to

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Incentive compensation recoupment and holdback policy. UNCONTROLLED IF PRINTED DOCUMENT CLASSIFICATION: INTERNAL ID: 119865992 LAST REVIEWED: 2023/11/07 STATUS: APPROVED 2023/11/07 EFFECTIVE DATE: 2023/12/01 2 mathematical recalculation directly from the information in the Restatement, the amount must be based on a reasonable estimate of the effect of the Restatement on stock price or total shareholder return upon which the Incentive-Based Compensation was received. The Company will maintain documentation of the determination of that reasonable estimate and provide such documentation to the New York Stock Exchange (NYSE). The amount of the Erroneously Awarded Compensation must not be reduced based on, or otherwise calculated with regard to, any taxes paid by the Covered Executive with respect to such amounts. c) This Policy must only apply to Incentive-Based Compensation that was received during the Applicable Period and that was received (or would have been settled in the absence of an elective deferral of payment by the individual) while TC Energy Corporation has a class of securities listed on a U.S. national securities exchange or a national securities association. For purposes of this Policy, Incentive-Based Compensation is deemed received in the fiscal period during which the Financial Reporting Measure(s) specified in the applicable Incentive-Based Compensation is attained, even if the payment or grant of the Incentive-Based Compensation occurs after the end of such fiscal period. 1.2 In the event of a recoupment of Erroneously Awarded Compensation from a Covered Executive, the Human Resources Committee may also seek reimbursement of all reasonable costs, including legal fees, incurred in connection with the recoupment of the Erroneously Awarded Compensation from such Covered Executive. 2 Impracticability 2.1 The Company must recoup any Erroneously Awarded Compensation unless the conditions set forth in the following clauses (a), (b) or (c) are met and such recoupment would be impracticable, as determined by the Human Resources Committee in accordance with Rule 10D-1 and the NYSE Listing Standards. No recoupment will be required if: a) the direct expense paid to a third party to assist in enforcing this Policy would exceed the amount to be recouped, provided that before concluding that it would be impractical to recoup any amount of Erroneously Awarded Compensation based on this clause (a), the Company must make a reasonable attempt to recoup such Erroneously Awarded Compensation, document such reasonable attempt(s) and provide such documentation to the NYSE; b) recoupment would likely cause an otherwise tax-qualified retirement plan, under which benefits are broadly available to Employees of the Company, to fail to meet the applicable requirements of the U.S. Internal Revenue Code, or any successor provision thereof; or c) recoupment would violate home country law where that law was adopted prior to November 28, 2022, provided that before concluding that it would be impractical to recoup any amount of Erroneously Awarded Compensation based on this clause (c), the Company must obtain an opinion of home country legal counsel, acceptable to the NYSE, that recoupment would result in such violation, and must provide such opinion to the NYSE.

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Incentive compensation recoupment and holdback policy. UNCONTROLLED IF PRINTED DOCUMENT CLASSIFICATION: INTERNAL ID: 119865992 LAST REVIEWED: 2023/11/07 STATUS: APPROVED 2023/11/07 EFFECTIVE DATE: 2023/12/01 3 3 No indemnification 3.1 The Company must not indemnify any current or former Covered Executive against the loss of Erroneously Awarded Compensation, and must not pay, or reimburse any Covered Executives for premiums, for any insurance policy to fund such Covered Executive’s potential repayment obligations. 4 Other recoupment rights 4.1 The Human Resources Committee may require that any employment agreement, equity award agreement, or similar agreement entered into, amended or restated on or after the Effective Date must, as a condition to the grant of any benefit thereunder, require a Covered Executive to agree to abide by the terms of this Policy and the application of this Policy to any award made prior to the Effective Date. 5 Notification requirements 5.1 In the event of a Restatement or potential Restatement, the Financial Reporting department must notify the Corporate Secretarial Legal department and the Human Resources department as soon as reasonably possible. 6 Effective Date 6.1 This Policy is effective as of the Effective Date. 6.2 To the extent there are any inconsistencies, as of the Effective Date, this Policy supersedes all prior contracts, agreements and understandings, written or oral, with any Covered Executive. In the event any contract, agreement or understanding with any Covered Executive is inconsistent with the terms of this Policy, the terms of this Policy will govern. 6.3 The terms of this Policy must apply to any Incentive-Based Compensation that is received by a Covered Executive on or after October 2, 2023, even if such Incentive-Based Compensation was approved, awarded, granted or paid to the Covered Executive prior to October 2, 2023. Subject to applicable law, the Human Resources Committee may effect forfeiture or recoupment under this Policy from any amount of compensation approved, awarded, granted, payable or paid to the Covered Executive prior to, on or after October 2, 2023.

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Incentive compensation recoupment and holdback policy. UNCONTROLLED IF PRINTED DOCUMENT CLASSIFICATION: INTERNAL ID: 119865992 LAST REVIEWED: 2023/11/07 STATUS: APPROVED 2023/11/07 EFFECTIVE DATE: 2023/12/01 4 Your responsibility Employees must follow all applicable provisions and the spirit and intent of this corporate governance document and support others in doing so. Employees must promptly report any suspected or actual violation of this corporate governance document through available channels so that TC Energy can investigate and address it appropriately. Employees who violate this corporate governance document or knowingly permit others under their supervision to violate it, may be subject to appropriate corrective action, up to and including termination of employment or contract, as applicable, in accordance with the Company’s corporate governance documents, employment practices, contracts, collective bargaining agreements and processes. Interpretation and administration The Company has sole discretion to interpret, administer and apply this corporate governance document and to change it at any time to address new or changed legal requirements or business circumstances. Non-retaliation TC Energy supports and encourages Employees and Contractors to report suspected violations of corporate governance documents, applicable laws, regulations, and authorizations, as well as hazards, potential hazards, incidents involving health and safety or the environment, and near hits. Such reports can be made through available channels. TC Energy takes every report seriously and investigates it to identify facts and, when warranted, makes improvements to our corporate governance documents and practices. All Employees and Contractors making reports in good faith will be protected from retaliation, and all Employees and Contractors must report if they or someone they know is being or has been retaliated against for reporting. Good Faith Reporting will not protect Employees and Contractors who make intentionally false or malicious reports, or who seek to exempt their own negligence or willful misconduct by the act of making a report. Definitions Applicable Period means the three completed fiscal years prior to the earlier of: • the date TC Energy Corporation’s Board of Directors, a committee of the Board of Directors, or officer(s) authorized to take such action if action by the Board of Directors is not required, concludes, or reasonably should have concluded, that TC Energy Corporation is required to prepare a Restatement; or • the date a court, regulator, or other legally authorized body directs TC Energy Corporation to prepare a Restatement.

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Incentive compensation recoupment and holdback policy. UNCONTROLLED IF PRINTED DOCUMENT CLASSIFICATION: INTERNAL ID: 119865992 LAST REVIEWED: 2023/11/07 STATUS: APPROVED 2023/11/07 EFFECTIVE DATE: 2023/12/01 5 In addition to the last three completed fiscal years described in the preceding sentence, the Applicable Period includes any transition period (that results from a change in TC Energy Corporation’s fiscal year) within or immediately following those three completed fiscal years; provided, however, a transition period between the last day of TC Energy Corporation’s previous fiscal year end and the first day of its new fiscal year that comprises a period of nine to 12 months would be deemed a completed fiscal year for purposes of the Applicable Period. Covered Executive means all of TC Energy Corporation’s current and former executive officers, as determined by the Human Resources Committee, in accordance with the Listing Standards and Rule 10D-1 and the definition of executive officer as defined in Rule 10D-1(d). Effective Date means December 1, 2023. Employee means full-time, part-time, temporary and student employees of the Company. Erroneously-Awarded Compensation means the amount of Incentive-Based Compensation received by a Covered Executive that exceeds the amount of Incentive-Based Compensation that otherwise would have been received had it been determined based on the Restatements. Exchange Act means the U.S. Securities Exchange Act of 1934, as amended. Financial Reporting Measures means measures that are determined and presented in accordance with the accounting principles used in preparing TC Energy Corporation’s financial statements, and any measures that are derived wholly or in part from such measures, including stock price and total shareholder return. Good Faith Reporting means an open, honest, fair and reasonable report without malice or ulterior motive. Human Resources Committee means the Human Resources Committee of the TC Energy Corporation Board of Directors. Incentive-Based Compensation means all compensation, such as cash bonuses or other cash incentive awards (including any deferred element thereof), and vested and unvested equity awards (including options, restricted stock and restricted stock units, performance stock unit awards and performance stock awards) from the Company that is granted, earned, or vested based wholly or in part upon the attainment of a Financial Reporting Measure. For the avoidance of doubt, Incentive-Based Compensation does not include annual salary, compensation awarded based on completion of a specified period of service, or compensation awarded based on subjective standards, strategic measures, or operational measures, unless also based on attainment of a Financial Reporting Measure. NYSE Listing Standards means Section 303A.14 of the New York Stock Exchange Listed Company Manual. Restatement means an accounting restatement of TC Energy Corporation’s financial statements due to material noncompliance with any financial reporting requirement under the U.S. federal securities laws, including any required accounting Restatement to correct an error in previously issued financial statements that is material to the previously issued financial statements, or that

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Incentive compensation recoupment and holdback policy. UNCONTROLLED IF PRINTED DOCUMENT CLASSIFICATION: INTERNAL ID: 119865992 LAST REVIEWED: 2023/11/07 STATUS: APPROVED 2023/11/07 EFFECTIVE DATE: 2023/12/01 6 would result in a material misstatement if the error were corrected in the current period or left uncorrected in the current period. Rule 10D-1 means Rule 10D-1 promulgated under the Exchange Act. TC Energy or the Company means TC Energy Corporation and its wholly-owned subsidiaries and operated entities. U.S. SEC means the United States Securities and Exchange Commission. References Related corporate governance and supporting documents • Code of Business Ethics Policy Other References • Dodd-Frank Wall Street Reform • NYSE Listing Standards • U.S. Internal Revenue Code • U.S SEC How to contact us • Policy Questions and Comments TC Energy’s reporting channels • Ethics Helpline • Corporate Compliance • Internal Audit • Human Resources • Legal department • Compliance Coordinators

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MAKING THE RIGHT CHOICES – DOING THE RIGHT THING TC Energy’s Code of Business Ethics (COBE) Policy Home Living our values Ethical business conduct Communication Assets and information Have a question? We’re here to help Table of contents EXHIBIT 99.1

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MESSAGE FROM FRANÇOIS POIRIER At TC Energy, we know what we do, and more importantly, how we do it, matters. The actions and decisions you make every day impact the Company and the communities we serve. That’s why we must ensure our actions are aligned with our values. It is important that stakeholders, rightsholders and the public are confident they can count on us to act with integrity in every situation. Our core values – safety in every step, personal accountability, one team and active learning – form the foundation of how we do business. Our Code of Business Ethics (COBE) helps us put our values into action by providing clear guidance on what ethical conduct looks like. As a member of the TC Energy team, you are expected to read, understand and comply with the principles and requirements set out in COBE and are required to complete annual COBE training and certification. We encourage you to refer to COBE regularly to help guide your decisions at work. COBE provides a framework for you to ask questions and highlights the resources in place to report concerns. Our purpose is clear – we are proud to connect the world to the energy it needs. François Poirier President & CEO TC Energy – Code of Business Ethics Policy   2   Home Living our values Ethical business conduct Communication Assets and information Have a question? We’re here to help Table of contents

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OUR EXPECTATIONS AND YOUR RESPONSIBILITIES The Code of Business Ethics (COBE) Policy reinforces TC Energy Corporation’s (the Company’s or TC Energy’s) requirements and expectations for conducting business and behaviours, and provides guidance to ensure our daily activities and decisions appropriately reflect, and are consistent with, our core values of safety in every step, personal accountability, one team and active learning. Doing business ethically, fairly and responsibly is not just a concept at TC Energy, it is a commitment we make every day. The COBE Policy functions in conjunction with TC Energy’s other policies and applies to all Employees, directors, officers and Contingent Workforce Contractors (CWCs) of TC Energy and its wholly-owned subsidiaries and/or operated entities in all countries in which TC Energy conducts business. In addition, TC Energy has a Contractor Code of Business Ethics (COBE) Policy that communicates the same requirements in the COBE Policy, as applicable. You must understand these requirements and know how to meet TC Energy’s standards. We expect compliance with all applicable laws, regulations, policies and rules. Have a question? We’re here to help. If you are unsure of what standard you need to comply with, ask. Contact information is located in the Resources section of this document. Failure to comply with the requirements set out in this document, or any TC Energy policy, may lead to serious consequences and corrective action up to and including termination of employment or contract. Ꝓ Look for this symbol throughout the COBE Policy to guide you to relevant policies available on our websites at TCEnergy.com/about/governance and on our Policy Listing 1TC webpage. TC Energy – Code of Business Ethics Policy   3   Home Table of contents Living our values Ethical business conduct Communication Assets and information Have a question? We’re here to help

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TABLE OF CONTENTS MESSAGE FROM FRANÇOIS POIRIER . . . . . . . . . . . . . . . . . . . . . 2 OUR EXPECTATIONS AND YOUR RESPONSIBILITIES . . . . . . . . . . 3 ETHICS HELP LINE . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4 OUR VALUES. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5 LIVING OUR VALUES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6 Making the right choices and doing the right thing . . . . . . . . . 7 Reporting safety, legal and ethical violations. . . . . . . . . . . . . . 8 Leader responsibilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9 Safety in every step . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10 Alcohol and drug use and being fit for work. . . . . . . . . . . . . . . 11 Human rights . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12 Harassment and violence-free workplace . . . . . . . . . . . . . . . 13 Employment equity and equal opportunity . . . . . . . . . . . . . . 13 Protecting everyone from weapons in the workplace. . . . . . . 14 ETHICAL BUSINESS CONDUCT . . . . . . . . . . . . . . . . . . . . . . . . 15 Avoiding conflicts of interest . . . . . . . . . . . . . . . . . . . . . . . . . 16 Personal Relationships . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17 Outside business activities and outside directorships. . . . . . . 18 Other potential conflicts of interest . . . . . . . . . . . . . . . . . . . . 19 Gifts, invitations and entertainment . . . . . . . . . . . . . . . . . . . 20 Engaging Government Officials . . . . . . . . . . . . . . . . . . . . . . . 22 Political contributions and lobbying . . . . . . . . . . . . . . . . . . . . 23 International trade . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24 Insider trading . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25 Complying with regulatory requirements . . . . . . . . . . . . . . . 26 Inter-affiliate interactions . . . . . . . . . . . . . . . . . . . . . . . . . . . 27 Competing fairly . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 28 Accounting, financial reporting and fraud prevention . . . . . . 29 Preventing money laundering and terrorist financing. . . . . . . 30 COMMUNICATION . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 31 Being socially responsible. . . . . . . . . . . . . . . . . . . . . . . . . . . . 32 Being a good ambassador of TC Energy. . . . . . . . . . . . . . . . . . 33 Social media and communications with the public. . . . . . . . . 34 Public disclosure of information . . . . . . . . . . . . . . . . . . . . . . . 35 Dealing fairly with customers, Contractors and other stakeholders . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 36 Dealing fairly with competitors . . . . . . . . . . . . . . . . . . . . . . . 37 ASSETS AND INFORMATION . . . . . . . . . . . . . . . . . . . . . . . . . . 38 Protecting confidential information. . . . . . . . . . . . . . . . . . . . 39 Generative Artificial Intelligence (AI) . . . . . . . . . . . . . . . . . . . 39 Protecting personal information. . . . . . . . . . . . . . . . . . . . . . . 40 Managing and maintaining the security of information . . . . . 41 Protecting and respecting intellectual property rights. . . . . . 42 Use and protection of TC Energy’s assets . . . . . . . . . . . . . . . . 43 HAVE A QUESTION? WE’RE HERE TO HELP . . . . . . . . . . . . . . . 45 Your responsibility and non-retaliation. . . . . . . . . . . . . . . . . . 46 Asking questions and reporting concerns . . . . . . . . . . . . . . . . 47 GLOSSARY. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 48 ETHICS HELP LINE Canada / U.S.: 1-888-920-2042 Mexico: 800-283-2783 (if calling from a cell phone) 0-800-283-2783 (if calling from a land line) TCEnergy.com/about/governance/code-of-business-ethics Home Table of contents Living our values Ethical business conduct Communication Assets and information Have a question? We’re here to help TC Energy – Code of Business Ethics Policy   4  

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OUR VALUES Our values guide our behaviours, decisions and actions every day. SAFETY IN EVERY STEP I put safety first to protect myself, my teammates, the public and the environment. PERSONAL ACCOUNTABILITY I act with integrity and own my commitments and outcomes. ONE TEAM I am part of the greater whole, where our unique skills enable us to achieve more together. ACTIVE LEARNING I embrace learning in all aspects of my work with curiosity and creativity. Ꝓ Our Commitment Statement TC Energy – Code of Business Ethics Policy   5   Home Table of contents Living our values Ethical business conduct Communication Assets and information Have a question? We’re here to help

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LIVING OUR VALUES + Making the right choices and doing the right thing + Reporting safety, legal and ethical violations + Leader responsibilities + Safety in every step + Alcohol and drug use and being fit for work + Human rights + Harassment and violence-free workplace + Employment equity and equal opportunity + Protecting everyone from weapons in the workplace TC Energy – Code of Business Ethics Policy   6   Home Table of contents Ethical business conduct Communication Assets and information Have a question? We’re here to help Living our values

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You are on the right path! YES YES Is it legal? Is it legal? YES YES YES Does it follow COBE and our other policies? Does it support our values? Does it feel right, fair and honest? Would I want everyone to know? NO NOT SURE NO NOT SURE NO NOT SURE NO NOT SURE NO NOT SURE MAKING THE RIGHT CHOICES AND DOING THE RIGHT THING At TC Energy, making the right choices and doing the right thing aren’t just words – these are fundamental requirements to how we do business that all Personnel must carry out in everything we do. But, what does it really mean to make the right choices and do the right thing? At a minimum, it means following the principles set out in COBE, including: • We report all health, safety and environment related hazards, potential hazards, incidents, near hits and unsafe acts • We comply with the applicable legal requirements and policies that impact us in our daily work • We report, through appropriate internal channels or the Ethics Help Line, any instances of actual or potential non-compliance with legal requirements or with our policies that we become aware of • We do not retaliate against anyone for good-faith reporting • We support others in making the right choices and doing the right thing Even if we try our best to make the right choices and do the right thing, there are times when the right thing isn’t completely clear. It’s at those times that we need to ask ourselves some necessary questions. The below guide to making the right choices and doing the right thing is intended to help you identify the right path in those situations. Contact the Ethics-Help-Line or one of the TC Energy’s internal safe and confidential reporting channels to help guide you in the right direction TC Energy – Code of Business Ethics Policy   7   Home Table of contents Living our values Ethical business conduct Communication Assets and information Have a question? We’re here to help

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REPORTING SAFETY, LEGAL AND ETHICAL VIOLATIONS We report actual or potential non-compliances with our policies or our legal requirements, so they can be addressed appropriately. Retaliation for Good Faith Reporting is prohibited at TC Energy and your confidentiality and identity will be protected to the greatest extent possible. ETHICS HELP LINE Canada / U.S.: 1-888-920-2042 Mexico: 800-283-2783 (if calling from a cell phone) 0-800-283-2783 (if calling from a land line) TCEnergy.com/about/governance/code-of-business-ethics How do I report an issue or seek guidance? You are required to report any actual or suspected violation of the law or COBE and all health, safety and environment related hazards, potential hazards, incidents, near hits and unsafe acts of which you may become aware. We take every report seriously and provide immunity from disciplinary action for Good Faith Reporting of incidents and issues. Resources To report an issue, or if you would like guidance on how to make the right choices and do the right thing in a particular situation, the following resources are available to you: • Your leader • Your Human Resources Business Partner • Your Compliance Coordinator • Corporate Compliance • Internal Audit • Legal department • Privacy Office • Harassment Investigation Coordinator • Safety Personnel • TC Energy’s Environment Health and Safety Management (EHSM) Incident Management System If you are uncomfortable speaking to any of these resources or if you would like to remain anonymous, you can contact the Ethics Help Line. For contact information – click here. TC Energy – Code of Business Ethics Policy   8   Home Table of contents Living our values Ethical business conduct Communication Assets and information Have a question? We’re here to help

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Our Enterprise Ethics and Compliance Committee is a senior leadership committee with members from across the Company who contribute to the development of our culture of integrity and ethics and support a consistent, comprehensive, and proactive approach to the management of compliance trends, issues and risks. The Board of Directors’ Governance Committee is responsible for assisting the board with maintaining strong governance policies and practices at TC Energy and recommends and reports to the board on corporate governance issues, principles and guidelines for review, discussion, approval, or other action by the board. LEADER RESPONSIBILITIES TC Energy’s leaders are here to help us make the right choices and do the right thing together. If you are a leader, in addition to acting in accordance with the principles set out in COBE, you are required to • Inspire Personnel to act ethically by setting an ethical tone within your team • Reinforce the importance of making the right choices and doing the right thing when carrying out corporate objectives (for example, profits and cost management) and support those who are unsure how to make the right choices and do the right thing • Set an example by modeling exemplary ethical business conduct • Create a safe environment where individuals are encouraged to speak up if they become aware of or suspect a legal or ethical violation, and help prevent against retaliation for reporting • Ensure that your team members understand and act in accordance with all legal and ethical requirements that impact them in their jobs, that they know how to report actual or potential non- compliance with the law or COBE or to ask questions regarding ethical or legal matters, and that they complete all required ethics and compliance-related training • Understand your obligation to act on any actual or suspected violations of COBE, any of our other policies, or the law that may be reported to you and the requirement for you to report these issues, as appropriate, to your Compliance Coordinator, Corporate Compliance, Internal Audit, the Harassment Investigation Coordinator, Privacy Office or the Ethics Help Line • Engage with Human Resources, your Compliance Coordinator, Corporate Compliance or Internal Audit to ensure violations of legal requirements, COBE or any of our other policies by your direct reports are addressed appropriately (including appropriate corrective action) For further information, please review the guidance for ethics, compliance and respectful workplace matters in the Leader’s Portal. TC Energy – Code of Business Ethics Policy   9   Home Table of contents Living our values Ethical business conduct Communication Assets and information Have a question? We’re here to help

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SAFETY IN EVERY STEP Protect myself, my teammates, the public and the environment Our commitment to safety isn’t just a mantra – it’s how we work 24/7, 365 days of the year across our entire organization. What started as a foundational value within our safety department decades ago has now come to mean much more to our Company. We ensure that when doing our work we put safety in every step to prevent all harm, loss and incidents. We expect all Personnel to share TC Energy’s commitment to safety. Learning from both achievements and challenges is essential for continuous improvement and growth. By reflecting on successes we can replicate effective safety strategies, and analyzing setbacks allows us to avoid repeating mistakes. Whether you work in a field location or in an office setting, you must always ensure that you comply with all health, safety and environment related legal requirements, as well as the requirements set out by TC Energy in COBE and applicable policies. If it isn’t safe, we won’t do it. By reinforcing a disciplined set of rules and providing rigorous training, we approach everything we do with safety and performance at the forefront. We report all health, safety and environment related hazards, potential hazards, incidents, near hits and unsafe acts. We take every report seriously, investigate to identify facts and ensure immunity from disciplinary action for the Good Faith Reporting of all incidents and issues. QUESTION: I’m working on a big project and it’s very important to the Company that it be completed on-time and on-budget. I’m concerned that I might be injured if I rush my work, but I’m feeling a lot of pressure to do so. What should I do? ANSWER: You should never compromise your or anyone else’s safety. If someone is pressuring you to do so, you should report the issue. TC Energy – Code of Business Ethics Policy   10   Home Table of contents Living our values Ethical business conduct Communication Assets and information Have a question? We’re here to help

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ALCOHOL AND DRUG USE AND BEING FIT FOR WORK We do not compromise our ability to do our jobs or the safety of others through the use of intoxicants, including alcohol, drugs or medications whether they are legal or not. Given the nature of TC Energy’s business, it is essential that all Personnel be fit to perform their jobs. The use of alcohol or drugs can impair your judgment and productivity and can lead to serious accidents and health and safety concerns – not only for yourself, but also for your coworkers and the public. TC Energy takes a zero-tolerance approach toward the use of alcohol, drugs and intoxication while working. You must always be fit for work while engaged in any TC Energy business. Inability to do so will result in serious consequences including being removed from our site(s) and subject to appropriate corrective action, up to and including termination of employment or contract. Ꝓ Alcohol and Drug Policy WHAT DOES BEING FIT FOR WORK MEAN? Fit for work means being able to safely and acceptably perform your assigned duties without any limitations due to the use or after-effects of any intoxicants. This can include legally-obtained medications (prescription and over the counter) which have the potential to change or adversely affect the way a person thinks, feels, or acts. TC Energy – Code of Business Ethics Policy   11   Home Table of contents Living our values Ethical business conduct Communication Assets and information Have a question? We’re here to help

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HUMAN RIGHTS Consistent with Our Commitment Statement, TC Energy does not tolerate human rights abuses. In our business activities, including engaging with Indigenous groups and stakeholders across Canada, the United States and Mexico, we are committed to respecting human rights. We will not be complicit with, nor engage in, any business activity that supports or facilitates abuse of human rights. As a participant in the United Nations (UN) Global Compact, TC Energy supports the Ten Principles of the UN Global Compact on human rights, labour, environment and anti-corruption. We are committed to making the UN Global Compact and its principles part of the strategy, culture and day-to-day operations of our Company, and to engage in collaborative projects which advance the broader development goals of the UN, particularly the Sustainable Development Goals. TC Energy considers the International Bill of Human Rights, which consists of the Universal Declaration of Human Rights, and the core International Labour Organization (ILO) Conventions when adopting human rights best practices. This enables the Company to comply with all applicable international standards, federal, provincial, state, and local laws, rules, regulations, orders, and ordinances, including, without limitation, environmental protection, energy, health and safety, and labor laws and regulations, as well as applicable industry codes and standards. We stand firmly against the use of forced labour, including child labour, prison labour, bonded labour, military labour, modern forms of slavery, human trafficking and any form of physical or mental abuse within our business and operations, including the Contractors we do business with. TC Energy monitors and assesses its Contractors for compliance with human rights requirements, and may terminate business relationships in the event violations are confirmed. In addition to TC Energy complying with applicable legislated compensation standards, such as minimum wage, wage payment, maximum work hours, mandatory holidays, progressive remuneration in case of overtime and benefits laws, we are committed to providing a fair living wage for all Employees. Employment of individuals below the minimum age permitted by local law is strictly prohibited. Respect for human rights is covered in TC Energy’s annual online Code of Business Ethics training and certification, as well as other related training, as required. Additional mandatory online training includes, but is not limited to, the following courses: • Health and Safety Core training • Inclusion and Unconscious Bias training • Respectful Workplace training Ꝓ Our Commitment Statement Ꝓ Indigenous Relations Policy TC Energy – Code of Business Ethics Policy   12   Home Table of contents Living our values Ethical business conduct Communication Assets and information Have a question? We’re here to help

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Ꝓ Equal Employment Opportunity and Non- Discrimination Policy Ꝓ Reasonable Workplace Accommodation Policy Ꝓ Harassment-Free Workplace Policy Canada • U.S. • Mexico TC Energy requires you to be tolerant, inclusive and to demonstrate respect for others. TC Energy requires that we treat one another with dignity and respect, and we are committed to maintaining an inclusive and respectful work environment that is free of harassment and violence. HARASSMENT AND VIOLENCE-FREE WORKPLACE Everyone deserves to do their job in a safe, respectful, and inclusive workplace, without fear of harassment or violence. You must always be respectful to our Employees and Contractors and be sensitive to the way in which others may react to your behaviours, comments, gestures or contacts. Always try to resolve differences in a calm and respectful manner, without resorting to insults, threats or violence. TC Energy prohibits any behaviour, including displaying any statements, messages, or images (e.g., on clothing, stickers on hard hats, decals on vehicles, etc.), that is: • Intimidating • Hostile • Offensive • Threatening • Violent • Demeaning or humiliating • Of a sexual nature • Creating an inappropriate work environment TC Energy will take allegations of harassment and violence seriously and address them promptly in a respectful, fair and thorough manner by trained investigators. If required, TC Energy will take appropriate corrective action, up to and including termination of employment or contract. EMPLOYMENT EQUITY AND EQUAL OPPORTUNITY TC Energy believes that our differences make us stronger and encourages a culture of inclusion and belonging. We prohibit any form of discrimination and provide reasonable accommodation of differences. We expect Personnel to create and reinforce an inclusive, creative and productive work environment in which everyone is accepted and respected. In particular, you must never take actions or make unwanted comments or gestures or discriminate against anyone on the basis of: • Gender • Race • National or ethnic origin • Colour • Disability • Religion • Age • Sexual orientation • Gender identity • Marital status • Family status • Veteran status • National Guard or reserve unit obligations • A criminal conviction • Or any other legally protected grounds TC Energy – Code of Business Ethics Policy   13   Home Table of contents Living our values Ethical business conduct Communication Assets and information Have a question? We’re here to help

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PROTECTING EVERYONE FROM WEAPONS IN THE WORKPLACE We prohibit the possession, use, carrying or transportation of any dangerous or potentially dangerous weapons, as defined by TC Energy’s Weapons in the Workplace Policy, when conducting Company business: • On or off all Company owned or controlled premises • In all Company vehicles (whether owned, leased or rented) • In all personal vehicles being used while conducting Company business For individuals in jurisdictions that permit firearms to be kept in personal vehicles, when in a Company parking lot the vehicle must be locked, firearms must be hidden from plain view and be kept within a locked case or container within the vehicle. Ꝓ Weapons in the Workplace Policy Individuals who are licensed to carry firearms (openly or in a concealed manner) are not exempt from our Policy. TC Energy – Code of Business Ethics Policy   14   Home Table of contents Living our values Ethical business conduct Communication Assets and information Have a question? We’re here to help

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ETHICAL BUSINESS CONDUCT + Avoiding conflicts of interest + Personal Relationships + Gifts, invitations and entertainment + Engaging Government Officials + Political contributions and lobbying + International trade + Insider trading + Complying with regulatory requirements + Inter-affiliate interactions + Competing fairly + Accounting, financial reporting and fraud prevention + Preventing money laundering and terrorist financing TC Energy – Code of Business Ethics Policy   15   Home Table of contents Living our values Communication Assets and information Have a question? We’re here to help Ethical business conduct

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AVOIDING CONFLICTS OF INTEREST We must act in the best interests of TC Energy, avoiding any situation that could place us in a conflict of interest, or create the perception of a conflict of interest. If, and when, a conflict of interest arises, you are required to report the conflict in a timely manner so it can be appropriately investigated and addressed. You should never make or influence business decisions on behalf of TC Energy based on personal relationships, bias or the potential for personal gain. Some examples of conflict of interest can include, but are not limited to: • Gifts, invitations and entertainment • Outside business activities • Corporate opportunities • Directorships or other board positions outside of TC Energy • Director independence • Personal Relationships • Intimate Relationships Ꝓ Conflict of Interest and Integrity Policy Personal accountability is a core value at TC Energy. In simple terms, this means acting with integrity and owning your commitments and outcomes. To act with integrity means we make the right choices and do the right thing – always. This is part of who we are and how we do business, every day. What is a conflict of interest? Conflict of interest means a situation in which Personnel have private interests that could conflict with their ability to act in good faith and the best interests of the Company, or where they may improperly benefit from knowledge acquired at the Company which is not available to the general public. TC Energy – Code of Business Ethics Policy   16   Home Table of contents Living our values Ethical business conduct Communication Assets and information Have a question? We’re here to help

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PERSONAL RELATIONSHIPS Personnel who have a Personal Relationship within the Company must not be in a direct or indirect reporting relationship with each other. In particular, the Company prohibits all Intimate Relationships between individuals in a direct or indirect reporting relationship. If Personnel are not certain whether a Personal Relationship within the Company is permissible, they should immediately discuss their situation with their TC Energy leader HR Business Partners, or HR Governance. Failure to disclose a relationship that could place individuals in a conflict of interest or create the perception of a conflict of interest could be a breach of Company policy. QUESTION: I want to hire someone who I know has a family member already working for TC Energy. Is that allowed? ANSWER: Yes, it is acceptable to hire someone (Employee or CWC) who has family members already working for TC Energy provided that doing so does not result in the person directly or indirectly (through other leader(s)) reporting to their family member. The onus is on all Personnel to notify HR Governance when they become aware of a Personal Relationship where there is a direct or indirect reporting relationship within the Company. TC Energy – Code of Business Ethics Policy   17   Home Table of contents Living our values Ethical business conduct Communication Assets and information Have a question? We’re here to help

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OUTSIDE BUSINESS ACTIVITIES AND OUTSIDE DIRECTORSHIPS Personnel must not engage in outside business activities (e.g., as a consultant, employee, or director) or Advisory Relationships that could conflict with, or be perceived to conflict with, or are detrimental to the interests of TC Energy, and which may include • Owning, controlling or directing a material financial interest (greater than one per cent) in a competitor, or in a vendor, supplier, customer or other business which does or seeks to do business with TC Energy • Advising or being involved in a business that competes with TC Energy or that does or seeks to do business with TC Energy • Outside business activities that interfere with Personnel’s day-to-day responsibilities at TC Energy • An outside business activity that requires Personnel to violate their confidentiality or other obligations to TC Energy TC Energy Personnel who have a Family Relationship with a supplier or potential supplier to the Company must ensure that they are not involved in the selection process or in directing or influencing the work of the supplier to whom they are related. In cases where the spouse, common law partner, or other family member of Personnel owns, controls, or directs a material financial interest in any of the outside business activities, that Personnel must contact the Corporate Compliance department for guidance. Personnel must declare all outside business activities and Advisory Relationships that could conflict with or be perceived to conflict with the interests of TC Energy to the Corporate Compliance department for guidance. Any outside business activities must be conducted outside of TC Energy work hours since your time and attention during TC Energy work hours is expected to be directly related to your employment with TC Energy. Personnel must declare all Outside Directorship positions on a board (e.g., board chair, treasurer, secretary, member, etc.) to Corporate Secretarial for review and approval, prior to accepting the position or upon joining the Company. TC Energy – Code of Business Ethics Policy   18   Home Table of contents Living our values Ethical business conduct Communication Assets and information Have a question? We’re here to help

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OTHER POTENTIAL CONFLICTS OF INTEREST Corporate opportunities Personnel must not take personal advantage of a business opportunity that you discover through the use of Company assets, property, information or your position with TC Energy, or use Company assets, property, information or your position with TC Energy for personal gain or to compete with TC Energy. Political office, appointments to boards or tribunals Personnel may not serve in a political office or on an administrative board or tribunal, if that office, board or tribunal has or may have decision-making authority in respect of any aspect of TC Energy’s business (such as the approval of projects or the issuing of permits). Executive leadership team - other business activities In addition to the conditions set out in the outside business activities and outside directorships section above, prior to serving in any capacity in an unaffiliated organization, the Chief Executive Officer and any member of the Executive Leadership Team must obtain the consent of the Chair of the Governance Committee. Directors’ independence To maintain their independence and to ensure that no relationships exist that may violate applicable corporate, securities and competition laws, all members of the Board of Directors of TC Energy must have their independence assessed: • Annually • In the event of a material change in their respective primary employment status • When they wish to join another board of directors, whether private or public All candidates to TC Energy’s Board of Directors must declare to the Corporate Secretarial group any material interest that they may have in a contract or transaction. All members of the TC Energy Board of Directors who have any material interest in a contract or transaction must recuse themselves from related deliberations and approval. TC Energy – Code of Business Ethics Policy   19   Home Table of contents Living our values Ethical business conduct Communication Assets and information Have a question? We’re here to help

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GIFTS, INVITATIONS AND ENTERTAINMENT Local customs with respect to providing gifts and other benefits can change depending on where we are doing business; however, these local customs must never compromise, or appear to compromise, our ability to act legally, ethically and objectively. While giving gifts can help to build and maintain strong business relationships, they can also cloud one’s judgement or be seen to improperly influence decisions depending on the nature and context of the gift. We must always be prudent in offering gifts, entertainment or anything of value to anyone or any organization that is a competitor, or that TC Energy does or seeks to do business with, or that TC Energy requires consent or approval from (e.g., a government authority). Corruption in business and government prevents fair and open competition based on merit and it can have a negative impact for both the Company and the individual. To mitigate these negative impacts, we must all comply with TC Energy’s Avoiding Bribery and Corruption Policy, Gift, Meals, Entertainment and Travel for Government Officials Standard, and Gifts and Entertainment Policy. TC Energy – Code of Business Ethics Policy   20   Home Table of contents Living our values Ethical business conduct Communication Assets and information Have a question? We’re here to help

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Accepting gifts, invitations and entertainment Accepting gifts or invitations from anyone or any organization can affect the way TC Energy is perceived and can run counter to our business objectives and values. We all have an obligation to conduct ourselves in a fair and impartial fashion in all business dealings with anyone or any organization. Careful consideration must be taken when offered a gift or an invitation to an event. Please see the Gifts and Entertainment Policy for more information. Ꝓ Avoiding Bribery and Corruption Policy Ꝓ Gifts and Entertainment Policy Ꝓ Gift, Meals, Entertainment and Travel for Government Officials Standard QUESTION: I have been invited by a shipper to attend the rodeo at the Calgary Stampede. Can I accept the invitation and attend the event? ANSWER: All Personnel must ensure they are acting in a manner which is fair and impartial and which does not create a real or perceived conflict of interest with those with whom we do business. As such, attendance at this event would only be acceptable if the criteria outlined in the Gifts and Entertainment Policy are met and, for Personnel below Vice-President (VP), prior approval is obtained from your VP or above. QUESTION: I sometimes receive items such as coffee mugs and pens from a company that I have a relationship with and which is a supplier to TC Energy. Am I able to accept these items? ANSWER: Personnel may accept occasional promotional gifts (such as pens, coffee mugs, calendars) as a customary business courtesy, provided that the gift does not exceed a value of CAD $150/ USD $150/ MXN $1000 per instance or total more than CAD $300/ USD $300/ MXN $2000 in aggregate for the calendar year from the same individual or organization. All dollar amounts for occasional promotional gifts are in local currency where they are being accepted. QUESTION: One of our existing auto leasing suppliers has invited me to attend their annual product roll-out, which will be held in Las Vegas. It is a big event that all customers are invited to. The supplier has offered to pay for all flights and accommodation, in addition to the meals that will be provided as part of the event. The supplier’s contract is not currently up for renewal, and I am not the person responsible for making the decision whether to renew. Can I attend? ANSWER: Given the location of the event, the business benefit to TC Energy should be carefully considered and discussed with your leader. Additionally, since the value of the event is significant, the supplier’s payment for flights and accommodation could create a perception of conflict and/or an obligation on the part of TC Energy. As a result, flights and accommodation should be paid for by TC Energy. You may accept the meals provided by the supplier as part of the event, provided they are not lavish in nature. Further, attendance at this event would only be acceptable if the criteria outlined in the Gifts and Entertainment Policy are met and, for Personnel below Vice-President (VP), prior approval is obtained from your VP or above. Home Table of contents Living our values Ethical business conduct Communication Assets and information Have a question? We’re here to help TC Energy – Code of Business Ethics Policy   21  

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ENGAGING GOVERNMENT OFFICIALS Engaging with Government Officials is an important part of TC Energy’s business, and during those engagements, expenses for Government Officials may be incurred. You should never provide Government Officials with bribes, payments, kickbacks, gifts or anything else of value for the purpose of improperly influencing their actions or decisions in TC Energy’s favour. These benefits can include entertainment, private parties, charitable contributions or employment opportunities. Even if there is no intent to influence, you should not provide a payment or benefit to any third party if it could appear to be improper. If a Government Official, Politically Exposed Person, Excluded Contractor, or any other person requests a bribe, kickback, or any other thing of value (including gifts, entertainment, travel, or other hospitality) that would be in violation of our policies, Personnel must refuse the request and make a record of the request as soon as possible. Mark the record as “confidential” and promptly provide it to your leader and Corporate Compliance so appropriate next steps can be determined. We are prohibited from offering, paying, promising or authorizing a compensation, payment or benefit to any Government Official, directly or indirectly, to secure any contract, concession or other improper advantage for TC Energy. Such action is prohibited even if the intent is not to influence a Government Official(s), as it could appear to be improper. Ꝓ Avoiding Bribery and Corruption Policy Ꝓ Gifts and Entertainment Policy Ꝓ Community Investment Standard Ꝓ Gift, Meals, Entertainment and Travel for Government Officials Standard With the exception of Mexico, many anti-corruption laws allow reasonable gifts or entertainment for Government Officials in limited circumstances. Only gifts, meals, and entertainment that are reasonable, do not influence business decisions and are not otherwise prohibited may be offered. All gifts, meals or entertainment must be provided in accordance with local laws and regulations, be appropriately recorded in TC Energy’s books and records, and follow the appropriate approval processes and thresholds as set out in TC Energy’s Gift, Meals, Entertainment and Travel for Government Officials Standard. TC Energy – Code of Business Ethics Policy   22   Home Table of contents Living our values Ethical business conduct Communication Assets and information Have a question? We’re here to help

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POLITICAL CONTRIBUTIONS AND LOBBYING TC Energy respects the political process and only makes political contributions and engages in lobbying activities that are legal and transparent. Legal requirements concerning political contributions and lobbying are aimed at preventing corruption in government and at ensuring proper functioning of the political system. These legal requirements can be complex and vary by jurisdiction. For example we are not allowed to make political donations at all in some jurisdictions. Also, there may be a legal requirement to be registered in some jurisdictions if you meet certain criteria. You must seek approval from the External Relations department before engaging in these activities on behalf of TC Energy. Ꝓ Political Contributions and Activities Policy QUESTION: I am very politically active. Is that allowed? ANSWER: You may participate in the political process on your personal time in accordance with your own political views and the laws and regulations governing this activity. In doing so, however, you may not use TC Energy’s name, nor indicate that you represent TC Energy, unless you have been authorized to do so. Lobbying occurs when Personnel, acting on behalf of the Company, communicate with a Government Official usually in an attempt to influence a government decision, program, or policy. Personnel must report internally to External Relations all interactions and communications with Government Officials that involve any matter of interest to the Company using the appropriate channels outlined in the Political Contributions and Activities Policy. TC Energy – Code of Business Ethics Policy   23   Home Table of contents Living our values Ethical business conduct Communication Assets and information Have a question? We’re here to help

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INTERNATIONAL TRADE When engaging in international business and procuring products from the global marketplace, TC Energy complies with all applicable international trade laws, as well as all customs and taxation requirements. International trade laws prohibit or restrict trade with certain countries that are subject to embargoes or sanctions, as well as with certain individuals and organizations (e.g., entities that have ties to actual or suspected terrorists or drug traffickers). These laws also prohibit or restrict imports and exports of certain types of goods, information and technologies and often impose stringent reporting obligations. As part of contractual arrangements, mergers and acquisitions, debt covenants, and know-your-client requirements, TC Energy may need to make representations regarding compliance with sanctions and confirm that its Personnel are not sanctioned persons. A sanctioned person refers to an individual or entity that is sanctioned under the sanctions laws of, but not limited to, Canada, the U.S., Japan, the UK, or the EU. If at any time you become a sanctioned person, you are required to report this to Corporate Compliance. Ꝓ Customs and Trade Policy Prior to engaging in any transaction, you must ensure: • that it is legally permitted • that all applicable licensing requirements and reporting and customs obligations are met And consider: • the types and use of the goods, information or technology • the counterparty with which you are dealing • the country in which the counterparty is located Even if TC Energy does not have ownership of a product we have purchased when it crosses a border (e.g., because we take ownership or title on delivery), we may nevertheless be responsible for import and/or export compliance based on certain terms of the purchase contract. It is important to ensure the contract does not contain terms that result in TC Energy inadvertently taking on these obligations. TC Energy – Code of Business Ethics Policy   24   Home Table of contents Living our values Ethical business conduct Communication Assets and information Have a question? We’re here to help

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INSIDER TRADING We engage only in transactions that have a legitimate business purpose, and we do not interfere with the normal functioning of the markets in which we operate and transact. We also report transactions in accordance with all legal requirements. Through the course of your work with TC Energy, you may have access to non-public information regarding TC Energy, our customers, Contractors and other business partners. You must always maintain the confidentiality of any non-public information encountered through the course of business with TC Energy. To the extent non-public information that you are aware of could be material to a decision to buy or sell shares in TC Energy or another company: • You and your immediate family members must not trade TC Energy shares or other securities based on that information • You must not share material non-public information with another person, except as necessary in the course of business, as outlined in the Public Disclosure Policy. Ꝓ Trading Policy Ꝓ Public Disclosure Policy QUESTION: I own units of a mutual fund that invests in shares of one of our suppliers. Is that a problem? ANSWER: Your ownership of mutual fund units is likely not a problem. If your investment in the supplier is through a mutual fund, you would need to ensure that you do not own more than one per cent of the stock of the supplier; however, because of the indirect nature of the investment, it is also less of a concern than if you owned the shares directly. We conduct business in a way that promotes a fair, efficient and openly competitive operation of markets we participate in and which complies with market manipulation laws. Insider trading is a serious offence and can have significant reputational and legal impacts. For Securities and Insider trading inquiries contact Corporate Secretarial Filing Desk. TC Energy – Code of Business Ethics Policy   25   Home Table of contents Living our values Ethical business conduct Communication Assets and information Have a question? We’re here to help

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COMPLYING WITH REGULATORY REQUIREMENTS TC Energy is committed to meeting our obligations under all regulations and tariffs. As a regulated Company, TC Energy is subject to many regulatory requirements, including those of the Canada Energy Regulator (CER), the Federal Energy Regulatory Commission (FERC), the North American Energy Reliability Corporation (NERC), and the Comisión Nacional de Hidrocarburos, among others. In addition, TC Energy’s transmission providers are subject to tariffs that we must comply with. Although it is impossible to list all of these requirements here, you must ensure you are familiar with the specific requirements applicable to you in your job. These can include reporting requirements and compliance with technical or other standards. To the extent the requirements of more than one jurisdiction apply, you must comply with the highest of the various standards. TC Energy – Code of Business Ethics Policy   26   Home Table of contents Living our values Ethical business conduct Communication Assets and information Have a question? We’re here to help

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INTER-AFFILIATE INTERACTIONS As a transmission provider, TC Energy is subject to the Canadian Gas Pipelines Code of Conduct (Code) in Canada, the FERC Standards of Conduct (SOC) in the U.S., and the TC Energía Code of Conduct in Mexico (Inter-Affiliate Codes). These Inter-Affiliate Codes are intended to ensure that our non-regulated affiliates do not receive an unfair advantage over other customers, whether as a result of discriminatory treatment or the improper sharing of information, Personnel or resources. The Inter-Affiliate Codes also prohibit cross-subsidization at the expense of our transmission customers. In order to ensure compliance with the Inter-Affiliate Codes, you must observe the following rules in your day-to-day activities: All customers must be treated equally Regulated transmission providers cannot give undue preference to any customer, whether affiliated with a TC Energy entity or not. Independent functioning Regulated Personnel and affiliates must function independently of non-regulated Personnel and affiliates (e.g., they must function without coordination or the sharing of non-public Regulated Information*). No conduit of information Regulated and shared Personnel must not share, or act as a conduit for the sharing of Regulated Information with non-regulated Personnel (e.g., by way of SharePoint links, Power Apps, Power Bi reports, data rooms, meetings etc.). Pay fair share Non-regulated affiliates must pay their fair share of any costs incurred by our regulated transmission providers, so as not to burden our transmission customers with costs our non-regulated entities benefit from. Reporting violations Any violations of the Inter-Affiliate Codes must be reported to the Inter-Affiliate Compliance department, since TC Energy may be legally required to either publicly post such information on its website or report it to our regulators. *Regulated Information (which may not be shared with non-regulated Personnel or affiliates) includes commercial, financial, strategic, planning, operational and customer information of our transmission providers. Ꝓ TC Energy’s Inter-Affiliate Codes TC Energy – Code of Business Ethics Policy   27   Home Table of contents Living our values Ethical business conduct Communication Assets and information Have a question? We’re here to help

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COMPETING FAIRLY A competitive marketplace in the energy and transmission services that TC Energy provides helps ensure fair prices and customer choice and, in turn, results in the industry as a whole providing more effective and better service. We believe in vigorous, fair competition and comply with all laws designed to protect the ability of companies to compete freely. You should never enter into agreements to: • Fix prices • Decrease capacity or volume available to customers • Allocate customers or markets among competitors • Boycott certain customers or Contractors You need to be very careful whenever you have contact with competitors (whether in trade association meetings, at conferences, through participation in benchmarking groups or in negotiating or otherwise dealing with actual or potential joint venture partners who are also TC Energy competitors) to avoid sharing competitively sensitive information. You must never enter into an agreement to reduce competition, or that is likely to have that effect. QUESTION: While at a trade association meeting recently, a few competitors I was sitting with at dinner started talking about their pricing. I knew it wasn’t appropriate, so I didn’t say anything. Did I do the right thing? ANSWER: While you were right not to participate in the discussion, when in such a situation, it’s a good idea to take the further step of making clear to everyone that the discussion is inappropriate and that you will not participate. If the inappropriate discussion continues, you should excuse yourself from the situation. You should also document what happened and report the matter. This will help to protect you and TC Energy in case anyone ever points to the fact that you were part of a group in which an inappropriate discussion took place. Employees must seek approval from the External Relations department before making any corporate membership payments to trade associations. TC Energy – Code of Business Ethics Policy   28   Home Table of contents Living our values Ethical business conduct Communication Assets and information Have a question? We’re here to help

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ACCOUNTING, FINANCIAL REPORTING AND FRAUD PREVENTION TC Energy ensures that our accounting, financial records and reporting are fair, accurate, understandable and complete, and we do not falsify financial documents or records, or misstate or misrepresent the nature of costs or expenditures. You must ensure all transactions that you engage in, or that you approve, whether under a TC Energy contract or as an individual business expense, are true and reported accurately, completely and in compliance with all applicable accounting and legal requirements. You must also follow TC Energy’s corporate policies and other requirements respecting the transaction (for example, obtaining of approvals). You must never engage in “off-the-record” or other transactions or accounts that do not fully and accurately state the nature and amount of specific transactions. You must also never falsify any invoice, expenditure, time sheet, benefits claim or other document related to the Company, our stakeholders, Contractors or benefits providers. Doing so constitutes fraud and may result in appropriate corrective action, up to and including termination of employment or contract. Ꝓ Avoiding Bribery and Corruption Policy Ꝓ Procurement Policy Ꝓ Business Expense Policy TC Energy’s Procurement Policy and Business Expense Policy TC Energy’s Procurement Policy provides a governing framework for all acquisitions, mandating legal, governance and safety compliance for all Personnel involved in procurement. The Business Expense Policy governs proper management of low-cost, low-risk business expenses, including expectations for corporate credit card use. This Policy prohibits splitting transactions to bypass limits and requires the most senior-level Employee present to incur expenses with multiple Employees from the same unit. Home Table of contents Living our values Ethical business conduct Communication Assets and information Have a question? We’re here to help TC Energy – Code of Business Ethics Policy   29  

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PREVENTING MONEY LAUNDERING AND TERRORIST FINANCING We expect all our Personnel to be vigilant in ensuring the payments we make and the methods of payment we use are legitimate and legal. Legal requirements concerning money laundering and terrorist financing are in place to deter criminal and terrorist activities of those with whom we might do business. To ensure compliance with these legal requirements you must: • Exercise care before agreeing to do business with a third-party, including ensuring that they were reviewed as part of Supply Chain’s qualification process • Ensure the third-party is legitimate and reputable • Recognize and report any suspicious payments or transactions Ignoring the signs that a transaction or payment initiated by a third party is not legitimate can result in TC Energy being found complicit in any illegal activity that may be associated with the transaction, even if the Company did not expressly authorize it or even know about it. Examples of suspicious payments or transactions include: • Any request by a third-party to have a payment deposited into a personal account rather than a business account • Transactions with entities other than those involved in the underlying contract or business deal • Payments or other transactions involving a country other than that in which the parties to the contract or business deal are located Payments of cash, unusual financing arrangements, fictitious invoices or other efforts by a third party to conceal the true purpose of a payment or transaction also raise concerns. TC Energy – Code of Business Ethics Policy   30   Home Table of contents Living our values Ethical business conduct Communication Assets and information Have a question? We’re here to help

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COMMUNICATION + Being socially responsible + Being a good ambassador of TC Energy + Social media and communication with the public + Public disclosure of information + Dealing fairly with customers, Contractors and other stakeholders + Dealing fairly with competitors TC Energy – Code of Business Ethics Policy   31   Home Table of contents Living our values Ethical business conduct Assets and information Have a question? We’re here to help Communication

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BEING SOCIALLY RESPONSIBLE TC Energy cultivates and continually strengthens our relationships with Indigenous and local communities, rightsholders, landowners and other stakeholders across our asset base. We are committed to being a good neighbour and supporting and enhancing the communities in which we live and work. We are committed to learning from and collaborating with Indigenous communities. We strive to build support for our operations and projects through early, honest and continuous communication, meeting or exceeding requirements while prioritizing respectful engagement and building partnerships. We are committed to working with Indigenous communities to develop positive, long-term relationships based on mutual trust and respect. We recognize their diversity, unique relationship with the land and importance they place on maintaining their cultures and traditional ways of life. In addition, we work hard to build and maintain relationships with landowners and local communities. We focus on keeping landowners informed and involved through all phases of a project. We recognize the importance of farming to their communities and actively support farming related organizations. Through these efforts, we comply with legal and regulatory requirements. Further, we set up our teams for successful, honest and long-lasting relationships with our landowners, grounded in transparency, fairness and accountability. Ꝓ Our Commitment Statement Ꝓ Indigenous Relations Policy TC Energy understands the importance that community, charitable and similar non-governmental organizations play in making the communities in which we live and work better places. We actively support these organizations and encourage our Personnel to become involved by volunteering and contributing to charitable and other community-based organizations, including during work hours if approved by your leader. TC Energy – Code of Business Ethics Policy   32   Home Table of contents Living our values Ethical business conduct Communication Assets and information Have a question? We’re here to help

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BEING A GOOD AMBASSADOR OF TC ENERGY We recognize that we are ambassadors of TC Energy and conduct ourselves in a manner that is respectful and appropriate, and will not harm TC Energy’s reputation. You must always keep in mind that you are a representative of TC Energy. The things you say and do should reflect the Company’s core values. You should not speak publicly on behalf of TC Energy unless authorized to do so by the Communications team. Any posting or statement on an external website, including personal sites, social media channels or in other media, should be considered a public statement. Even on personal time, you must not participate in any illegal or inappropriate statements or activities that could be detrimental to the Company or its reputation. Personnel are encouraged to engage with social media content from official TC Energy accounts through actions such as liking and sharing. Ꝓ Public Disclosure Policy Ꝓ Communications Policy TC Energy – Code of Business Ethics Policy   33   Home Table of contents Living our values Ethical business conduct Communication Assets and information Have a question? We’re here to help

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SOCIAL MEDIA AND COMMUNICATIONS WITH THE PUBLIC In the age of social media, it is easy to communicate information broadly and publicly. You need to be particularly aware of your obligations and our expectations when it comes to the disclosure of Company information and ensuring it is in accordance with legal and internal requirements. When sharing information on social media, keep the following requirements in mind: • Do not speak on behalf of or give the impression that you are speaking on behalf of TC Energy, unless you have been authorized to do so • Be clear that your comments represent your opinion and are not written on behalf of TC Energy • Use good judgement and ensure you do not post anything that reflects negatively on TC Energy or yourself, or that is discriminatory, offensive, or in poor taste • Be respectful of others, keeping in mind our Harassment-Free Workplace policies and make sure your comments cannot be seen in a negative light • Share only approved TC Energy content to ensure you are accurate and add value to the conversation • Do not disclose confidential, proprietary, or non-public information about TC Energy • Do not post pictures of TC Energy’s facilities or operations unless you are authorized to do so and have received the required approvals • Never falsely represent yourself QUESTION: While scrolling through social media I saw anti LNG posts that my extended family were making. I wanted to comment on the post with some facts regarding the use of LNG in our everyday lives, but I didn’t want to fuel the fire. Did I do the right thing? ANSWER: Yes, you did the right thing by not participating in the online discussion. Engaging with individuals who have opposing opinions or values to yourself or to the Company can increase hostility, and social media algorithms may also bring more attention to the conflict rather than the facts. . TC Energy recognizes that Personnel use social media for personal use. Personal use of social media must not interfere with your job. Personnel should be mindful that personal use of social media can also impact TC Energy, its business relationships, and reputation in the communities it serves. TC Energy – Code of Business Ethics Policy   34   Home Table of contents Living our values Ethical business conduct Communication Assets and information Have a question? We’re here to help

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PUBLIC DISCLOSURE OF INFORMATION TC Energy ensures that public statements regarding the Company are provided in a timely manner, are fair, accurate and complete, comply with legal requirements and corporate policies, and preserve and protect our reputation and brand. TC Energy has prescribed Personnel who are authorized to speak on our behalf. If you receive an inquiry for information or comment, please direct the inquiry to our media line 1-800-608-7859, or by email. Our Communications team will direct it to the appropriate Company representative for response. Ꝓ Public Disclosure Policy Ꝓ Communications Policy Use of Company name for personal gain You must never use the Company’s name or purchasing power or your employment status to obtain personal discounts or rebates from Contractors unless those discounts or rebates are available to all Employees. TC Energy – Code of Business Ethics Policy   35   Home Table of contents Living our values Ethical business conduct Communication Assets and information Have a question? We’re here to help

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DEALING FAIRLY WITH CUSTOMERS, CONTRACTORS AND OTHER STAKEHOLDERS We consider the impact of our actions on stakeholders, rightsholders, the environment and the communities in which we operate. We follow the requirements of our policies, procedures and commitment statements to make sure we act responsibly to protect us, our co-workers, our workplace and assets and the communities we work in. We act as responsible stewards of the environment and manage risk, share knowledge and best practices to ensure continual improvement. You should never make business decisions on behalf of TC Energy based on personal relationships, unfair bias or the potential for personal gain. We are fair and honest in our dealings with customers, Contractors and other stakeholders and we honour our obligations and commitments to them. Treating customers, Contractors and other stakeholders fairly requires that you: • Enter into business relationships based on merit • Use objective criteria to evaluate them, such as: – Price – Quality – Service It also requires that you are honest and forthright when dealing with others (never omitting important facts, manipulating another person or situation, or misrepresenting yourself or TC Energy), and that you honour TC Energy’s contractual, regulatory and other commitments. TC Energy – Code of Business Ethics Policy   36   Home Table of contents Living our values Ethical business conduct Communication Assets and information Have a question? We’re here to help

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DEALING FAIRLY WITH COMPETITORS You must ensure that you use only legitimate means (such as searches of public information) to obtain competitive intelligence. You must never use deceit or misrepresent yourself to obtain such information, and you should never take advantage of information you receive in error, for example: • Emails or faxes received in error • Physical documents left in a meeting room or in a public place or which have been sent to you in error • Information you overheard TC Energy – Code of Business Ethics Policy   37   Home Table of contents Living our values Ethical business conduct Communication Assets and information Have a question? We’re here to help

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ASSETS AND INFORMATION + Protecting confidential information + Protecting personal information + Managing and maintaining the security of information + Protecting and respecting intellectual property rights + Use and protection of TC Energy assets TC Energy – Code of Business Ethics Policy   38   Home Table of contents Living our values Ethical business conduct Communication Have a question? We’re here to help Assets and information

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PROTECTING CONFIDENTIAL INFORMATION We protect TC Energy’s confidential information, and that of our customers, Contractors and other stakeholders, from improper disclosure and use. We all have access to confidential information. TC Energy confidential information includes all non-public Company information because it may be of use to competitors or harmful to TC Energy or its customers, Contractors or other stakeholders, if disclosed. Confidential information about TC Energy’s projects and operations, such as project delays, costs or outage timing and the resulting system capacity impacts can influence the decisions of participants in the gas market. Such information must be disclosed to all customers and other gas market participants at the same time through our typical communication protocols, such as a bulletin. Because such information is commercially sensitive and can be used by competitors or others to TC Energy’s detriment, it must be protected. You must not disclose such information to anyone who does not need to know the information for legitimate business purposes (including within TC Energy or to a future or potential employer). All confidential information should be protected from unauthorized access. When disposing of confidential information, you should do so in a secure manner, which may include shredding of hard copies. See additional information in the Managing and Maintaining the Security of Information and the Use and Protection of TC Energy’s Assets sections. GENERATIVE ARTIFICIAL INTELLIGENCE (AI) The use of generative AI presents many opportunities, but its misuse can also present potential threats to confidential information. To further protect confidential information, Personnel must never create, transmit or store non-public Company information on non-TC Energy accounts and must use only Company-approved generative AI software on TC Energy computer systems. Confidential information can include: • Marketing information and field notes • Sketches and photographs • Electronic information assets (including emails, voicemails, and text messages) • Computer records or software, specifications, models • Other information which is or may be either applicable to or related in any way to the assets, business or affairs of TC Energy • Information regarding TC Energy’s business, operations, finances, strategies, business plans, or projects • Proposed mergers, acquisitions and divestitures • Engineering designs and reports • Legal proceedings, contracts • Environmental report TC Energy – Code of Business Ethics Policy   39   Home Table of contents Living our values Ethical business conduct Communication Assets and information Have a question? We’re here to help

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PROTECTING PERSONAL INFORMATION TC Energy takes seriously the fact that its Employees, Contractors, customers and other stakeholders have entrusted the Company with their personal information. Personal information is any information that on its own or when combined with other information, can be used to identify an individual. Personal information may include, but is not limited to, name, contact information, date of birth, demographics, biometrics, employment history, performance appraisals, training records, Employee or national identification numbers, health or medical records, and banking information. Use of personal information must be limited to the business purposes for which the information was provided. To the extent that you collect, store, access, or use personal information of any individual as a result of your work with TC Energy, you may not disclose that personal information to others, or use it for a purpose other than that for which it was collected, without the express approval of TC Energy’s Privacy Office or the individual’s written consent. You should never collect, store, access, use, or disclose personal information for an inappropriate purpose or by inappropriate or illegal means. If you are ever unsure if information can be disclosed or used for a new purpose, check with TC Energy’s Privacy Office before taking any action. For more information, please see the Protection of Personal Information Policy. Ꝓ Protection of Personal Information Policy TC Energy is committed to protecting personal information in compliance with all legal requirements and requires that our Personnel share this commitment to information security. You should protect and safeguard personal information from inappropriate access by applying physical, administrative, and technological safeguards (e.g., keeping physical records in a locked cabinet, and keeping electronic records in a password protected or otherwise restricted folder). TC Energy – Code of Business Ethics Policy   40   Home Table of contents Living our values Ethical business conduct Communication Assets and information Have a question? We’re here to help

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MANAGING AND MAINTAINING THE SECURITY OF INFORMATION Company records are valuable assets of TC Energy and you must ensure appropriate and reasonable efforts are made to manage, protect and preserve these assets. All of these information assets are important Company records that TC Energy may be required to produce in the event of a legal or regulatory proceeding, audit or investigation. It is important that you manage and retain these assets in accordance with all legal requirements and TC Energy’s corporate policies. In particular, you must never destroy an information asset in the event of a legal hold or an actual or pending legal or regulatory proceeding. Ꝓ Information Management Policy Ꝓ Cybersecurity Policy Ꝓ Records Retention Schedule What are information assets? • Memos • Emails • Accounting records • Invoices and contracts • Technical drawings • Recordings of trade-related phone calls • Records of safety or other incidents • Marketing literature • Other similar types of records What form can an information asset take? An information asset can take any form or on any media, including: • Paper • Digital files • Voice or video recordings • Text and instant messages • Other electronic formats TC Energy – Code of Business Ethics Policy   41   Home Table of contents Living our values Ethical business conduct Communication Assets and information Have a question? We’re here to help

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PROTECTING AND RESPECTING INTELLECTUAL PROPERTY RIGHTS We preserve TC Energy’s intellectual property rights and respect and honour those of third parties. Intellectual property can include trade secrets, which is any information that gives the owner an economic advantage over its competitors and that the owner takes reasonable steps to keep confidential, as well as copyrights, trademarks and patents, and also includes inventions, innovations, discoveries and copyrighted material developed while employed by TC Energy. We must take steps to protect intellectual property rights. This includes keeping trade secrets confidential, consistently using TC Energy’s trademarks solely as authorized, and respecting the intellectual property rights of third parties. TC Energy respects and honours intellectual property rights by: • Complying with the terms of license agreements that TC Energy has entered into with Contractors • Complying with copyright legislation • Not using improper means to obtain third-party information or trade secrets • Using confidential third-party information only for the purpose for which it was provided TC Energy – Code of Business Ethics Policy   42   Home Table of contents Living our values Ethical business conduct Communication Assets and information Have a question? We’re here to help

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USE AND PROTECTION OF TC ENERGY’S ASSETS TC Energy assets that you have access to for the completion of your duties must be protected and only used for legitimate business purposes. You have an obligation to be a good steward of the assets that TC Energy provides to you in the course of your work and you must protect these assets from loss, theft, damage and misuse. Additionally, using Company facilities, equipment and/or Company time to work on your personal assets, for personal activities or to store personal assets is not allowed. Limited personal use of Company assets such as accessing Internet or printing is acceptable provided that it does not interfere with your job duties. TC Energy regularly monitors Company internet use, and individuals should not assume any right of privacy with respect to either their use of or data stored on TC Energy’s computer systems. Any misuse of Company assets or services, including inappropriate use of TC Energy’s computer equipment and systems, may lead to serious consequences including appropriate corrective action up to and including termination of employment or contract. Ꝓ Acceptable Use Policy Ꝓ Corporate Security Policy QUESTION: I sometimes use my Company computer to access Facebook during my lunch break and I post about my personal life. Is that allowed? ANSWER: Limited personal use of Company assets to access social media during a break is acceptable; however, you need to keep in mind that you are using a Company computer and accessing the Internet through a TC Energy IP address. You must ensure that you do not post content that is inappropriate or could reflect poorly on TC Energy. The Company regularly monitors the use of its equipment and systems and you should not expect your personal use of TC Energy assets to be private. Any inappropriate or offensive use of Company assets by Personnel may result in disciplinary action. What are Company assets? Company assets can include: • Company time • Equipment • Facilities • Furniture • Computers • Telephones • Supplies • Tools • Personal protective equipment • Corporate credit cards • Other resources What can Company assets NOT be used for? Company assets must not be used for: • Engaging in hate-based activities • Downloading illegal material • Viewing pornography • Other inappropriate uses Home Table of contents Living our values Ethical business conduct Communication Assets and information Have a question? We’re here to help TC Energy – Code of Business Ethics Policy   43  

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QUESTION: I send my claims to TC Energy benefits providers and use my TC Energy address to receive trade publications, contact lenses and books for the book club that I started with my coworkers. Is that allowed? ANSWER: Personal shipments and mail must not be sent to your TC Energy address. Personal shipments include: • Personal online purchases, such as electronics, clothing, footwear, hygiene/beauty products, food, contact lenses/glasses, book of the month/wine of the month or any other shipments for interest group meetings, including those created by and for Personnel • Personal magazine and newspaper subscriptions, except for business correspondence, trade publications and vendor catalogues • Gifts from friends and family, except for flower deliveries and gifts from Contractors which must comply with all applicable TC Energy corporate policies As an exception to this rule, Personnel may send their claims to TC Energy benefits providers (e.g., Manulife and MetLife) or send personal mail with the appropriate postage affixed through Company mailrooms. QUESTION: I live in a very small condominium and keep my bike chained to an outside bike rack except for winters, when I store it in a paid facility. My co-worker told me about an empty shed in one of the Company’s sites near my condo. Would it be acceptable for me to keep my bike in the Company’s shed for winter? ANSWER: Storing your bike in the Company’s shed for the winter is not acceptable. Storing personal property that is not required during work hours, such as motorized and nonmotorized vehicles, including but not limited to bicycles, motorcycles, RVs and boats, on the Company premises is generally prohibited. There are two exceptions: • Subject to the site management’s approval, Personnel who commute to remote worksites to perform their job duties may park their personal vehicle used to reach the site on the Company premises for the duration of their work shift • Parking spaces on the Company premises that are either designated or paid for by Personnel may be used to park a personal vehicle, subject to notices to vacate the parking space for seasonal cleaning, maintenance or repairs TC Energy – Code of Business Ethics Policy   44   Home Table of contents Living our values Ethical business conduct Communication Assets and information Have a question? We’re here to help

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HAVE A QUESTION? WE’RE HERE TO HELP + Your responsibility and non-retaliation + Asking questions and reporting concerns TC Energy – Code of Business Ethics Policy   45   Home Table of contents Living our values Ethical business conduct Communication Assets and information Have a question? We’re here to help

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YOUR RESPONSIBILITY Personnel must follow all applicable provisions and the spirit and intent of this corporate governance document and support others in doing so. Personnel must promptly report any suspected or actual violation of this corporate governance document through available channels so that TC Energy can investigate and address it appropriately. Personnel who violate this corporate governance document or knowingly permit others under their supervision to violate it, may be subject to appropriate corrective action, up to and including termination of employment or contract, as applicable, in accordance with the Company’s corporate governance documents, employment practices, contracts, collective bargaining agreements and processes. INTERPRETATION AND ADMINISTRATION The Company has sole discretion to interpret, administer and apply this corporate governance document and to change it at any time to address new or changed legal requirements or business circumstances. NON-RETALIATION TC Energy supports and encourages Employees and Contractors to report suspected violations of corporate governance documents, applicable laws, regulations, and authorizations, as well as hazards, potential hazards, incidents involving health and safety or the environment, and near hits. Such reports can be made through available channels. TC Energy takes every report seriously and investigates it to identify facts and, when warranted, makes improvements to our corporate governance documents and practices. All Employees and Contractors making reports in good faith will be protected from retaliation, and all Employees and Contractors must report if they or someone they know is being or has been retaliated against for reporting. Good Faith Reporting will not protect Employees and Contractors who make intentionally false or malicious reports, or who seek to exempt their own negligence or willful misconduct by the act of making a report. TC Energy – Code of Business Ethics Policy   46   Home Table of contents Living our values Ethical business conduct Communication Assets and information Have a question? We’re here to help

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ASKING QUESTIONS AND REPORTING CONCERNS You are required to report in a timely manner any actual or potential non-compliance with COBE, any other TC Energy policies, or any legal obligation, as it applies to you or the Company, so it can be appropriately investigated and addressed. You can do so with confidence that your confidentiality and identity will be protected to the greatest extent possible and that retaliation for good faith reporting is prohibited. ETHICS HELP LINE Although TC Energy has various reporting resources available for Personnel to report a concern or to seek guidance, there may be times when you are not comfortable raising concerns through those resources. TC Energy’s Ethics Help Line is operated by an independent third-party service provider and reporting through the Ethics Help Line is confidential and may be done anonymously. ETHICS HELP LINE Canada / U.S.: 1-888-920-2042 Mexico: 800-283-2783 (if calling from a cell phone) 0-800-283-2783 (if calling from a land line) TCEnergy.com/about/governance/code-of-business-ethics All calls to the Ethics Help Line are free of charge, and can be made in English, French, or Spanish 24 hours a day, seven days a week, 365 days a year. You may use the Ethics Help Line either to report any actual or suspected issues or to ask questions on topics such as: • Accounting irregularities • Alcohol and drug abuse • Conflicts of interest • Employee concerns • Employment practices • Engineering concerns • Environment concerns • Equitable treatment • Harassment • Human rights • Safety • Theft and fraud • Workplace violence • Other improprieties If the issue raises an immediate threat to safety or security, you should contact Corporate Security, local police or other emergency services as appropriate. All reports are taken seriously Regardless of the means used to report, your report will be taken seriously and it will be investigated and addressed appropriately. If you are reporting through the Ethics Help Line, please make note of your key code for your case file since the investigator may contact you through your case file for further information or clarification prior to initiating an investigation. Participation in investigations and audits Personnel, including directors and officers are required to participate in investigations and audits if, and as, requested. QUESTION: I suspect one of my colleagues has violated part of COBE, but I’m not sure my suspicions are correct. I’m concerned I’ll be labeled a tattle-tale (or worse) if I report it. What should I do? ANSWER: If you suspect misconduct, you should report it in a timely manner so it can be investigated. If it turns out not to be an issue, there will be no harm done. However, violations of the law or COBE that are not reported, cannot be addressed, and that can seriously undermine the Company. If that happens, we all suffer. If you report the issue, your confidentiality and identity will be protected and if any retaliation is found to occur, it will be taken very seriously. Home Table of contents Living our values Ethical business conduct Communication Assets and information Have a question? We’re here to help TC Energy – Code of Business Ethics Policy   47  

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GLOSSARY Advisory Relationship means a relationship where one provides advice, counsel, suggestions, recommendations, intelligence, guidance or any other similar types of information or opinion. Contingent Workforce Contractor (CWC) means an individual who: • is employed by a third party to work on behalf of TC Energy; • uses TC Energy’s assets (e.g., workstation, email, phone) and corporate services; • is compensated on an hourly or daily rate basis; and • works under the direction of a TC Energy leader. Contractor means a third party hired by TC Energy to perform services for or supply equipment, materials, or goods to the Company. Contractors include, without limitation, Contingent Workforce Contractors and Excluded Contractors. Employee means full-time, part-time, temporary and student employees of TC Energy. Excluded Contractor means a third party or individual employed by a third party who: • delivers services, equipment, materials, or goods to the Company using their own tools and assets (e.g., work station, laptop, email, phone, PPE, vehicle); • does not increase TC Energy corporate headcount and overhead costs; • does not use TC Energy’s assets and corporate services; and • directs their own work or receives direction from their employer. Family Relationship means relatedness or connection by blood, marriage or adoption and includes, but is not limited to: • a marriage/common law spouse; • parent and grandparent; • child and grandchild; • sibling; • aunt and uncle; • niece and nephew; • first cousin; and • any “step”, “common law”, or “in law” variations of the above relationships. Good Faith Reporting means an open, honest, fair and reasonable reporting without malice or ulterior motive. Government Officials means any appointed, elected, or honorary official or any employee of a government, of a government owned or controlled company, or of a public or international organization. This definition encompasses officials in all branches and at all levels of government: federal, state/provincial or local. This definition also includes political parties and party officials and candidates for political office. Indigenous officials may also be considered Government Officials. A person does not cease to be a Government Official by claiming to act in a private capacity or by the fact that he/she serves without compensation. Examples of Government Officials relevant to TC Energy’s business include: • government ministers and their staff; • members of legislative bodies or other elected officials; • officials or employees of government departments; • employees of regulatory agencies; • judges and judicial officials; • employees of government-owned or controlled corporations; • customs, immigration, tax, and police personnel; and • employees of public international organizations, such as the United Nations or World Bank. Intimate Relationship means any romantic and/or dating and/or sexual relationship, including casual encounters. Personal Relationship means all Family Relationships and Intimate Relationships and any other personal relationship that is sufficiently close to create a real or perceived conflict of interest. Personnel means full-time, part-time and temporary Employees and Contingent Workforce Contractors of TC Energy. Politically Exposed Person means anyone who recently served as a Government Official or individuals who have a close friendship or Family Relationship with a Government Official. TC Energy or the Company means TC Energy Corporation and its wholly-owned subsidiaries and/or operated entities. TC Energy – Code of Business Ethics Policy   48   Home Living our values Ethical business conduct Communication Assets and information Have a question? We’re here to help Table of contents

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July 2025 MAKING THE RIGHT CHOICES – DOING THE RIGHT THING

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