November 5, 2025

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 three and nine months ended September 30, 2025 and should be read with the accompanying unaudited Condensed consolidated financial statements for the three and nine months ended September 30, 2025, which have been prepared in accordance with U.S. GAAP.

This MD&A should also be read in conjunction with our December 31, 2024 audited Consolidated financial statements and notes and the MD&A in our 2024 Annual Report. Capitalized and abbreviated terms that are used but not otherwise defined herein are defined in our 2024 Annual Report. Certain comparative figures have been adjusted to reflect the current period's presentation.

On October 1, 2024, TC Energy completed the spinoff of its Liquids Pipelines business into a new public company, South Bow Corporation (the Spinoff Transaction). Upon completion of the Spinoff Transaction, the Liquids Pipelines business was accounted for as a discontinued operation. Discussions throughout this MD&A are based on continuing operations unless otherwise noted. Prior year results have been recast to reflect the split between continuing and discontinued operations. Refer to our 2024 Annual Report and the Discontinued operations section for additional 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 interim 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.

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

•realization of expected impacts from acquisitions and divestitures, including the Spinoff Transaction

•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.

•realization of expected impacts from acquisitions and divestitures, including the Spinoff Transaction

•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, including the MD&A in our 2024 Annual Report.

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.

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).

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 the Non-GAAP measures section for additional information, as well as each business segment, the Financial condition and Discontinued operations sections for reconciliations to the most directly comparable GAAP measures.

Discussions throughout this MD&A are based on continuing operations unless otherwise noted. Prior year results have been recast to reflect the split between continuing and discontinued operations.

1Prior year results have been recast to reflect the split between continuing and discontinued operations.

2Additional information on the most directly comparable GAAP measure can be found in the Non-GAAP measures section.

3Reflects dividends declared following the Spinoff Transaction.

1Includes continuing and discontinued operations.

2Additional information on the most directly comparable GAAP measure can be found in the Non-GAAP measures section.

3Includes Liquids Pipelines earnings for the three and nine months ended September 30, 2024 compared to Liquids Pipelines earnings of nil for the same periods in 2025. Refer to the Discontinued operations section and our 2024 Annual Report for additional information.

4Capital spending reflects cash flows associated with our Capital expenditures, Capital projects in development and Contributions to equity investments. Refer to Note 4, Segmented information, of our Condensed consolidated financial statements for additional information.

5Included in the Financing activities section of the Condensed consolidated statement of cash flows.

1Prior year results have been recast to reflect the split between continuing and discontinued operations.

1Prior year results have been recast to reflect the split between continuing and discontinued operations.

Net income (loss) attributable to common shares from continuing operations decreased by $525 million or $0.51 per common share and $477 million or $0.47 per common share for the three and nine months ended September 30, 2025 compared to the same periods in 2024. Refer to the Non-GAAP measures section for the specific items recognized in Net income (loss) attributable to common shares from continuing operations and excluded from comparable earnings from continuing operations.

This MD&A references non-GAAP measures, which are described 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.

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 and unrealized foreign exchange on intercompany loans 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 each of our continuing operations and discontinued operations. Quantitative reconciliations of our comparable measures to their GAAP measures and a discussion of specific adjustments made for the three and nine months ended September 30, 2025 and comparative periods are found throughout this MD&A.

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 reflects net cash provided by operations before changes in operating working capital. The components of changes in working capital are disclosed in our 2024 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 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 in our Condensed 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 the following page as well as 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.

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:

•pre-tax unrealized foreign exchange gains, net, of $87 million and pre-tax unrealized foreign exchange losses, net, of
$42 million for the three and nine months ended September 30, 2025, respectively, 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 recovery of $12 million and a pre-tax expense of $79 million for the three and nine months ended September 30, 2025, respectively, on the expected credit loss provision related to TGNH net investment in leases and certain contract assets in Mexico, net of non-controlling interest.

•a pre-tax gain of $572 million in third quarter 2024 related to the sale of Portland Natural Gas Transmission System (PNGTS), which was completed in third quarter 2024

•a pre-tax gain of $48 million in second quarter 2024 related to the sale of non-core assets in U.S. Natural Gas Pipelines and Canadian Natural Gas Pipelines

•a pre-tax expense of $5 million and a pre-tax recovery of $19 million for the three and nine months ended September 30, 2024, respectively, on the expected credit loss provision related to TGNH net investment in leases and certain contract assets in Mexico, net of non-controlling interest

•pre-tax costs of $10 million related to the ownership transfer of the NGTL System from Nova Gas Transmission Ltd to NGTL GP Ltd. on behalf of NGTL Limited Partnership (NGTL System Ownership Transfer) in second quarter 2024

•a pre-tax expense of $34 million related to a non-recurring third-party settlement in first quarter 2024

•a pre-tax expense of $5 million and $15 million for the three and nine months ended September 30, 2024, respectively, related to Focus Project costs

•pre-tax unrealized foreign exchange losses, net, of $52 million and nil for the three and nine months ended September 30, 2024, respectively, on the peso-denominated intercompany loan between TCPL and TGNH, net of         non-controlling interest.

1Prior year results have been recast to reflect continuing operations only.

2In 2022, TGNH and the CFE executed agreements which consolidate several natural gas pipelines under one TSA. As this TSA contains a lease, we have recognized amounts in net investment in leases on our Condensed consolidated balance sheet and have recognized an expected credit loss provision in relation to the 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 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 12, Risk management and financial instruments, of our Condensed consolidated financial statements for additional information.

3In 2023, TCPL and TGNH became party to an unsecured revolving credit facility. The loan receivable and loan payable are eliminated upon consolidation; however, due to differences in the currency that each entity reports its financial results, there is an impact to net income reflecting the revaluation and translation of the loan receivable and loan payable to TC Energy's reporting currency. As the amounts do not accurately reflect what will be realized at settlement, we exclude from comparable measures the unrealized foreign exchange gains and losses on the loan receivable, as well as the corresponding unrealized foreign exchange gains and losses on the loan payable, net of non-controlling interest.

4    In 2022, we launched the Focus Project with benefits in the form of enhanced safety, productivity and cost-effectiveness expected to be realized over the long term. In 2023 and 2024, we recognized expenses in Plant operating costs and other, for external consulting and severance, some of which are not recoverable through regulatory and commercial tolling structures.

Comparable EBITDA from continuing operations represents segmented earnings (losses) adjusted for the specific items described on the previous page and excludes charges for depreciation and amortization. Refer to each business segment for further information on our reconciliation of comparable EBITDA.

1Prior year results have been recast to reflect continuing operations only.

Comparable EBITDA increased by $242 million for the three months ended September 30, 2025 compared to the same period in 2024 primarily due to the net effect of the following:

•increased U.S. dollar-denominated EBITDA from Mexico Natural Gas Pipelines due to higher earnings in TGNH primarily related to the completion of the Southeast Gateway pipeline, 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 income taxes on the NGTL System and increased contributions from Coastal GasLink

•increased U.S. dollar-denominated EBITDA from U.S. Natural Gas Pipelines mainly due to an increase in earnings from Columbia Gas as a result of higher transportation rates effective April 1, 2025, subject to refund upon completion of the current rate proceeding, incremental earnings from projects placed in service and additional contract sales, partially offset by higher operating costs and decreased earnings as a result of the sale of PNGTS completed in third quarter 2024. Refer to the Recent developments - U.S. Natural Gas Pipelines section for additional information

•increased EBITDA in 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 mainly attributable to lower net contributions from Bruce Power due to reduced generation primarily resulting from the Unit 4 Major Component Replacement (MCR), partially offset by a higher contract price; and lower realized power prices in Canadian Power, partially offset by lower business development costs

•a positive foreign exchange impact of a stronger U.S. dollar on the Canadian dollar equivalent comparable EBITDA in our U.S. dollar-denominated operations, which was translated at a rate of 1.38 in 2025 versus 1.36 in 2024. Refer to the Foreign exchange section for additional information.

Comparable EBITDA increased by $558 million for the nine months ended September 30, 2025 compared to the same period in 2024 primarily due to the net effect of the following:

•increased EBITDA in Canadian Natural Gas Pipelines mainly due to higher flow-through depreciation and income taxes on the NGTL System and increased contributions from Coastal GasLink

•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, 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 U.S. dollar-denominated EBITDA from U.S. Natural Gas Pipelines mainly due to a net increase in earnings from Columbia Gas as a result of higher transportation rates effective April 1, 2025, subject to refund upon completion of the current rate proceeding, incremental earnings from projects placed in service and additional contract sales, partially offset by decreased earnings as a result of the sale of PNGTS completed in third quarter 2024, higher operational costs and lower earnings from our equity investments. Refer to the Recent developments - U.S. Natural Gas Pipelines section for additional information

•increased EBITDA in 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 mainly attributable to lower realized power prices in Canadian Power, decreased net contributions from Bruce Power primarily due to the Unit 4 MCR, higher operating costs, partially offset by a higher contract price; and lower realized Alberta natural gas storage spreads, partially offset by lower business development costs

•a positive foreign exchange impact of a stronger U.S. dollar on the Canadian dollar equivalent comparable EBITDA in our U.S. dollar-denominated operations, which was translated at a rate of 1.40 in 2025 versus 1.36 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 decreased by $89 million or $0.09 per common share for the three months ended September 30, 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, a change in the geographic and business mix of earnings and higher flow-through income taxes

•higher depreciation and amortization primarily due to higher depreciation rates on the NGTL System under the 2025-2029 Revenue Requirement Settlement and on Columbia Gas related to the settlement-in-principle filed with FERC in third quarter 2025. Refer to the Recent developments - U.S. Natural Gas Pipelines section for additional information

•lower capitalized interest due to the declared commercial in-service of the Coastal GasLink pipeline in fourth 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

•lower net income attributable to non-controlling interests is primarily the result of lower net income in TGNH due to the net effect of higher EBITDA and lower AFUDC resulting from the completion of the Southeast Gateway pipeline in second quarter 2025 and the overall impact of foreign exchange. In addition, the divestiture of PNGTS in third quarter 2024, partially offset by higher net income recognized from the Columbia Gas and Columbia Gulf assets also contributed to lower net income attributable to non-controlling interests.

Comparable earnings decreased by $135 million or $0.14 per common share for the nine months ended September 30, 2025 compared to the same period in 2024 primarily due to the net effect of the following:

•changes in comparable EBITDA described above

•higher income tax expense primarily due to the impact of Mexico foreign exchange exposure, higher flow-through income taxes and a change in the geographic and business mix of earnings

•lower capitalized interest due to the declared commercial in-service of the Coastal GasLink pipeline in fourth quarter 2024

•higher depreciation and amortization primarily due to higher depreciation rates on the NGTL System under the 2025-2029 Revenue Requirement Settlement and on Columbia Gas related to the settlement-in-principle that was filed with FERC in third quarter 2025. Refer to the Recent developments - U.S. Natural Gas Pipelines section for additional information

•lower AFUDC 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, partially offset by higher capital expenditures on U.S. natural gas pipeline projects

•lower interest income and other due to lower interest earned on short-term investments

•higher net income attributable to non-controlling interests due to the net effect of the completion of the Southeast Gateway pipeline in second quarter 2025, the sale of the 13.01 per cent non-controlling equity interest in TGNH to the CFE in second quarter 2024, net income recognized from Columbia Gas and Columbia Gulf assets, and the divestiture of PNGTS in third quarter 2024

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

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 for projects included as part of the 2022 strategic alliance between TGNH and the CFE, including Villa de Reyes, Southeast Gateway and Tula. 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.

Our overall comparable EBITDA and comparable earnings per common share outlooks for 2025 remain consistent with our 2024 Annual Report.

Our expected total capital expenditures for 2025 as outlined in our 2024 Annual Report remain materially unchanged.

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.

We placed approximately $7.6 billion of natural gas pipeline capacity projects along our extensive North American asset footprint into service, including Southeast Gateway pipeline. Approximately $1.5 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.

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 as discussed in our 2024 Annual Report. Projects under development have greater uncertainty with respect to timing and estimated project costs and are subject to corporate and regulatory approvals, unless otherwise noted. While each business segment also has additional areas of focus for further ongoing business development activities and growth opportunities, new opportunities will be assessed within our capital allocation framework in order to fit within our annual capital expenditure parameters. As these projects advance and reach necessary milestones they will be included in the Secured projects table on the following page. Refer to the Recent developments section for updates to our secured projects and projects under development.

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.

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 announced by the Government of Canada in February 2024.

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 1.39 at September 30, 2025.

1Includes results from Foothills, Ventures LP, Great Lakes Canada and our proportionate share of income related to investments in Trans Québec & Maritimes (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 increased by $38 million and $90 million for the three and nine months ended September 30, 2025 compared to the same periods in 2024 and included a pre-tax gain on sale of a non-core asset of $10 million in second quarter 2024, which has been excluded from our calculation of comparable EBITDA and comparable EBIT.

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 for the NGTL System increased by $7 million and $12 million for the three and nine months ended September 30, 2025 compared to the same periods in 2024 primarily due to higher incentive earnings. The NGTL System is currently operating under the CER approved five-year negotiated revenue requirement settlement (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 $1 million and $9 million for the three and nine months ended September 30, 2025 compared to the same periods 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 $68 million and $189 million for the three and nine months ended September 30, 2025 compared to the same periods in 2024 due to:

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

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

Depreciation and amortization increased by $30 million and $89 million for the three and nine months ended September 30, 2025 compared to the same periods in 2024 primarily reflecting higher depreciation rates on the NGTL System under the 2025-2029 Revenue Requirement Settlement.

1Includes non-controlling interest. Refer to the Corporate 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 decreased by $529 million and $318 million for the three and nine months ended September 30, 2025 compared to the same periods in 2024 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 third quarter 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 related to our U.S. natural gas marketing business.

A stronger U.S. dollar for the three and nine months ended September 30, 2025 had a positive 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.

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.

Comparable EBITDA for U.S. Natural Gas Pipelines increased by US$36 million and US$75 million for the three and nine months ended September 30, 2025 compared to the same periods 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, subject to refund upon completion of the current rate proceeding. Refer to the Recent developments - U.S. Natural Gas Pipelines section for additional information

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

•decreased earnings as a result of the sale of PNGTS, which was completed in third quarter 2024

•decreased equity earnings from Iroquois and Millennium

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

Depreciation and amortization increased by US$27 million for the three and nine months ended September 30, 2025 compared to the same periods in 2024 primarily due to depreciation rate changes reflected in the Columbia Gas settlement-in-principle that was filed with FERC in third quarter 2025. See Recent Developments - U.S. Natural Gas Pipelines for more details.

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

2Includes non-controlling interest. Refer to the Corporate 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 increased by $170 million and $94 million for the three and nine months ended September 30, 2025 compared to the same periods in 2024 and included a recovery of $14 million and expense of     $87 million, respectively (2024 – expense of $5 million and recovery of $19 million, respectively), 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. During second quarter 2025, we completed the Southeast Gateway pipeline and recognized a net investment in sales-type lease. Refer to Note 12, Risk management and financial instruments and Note 13, TGNH strategic alliance, of our Condensed consolidated financial statements for additional information.

A stronger U.S. dollar for the three and nine months ended September 30, 2025 had a positive impact on the Canadian dollar equivalent segmented earnings from our U.S. dollar-denominated operations in Mexico compared to the same periods in 2024. Refer to the Foreign exchange section for additional information.

Comparable EBITDA for Mexico Natural Gas Pipelines increased by US$108 million and US$133 million for the three and nine months ended September 30, 2025 compared with the same periods in 2024, due to the net effect of:

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

•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. We use foreign exchange derivatives to manage the     peso-denominated exposure, the impact of which is recognized in Foreign exchange (gains) losses, net in the Condensed consolidated statement of income. Refer to the Foreign exchange section for additional information.

Depreciation and amortization was generally consistent for the three and nine months ended September 30, 2025 compared to the same periods in 2024. Under sales-type lease accounting, the completed Southeast Gateway 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.

1Represents our share of equity income from Bruce Power.

2Includes non-controlling interest in the Fluvanna and Blue Cloud Wind Farms (Texas Wind Farms), which is comprised of Class A Membership Interests. Refer to the Corporate section for additional information.

Power and Energy Solutions segmented earnings decreased by $164 million and $189 million for the three and nine months ended September 30, 2025 compared to the same periods in 2024 and included the following specific items which have been excluded from our calculation of comparable EBITDA and comparable EBIT:

•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 $60 million and $82 million for the three and nine months ended September 30, 2025 compared to the same period in 2024 primarily due to the net effect of:

•decreased contributions from Bruce Power due to reduced generation primarily related 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

•lower Canadian Power financial results primarily from lower realized power prices

•higher Natural Gas Storage and other results for the three months ended September 30, 2025 is primarily due to lower business development costs and improved realized natural gas storage spreads. Increased financial results for the nine months ended September 30, 2025 were the result of lower business development costs, partially offset by decreased contributions from our U.S. marketing business and lower realized Alberta natural gas storage spreads in first quarter 2025.

Depreciation and amortization increased by $7 million and $10 million for the three and nine months ended September 30, 2025 compared to the same periods in 2024 primarily due to the in-service of maintenance projects.

The following is our proportionate share of the components of comparable EBITDA and comparable EBIT.

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.

A planned outage on Unit 5 was completed in first quarter 2025. Planned maintenance on Unit 2 commenced in September 2025 with a return to service expected in late fourth quarter 2025.

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

in 2028.

1Prior year results have been recast to reflect continuing operations only.

Corporate segmented losses decreased by $30 million and $105 million for the three and nine months ended September 30, 2025 compared to the same periods in 2024. Corporate segmented losses 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 first quarter 2024 related to a non-recurring third-party settlement

•a pre-tax charge of $5 million and $15 million for the three and nine months ended September 30, 2024 related to Focus Project costs

•a pre-tax cost of $10 million in second quarter 2024 related to the NGTL System Ownership Transfer.

Comparable EBITDA for Corporate increased by $23 million and $41 million for the three and nine months ended September 30, 2025 compared to the same periods in 2024 primarily due to costs in 2024 related to TC Energy's corporate services and governance functions that were not allocated to discontinued operations.

1Prior year results have been recast to reflect continuing operations only.

Interest expense increased by $70 million and $194 million for the three and nine months ended September 30, 2025 compared to the same periods in 2024 and included $1 million in third quarter 2025 of unrealized gains on derivatives used to manage our interest rate risk, which has been removed from our calculation of Interest expense included in comparable earnings. Refer to the Financial risks and financial instruments section for additional information.

Interest expense included in comparable earnings increased by $71 million and $195 million for the three and nine months ended September 30, 2025 compared to the same periods in 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. Refer to our 2024 Annual Report and the Financial condition section for additional information

•the foreign exchange impact from a stronger U.S. dollar on translation of U.S. dollar-denominated interest expense.

AFUDC decreased by $155 million and $134 million for the three and nine months ended September 30, 2025 compared to the same periods in 2024.

The decrease in AFUDC for the three and nine months ended September 30, 2025 is primarily the result of 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.

1     Includes non-controlling interest. Refer to Net (income) loss attributable to non-controlling interests for additional information.

Foreign exchange gains (losses), net, changed by $68 million and $220 million for the three and nine months ended September 30, 2025 compared to the same periods in 2024. 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

•unrealized gains and losses from changes in the fair value of derivatives used to manage our foreign exchange risk. Refer to the Financial risks and financial instruments section for additional information.

Foreign exchange gains (losses), net included in comparable earnings changed by $55 million and $108 million for the three and nine months ended September 30, 2025 compared to the same periods in 2024. The changes were 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.

1Prior year results have been recast to reflect continuing operations only.

Interest income and other decreased by $14 million and $57 million for the three and nine months ended September 30, 2025 compared to the same periods in 2024 due to lower interest earned on short-term investments, partially offset by the change in fair value of other restricted investments.

1Prior year results have been recast to reflect continuing operations only.

Income tax expense decreased by $62 million and increased by $176 million for the three and nine months ended September 30, 2025 compared to the same periods in 2024. The income tax impacts on specified items referenced throughout the MD&A have been removed from our calculation of Income tax expense included in comparable earnings.

Income tax expense included in comparable earnings increased by $80 million and $242 million for the three and nine months ended September 30, 2025 compared to the same periods in 2024 primarily due to the impact of Mexico foreign exchange exposure, higher flow-through income taxes and a change in geographic and business mix of earnings.

1    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. We own 100 per cent of the Class B Membership Interests.

2    In second quarter 2024, the CFE became a partner in TGNH with a 13.01 per cent equity interest in TGNH. Refer to the Recent developments – Mexico Natural Gas Pipelines section for additional information.

3    The sale of PNGTS was completed in August 2024.

Net income attributable to non-controlling interests decreased by $41 million and $90 million for the three and nine months ended September 30, 2025 compared to the same periods in 2024 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 and certain contract assets in Mexico.

Net income attributable to non-controlling interests included in comparable earnings decreased by $9 million for the three months ended September 30, 2025 compared to the same period in 2024 and is primarily the result of lower net income in TGNH due to the net effect of higher EBITDA and lower AFUDC resulting from the completion of the Southeast Gateway pipeline in second quarter 2025 and the overall impact of foreign exchange. In addition, the divestiture of PNGTS in third quarter 2024 , partially offset by higher net income recognized from the Columbia Gas and Columbia Gulf assets also contributed to lower net income attributable to non-controlling interests.

Net income attributable to non-controlling interests included in comparable earnings increased by $11 million for the

nine months ended September 30, 2025 compared to the same period in 2024, due to the net effect of higher net income recognized from the Columbia Gas and Columbia Gulf assets, the divestiture of PNGTS in third quarter 2024, the completion of the Southeast Gateway pipeline in second quarter 2025 and the sale of the 13.01 per cent non-controlling equity interest in TGNH to the CFE in second quarter 2024.

Preferred share dividends increased by $2 million and $8 million for the three and nine months ended September 30, 2025 compared to the same periods in 2024 primarily due to the dividend rate resets on Series 1, 7 and 9 preferred shares in 2024.

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 and nine months ended September 30, 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.

1    Prior year results have been recast to reflect continuing operations only.

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 Condensed 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 Condensed consolidated statement of income. Refer to the Financial risks and financial instruments section for additional information.

The period end exchange rates for one U.S. dollar to Mexican pesos were as follows:

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:

1Includes the foreign exchange impacts from the Sur de Texas joint venture recorded in Income (loss) from equity investments in the Condensed consolidated statement of income.

2    Represents the non-controlling interest portion related to TGNH. Refer to the Corporate section for additional information.

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 Multi-Year Growth Plan (MYGP) for expansion facilities on the NGTL System. It is comprised of multiple distinct projects with various targeted in-service dates, subject to final company and regulatory approvals. With in-service dates beginning in 2026, a total of approximately $0.7 billion of MYGP expansion facilities have received FID, including $0.4 billion in 2025. We continue to evaluate plans for each MYGP facility to optimize cost and schedule. The completion of the MYGP is expected to enable approximately 1.0 Bcf/d of incremental system throughput.

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 project is designed to provide incremental capacity on the NGTL System of approximately 428 TJ/d (400 MMcf/d) and consists of new pipeline, one new non-emitting electric compressor unit and associated facilities.

In November 2024, Coastal GasLink 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 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 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 in our financial statements as at December 31, 2024.

Coastal GasLink LP has resolved all material claims with contractors with a net positive recovery overall to Coastal GasLink LP. Refer to Note 14, Commitments, contingencies and guarantees, of our Condensed consolidated financial statements for additional information.

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 September 2025, prospective investors entered into a non-binding window, which is due to close at the end of 2025.

Columbia Gas filed a Section 4 Rate Case with FERC in September 2024 requesting an increase to its maximum transportation rates effective April 1, 2025, subject to refund upon completion of the current rate proceeding. On October 30, 2025, FERC approved the settlement filing. Previously accrued rate refund liabilities will be refunded to customers, including interest, in fourth quarter 2025.

In April 2025, ANR and GLGT 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.

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.

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.

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.

In October 2025, we approved the US$0.3 billion TCO Connector and US$0.1 billion Midwest Connector projects on our Columbia Gas and extended system. Together these projects are designed to provide approximately 0.6 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 TCO Connector and Midwest Connector projects have anticipated in-service dates of 2030 and 2031, respectively.

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

During second quarter 2024, upon the CFE’s equity injection of US$340 million as well as non-cash consideration in recognition of the completion of certain contractual obligations, including land acquisition and permitting support, the CFE became a partner in TGNH with a 13.01 per cent equity interest. With the CFE's contractual support related to land acquisition, community relations and permitting, 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.

Bruce Power received approval 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.

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.

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.

We believe that we have the financial capacity to fund our existing capital program through predictable cash flows from 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.

At September 30, 2025, our current assets totaled $7.5 billion and current liabilities amounted to $11.9 billion, leaving us with a working capital deficit of $4.4 billion compared to a deficit of $4.8 billion at December 31, 2024, excluding discontinued operations. Our working capital deficiency is considered to be in the normal course of business and is managed through:

•our ability to generate predictable cash flows from operations

•a total of $7.9 billion of TCPL committed revolving credit facilities, of which $5.7 billion of short-term borrowing capacity remains available, net of $2.2 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 September 30, 2025

•additional $2.0 billion of committed revolving credit facilities at certain of our subsidiaries and affiliates, of which         $1.9 billion of short-term borrowing capacity remains available as of September 30, 2025, net of $0.1 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.

CASH PROVIDED BY OPERATING ACTIVITIES1,2

1    Includes continuing and discontinued operations.

2    Includes Liquids Pipelines earnings for the three and nine months ended September 30, 2024 compared to Liquids Pipelines earnings of nil for the same periods in 2025. Refer to the Discontinued operations section and our 2024 Annual Report for additional information.

Net cash provided by operations was generally consistent for the three months ended September 30, 2025 compared to the same period in 2024. Net cash provided by operations decreased by $160 million for the nine months ended September 30, 2025 compared to the same period in 2024 primarily due to lower funds generated from operations, partially offset by the timing of working capital changes.

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 decreased by $125 million and $522 million for the three and nine months ended September 30, 2025 compared to the same periods in 2024 primarily due to lower comparable earnings and lower distributions from our equity investments.

Net cash used in investing activities increased by $738 million and $422 million for the three and nine months ended September 30, 2025 compared to the same periods in 2024 primarily due to proceeds from sale of assets in 2024, partially offset by decreased capital spending in 2025.

Capital expenditures incurred for the nine months ended September 30, 2025 were primarily for the advancement of the Columbia Gas and ANR projects, as well as maintenance capital expenditures. Lower capital expenditures for the nine months ended September 30, 2025 compared to the same period in 2024 reflect the completion of the Southeast Gateway pipeline in second quarter 2025, partially offset by increased spending on ANR projects.

The following table outlines significant long-term debt issuances in the nine months ended September 30, 2025:

The following table outlines significant long-term debt repaid/retired in the nine months ended September 30, 2025:

The following table outlines significant junior subordinated notes issued in the nine months ended September 30, 2025:

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.

In October 2025, TCPL issued US$370 million of junior subordinated notes, including the exercise of the over-allotment option, maturing in 2085 with a fixed interest rate of 6.25 per cent. We intend to use the proceeds from the issuance to redeem all issued and outstanding TC Energy Series 11 preferred shares on November 28, 2025 pursuant to their terms, to reduce indebtedness and for general corporate purposes.

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 8, Junior subordinated notes, of our Condensed consolidated financial statements for additional information.

On November 6, 2025, we announced a quarterly dividend on our outstanding common shares of $0.85 per share payable on January 30, 2026 to shareholders of record at the close of business on December 31, 2025.

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.

At October 30, 2025, we had approximately 1.0 billion issued and outstanding common shares and approximately 2.4 million outstanding options to buy common shares, of which 2.0 million were exercisable.

At October 30, 2025, we had a total of $7.9 billion of TCPL committed revolving credit facilities, of which $5.9 billion of     short-term borrowing capacity remains available, net of $2.0 billion backstopping outstanding commercial paper balances. We also have arrangements in place for a further $2.0 billion of demand credit facilities, of which $1.2 billion remains available.

In addition, we have $2.1 billion of committed revolving credit facilities at certain of our subsidiaries and affiliates, of which $2.0 billion of borrowing capacity remains available at October 30, 2025, net of $0.1 billion backstopping outstanding commercial paper balances.

Capital expenditure commitments at September 30, 2025 are consistent with amounts reported at December 31, 2024, reflecting new contractual commitments entered into for construction on U.S. natural gas pipelines primarily related to the construction costs associated with ANR and other pipeline projects, offset by completion of Southeast Gateway pipeline and normal course fulfillment of construction contracts.

There were no material changes to our contractual obligations in third quarter 2025 or to payments due in the next five years or thereafter. Refer to our 2024 Annual Report for additional information about our contractual obligations.

On October 1, 2024, TC Energy completed the spinoff of its Liquids Pipelines business into a new public company, South Bow Corporation (South Bow). Upon completion of the Spinoff Transaction, the Liquids Pipelines business was accounted for as a discontinued operation. Prior year amounts have been recast to present the Liquids Pipelines business as a discontinued operation. Refer to our 2024 Annual Report for additional information.