April 30, 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 three months ended March 31, 2026 and should be read with the accompanying unaudited Condensed consolidated financial statements for the three months ended March 31, 2026, which have been prepared in accordance with U.S. GAAP.

This MD&A should also be read in conjunction with our December 31, 2025 audited Consolidated financial statements and notes and the MD&A in our 2025 Annual Report. Capitalized and abbreviated terms that are used but not otherwise defined herein are defined in our 2025 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. For the three months ended March 31, 2026 and 2025, we did not recognize any income or loss from discontinued operations.

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.

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

•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

•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 the Canadian securities regulators and the SEC, including the MD&A in our 2025 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, comparable earnings per common share 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 and the Financial condition sections for reconciliations to the most directly comparable GAAP measures.

1Additional information on the most directly comparable GAAP measure can be found in the Non-GAAP measures section.

1Additional information on the most directly comparable GAAP measure can be found in the Non-GAAP measures section.

2Capital 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.

Net income (loss) attributable to common shares decreased by $79 million or $0.08 per common share for the three months ended March 31, 2026 compared to the same period in 2025.

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.

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 and 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. Quantitative reconciliations of our comparable measures to their GAAP measures and a discussion of specific adjustments made for the three months ended March 31, 2026 and comparative period 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 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 the Consolidated financial statements of our 2025 Annual Report. 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 for reconciliations to Net income (loss) attributable to common shares and Net income (loss) per common share.

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

•pre-tax unrealized foreign exchange gains, net, of $58 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 $33 million related to the resolution of certain legal matters within our U.S. Natural Gas Pipelines segment

•a pre-tax expense of $17 million on the expected credit loss provision related to TGNH net investment in leases, net of     non-controlling interest as well as on certain contract assets in Mexico.

•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 on certain contract assets in Mexico.

1TCPL and TGNH are parties to 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 12, Risk management and financial instruments, in the Condensed consolidated financial statements for additional information.

Comparable EBITDA 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 to comparable EBITDA.

Comparable EBITDA – 2026 versus 2025

Comparable EBITDA increased by $379 million for the three months ended March 31, 2026 compared to the same period in 2025 primarily due to the net result of the following:

•increased U.S. dollar-denominated EBITDA in Mexico Natural Gas Pipelines due to higher earnings in TGNH primarily related to the completion of the Southeast Gateway pipeline in second quarter 2025 and higher equity earnings from Sur de Texas as a result of peso-denominated financial exposure

•increased U.S. dollar-denominated EBITDA in 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, settlement-in-principle reached with ANR and additional contract sales, partially offset by lower margins in our U.S. natural gas marketing business

•increased EBITDA in Canadian Natural Gas Pipelines mainly due to higher flow-through depreciation on both the NGTL System and Canadian Mainline and incentive earnings on the NGTL System, partially offset by lower flow-through income taxes on the Canadian Mainline

•increased EBITDA in Power and Energy Solutions mainly attributable to higher net contributions from Bruce Power due to a higher contract price partially offset by reduced generation primarily resulting from the Unit 4 Major Component Replacement (MCR)

•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 1.37 in 2026 versus 1.43 in 2025. 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 – 2026 versus 2025

Comparable earnings increased by $48 million or 0.04 per common share for the three months ended March 31, 2026 compared to the same period in 2025 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 net income attributable to non-controlling interests primarily from higher net income recognized from the Columbia Gas and Columbia Gulf assets

•higher depreciation and amortization primarily due to assets placed in service in our Canadian Natural Gas Pipeline segment, higher depreciation rates on the NGTL System and depreciation rate changes as a result of the Columbia Gas Settlement and ANR settlement-in-principle

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

•lower interest income and other due to the change in fair value of other restricted investments

•risk management activities used to manage our foreign exchange exposure.

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.

Our overall comparable EBITDA and comparable earnings per common share outlooks for 2026 remain consistent with our 2025 Annual Report.

Our expected total capital expenditures for 2026 as outlined in our 2025 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 $23 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.

For the three months ended March 31, 2026, we placed approximately $0.4 billion of natural gas pipeline capacity projects into service along our extensive North American asset footprint. In addition, approximately $0.3 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 2025 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.

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 1.40 at March 31, 2026.

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 decreased by $7 million for the three months ended March 31, 2026 compared to the same period in 2025.

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 $6 million for the three months ended March 31, 2026 compared to the same period in 2025 primarily due to higher incentive earnings. The NGTL System is currently operating under the 2025-2029 NGTL Settlement, which 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 was consistent for the three months ended March 31, 2026 compared to the same period in 2025. 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 $29 million for the three months ended March 31, 2026 compared to the same period in 2025 due to the net effect of higher flow-through depreciation and incentive earnings on the NGTL System along with higher flow-through depreciation, partially offset by lower flow-through income taxes on the Canadian Mainline.

Depreciation and amortization increased by $36 million for the three months ended March 31, 2026 compared to the same period in 2025 mainly due to an increase in assets placed in service on the Canadian Mainline and higher depreciation rates and expansion facilities placed in service on the NGTL System.

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

2Reflects 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 $34 million for the three months ended March 31, 2026 compared to the same period in 2025 and included the following specific items which have been excluded from our calculation of comparable EBITDA and comparable EBIT:

•a pre-tax expense of $33 million related to the resolution of certain legal matters within our U.S. Natural Gas Pipelines segment

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

A weaker U.S. dollar for the three months ended March 31, 2026 had a negative impact on the Canadian dollar equivalent segmented earnings from our U.S. dollar-denominated operations compared to the same period in 2025. 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$138 million for the three months ended March 31, 2026 compared to the same period in 2025 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

•a net increase in earnings from ANR as a result of higher transportation rates effective November 1, 2025 as well as adjustments related to the ANR settlement-in-principle

•incremental earnings from projects placed in service and lower operating costs on Columbia Gulf

•increased earnings from additional short-term contract sales due to the impacts of a cold weather event across multiple U.S. Natural Gas Pipeline assets

•lower realized earnings related to our U.S. natural gas marketing business primarily due to reduced trading margins from the impacts of a cold weather event.

Depreciation and amortization increased by US$11 million for the three months ended March 31, 2026 compared to the same period in 2025 primarily due to new projects placed in service and depreciation rate changes as a result of the Columbia Gas Settlement, offset by a decrease in depreciation rate changes as a result of the ANR settlement-in-principle.

1Includes the operating 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 $178 million for the three months ended March 31, 2026 compared to the same period in 2025 and included an expense of $19 million (2025 – recovery of $2 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 ended March 31, 2026 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 2025. Refer to the Foreign exchange section for additional information.

Comparable EBITDA for Mexico Natural Gas Pipelines increased by US$152 million for the three months ended March 31, 2026 compared with the same period in 2025 due to:

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

•higher equity earnings from Sur de Texas primarily due to the foreign exchange impacts on the revaluation of
peso-denominated liabilities as well as lower interest expense.

Depreciation and amortization was generally consistent for the three months ended March 31, 2026 compared to the same period in 2025. 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.

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 Condensed 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:

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 increased by $66 million for the three months ended March 31, 2026 compared to the same period in 2025 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 increased by $19 million for the three months ended March 31, 2026 compared to the same period in 2025 primarily due to the net effect of:

•increased Bruce Power contributions due to a higher contract price and realized gains on funds invested for post-retirement benefits, partially offset by reduced generation primarily related to the Unit 4 MCR and increased operating costs. Refer to the Bruce Power results section for additional information

•higher Canadian Power financial results primarily from increased contributions from our marketing business

•decreased Natural Gas Storage and other results primarily due to lower contributions from our U.S. marketing business.

Depreciation and amortization was generally consistent for the three months ended March 31, 2026 compared to the same period in 2025.

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.

Planned maintenance on Unit 8 was completed in first quarter 2026.

Corporate segmented losses were generally consistent for the three months ended March 31, 2026 compared to the same period in 2025.

Interest expense decreased by $2 million for the three months ended March 31, 2026 compared to the same period in 2025 primarily due to the net effect of:

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

•long-term debt issuances and maturities. Refer to the Financial condition section for additional information.

AFUDC decreased by $209 million for the three months ended March 31, 2026 compared to the same period in 2025. The decrease in U.S. dollar-denominated AFUDC is mainly the result of the completion of the Southeast Gateway pipeline in second quarter 2025 and U.S natural gas pipeline projects placed in service during 2025.

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 $43 million for the three months ended March 31, 2026 compared to the same period in 2025. 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 $11 million for the three months ended March 31, 2026 compared to the same period in 2025. 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 gains in 2026 compared to foreign exchange losses in 2025 on the revaluation of our peso-denominated net monetary liabilities to U.S. dollars

•foreign exchange losses in 2026 compared to foreign exchange gains in 2025 on the revaluation of our U.S. dollar-denominated assets and liabilities to Canadian dollars.

Interest income and other decreased by $18 million for the three months ended March 31, 2026 compared to the same period in 2025 primarily due to:

•changes in fair value of other restricted investments

•lower interest earned on Canadian and U.S. dollar-denominated short-term investments.

Income tax expense decreased by $39 million for the three months ended March 31, 2026 compared to the same period in 2025. 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 $24 million for the three months ended March 31, 2026 compared to the same period in 2025 primarily due to a change in geographic and business mix of earnings and higher flow-through income taxes, partially offset by the impact of Mexico foreign exchange exposure.

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.

Net income attributable to non-controlling interests increased by $55 million for the three months ended March 31, 2026 compared to the same period in 2025 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 $48 million for the three months ended March 31, 2026 compared to the same period in 2025 resulting from higher net income recognized from the Columbia Gas and Columbia Gulf assets.

Preferred share dividends were consistent for the three months ended March 31, 2026 compared to the same period in 2025 primarily due to the offsetting impacts of the redemption of preferred shares in 2025 and dividend rate resets on and conversions of certain series of preferred shares in 2026 and 2025.

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 March 31, 2026 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.

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.

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

In the three months ended March 31, 2026, the NGTL System placed approximately $0.4 billion of capacity projects into service, including $0.1 billion of Multi-Year Growth Plan (MYGP) projects.

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. As of March 31, 2026, approximately $1.1 billion of expansion facilities have received FID, with various in-service dates starting in 2026. As we have continued to evaluate plans for each MYGP facility, we do not expect that all facilities up to the Board-approved capital allocation will be required to satisfy our MYGP capacity commitments of approximately 1.0 Bcf/d of incremental system throughput.

The Valhalla North and Berland River project continues to advance. 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 construction of the Berland River non‑emitting electric compressor unit was completed in first quarter 2026, with a capital cost of approximately $0.3 billion, and is expected to be operational in the second half of 2026 upon completion of the third-party power transmission connection. The project is designed to provide incremental capacity on the NGTL System of approximately 428 TJ/d (400 MMcf/d).

In March 2026, we filed an application with the CER seeking approval of a four‑year negotiated settlement governing the Canadian Mainline tolls and service for the period from January 2027 through December 2030. The proposed settlement, supported by our customers and other interested parties, maintains a return on equity of 10.1 per cent on 40 per cent deemed common equity and includes an incentive mechanism designed to encourage cost management and revenue optimization, with benefits shared between customers and us. This incentive provides the opportunity to outperform the approved rate of return. In addition, TC Energy has committed up to $200 million of capital to support incremental capacity, with targeted returns that exceed the approved return on equity.

In March 2026, Coastal GasLink Limited Partnership (Coastal GasLink LP) entered into commercial agreements with LNG Canada (LNGC), which establish a framework for advancing a proposed expansion of the Coastal GasLink pipeline (the CGL Phase 2 Expansion) to enable the delivery of incremental pipeline capacity to the LNGC export facility in Kitimat, British Columbia. The commercial structure of the agreements includes limits on Coastal GasLink LP's capital commitments and overall liability for construction cost and schedule risks. Under the agreements, LNGC will lead project construction as the     CGL Phase 2 Expansion execution manager and Coastal GasLink LP will provide LNGC technical advisory services. The CGL Phase 2 Expansion remains subject to FID by LNGC and its joint venture participants, as well as approval by Coastal GasLink LP.

In April 2025, ANR filed a Section 4 Rate Case with FERC requesting an increase to its overall maximum transportation rates effective November 1, 2025, subject to refund. On March 18, 2026, ANR notified FERC that it has reached a settlement-in-principle with its customers. ANR expects the final settlement to include an increase relative to pre-filed rates, subject to revision following completion and approval of settlement terms, which we anticipate in third quarter 2026.

In April 2025, Great Lakes filed a Section 4 Rate Case with FERC requesting an increase to its maximum transportation rates effective November 1, 2025, subject to refund. On April 28, 2026, Great Lakes notified FERC that it has reached a settlement-in-principle with its customers, subject to revision following completion and approval of settlement terms, which we anticipate in fourth quarter 2026.

In April 2026, we approved the Appalachia Supply project, an expansion project of our Columbia Gas system designed to provide up to 0.8 Bcf/d of capacity to facilitate expanded new natural gas-fired power generation. The project has an anticipated in-service date of 2030 and an estimated project cost of approximately US$1.5 billion.

The CFE is an equity partner in TGNH with a 13.01 per cent equity interest, which 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.

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 March 31, 2026, our current assets totaled $6.8 billion and current liabilities amounted to $10.3 billion, leaving us with a working capital deficit of $3.5 billion compared to a deficit of $3.7 billion at December 31, 2025, 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 $6.8 billion of short-term borrowing capacity remains available, net of $1.1 billion backstopping outstanding commercial paper balances, and arrangements for a further $2.0 billion of demand credit facilities, of which $1.2 billion remains available as of March 31, 2026

•additional $2.1 billion of committed revolving credit facilities at certain of our subsidiaries and affiliates, of which         $0.9 billion of short-term borrowing capacity remains available as of March 31, 2026, net of $1.2 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.

Net cash provided by operations increased by $1,244 million for the three months ended March 31, 2026 compared to the same period in 2025 primarily due to the timing of working capital changes and higher 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 $387 million for the three months ended March 31, 2026 compared to the same period in 2025 primarily due to higher comparable earnings and higher distributions from our equity investments.

Net cash used in investing activities decreased by $472 million for the three months ended March 31, 2026 compared to the same period in 2025 primarily due to decreased capital spending in 2026.

Capital expenditures incurred for the three months ended March 31, 2026 were primarily for capital spending across our U.S. Natural Gas Pipelines asset footprint, NGTL System expansion projects and maintenance capital expenditures. Lower capital expenditures for the three months ended March 31, 2026 compared to the same period in 2025 reflect the completion of the Southeast Gateway pipeline and ANR projects in 2025.

The following table outlines significant long-term debt repaid/retired in the three months ended March 31, 2026:

The following table outlines significant junior subordinated notes issued in the three months ended March 31, 2026:

1    Fixed rate of interest per year until August 20, 2031, and resetting every five years thereafter, subject to a rate-reset minimum.

On April 17, 2026, TCPL issued US$500 million of junior subordinated notes, maturing in October 2056 with a fixed interest rate of 6.13 per cent and US$500 million of junior subordinated notes, maturing in October 2056 with a fixed interest rate of 6.38 per cent. We intend to use the net proceeds from these issuances, combined with the net proceeds of the 5.13 per cent junior subordinated notes issued in February 2026, to fund the redemption price of the US$1.2 billion in aggregate principal amount of outstanding Trust Notes - Series 2016-A issued by TransCanada Trust, a wholly owned financing trust subsidiary of TCPL, in August 2026 pursuant to their terms. Prior to such redemption, the funds will be used to reduce other indebtedness of TC Energy and for general corporate purposes. Refer to Note 8, Junior subordinated notes, of our Condensed consolidated financial statements 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 June 30, 2026.

At April 24, 2026, we had approximately 1.0 billion issued and outstanding common shares and approximately 1.4 million outstanding and exercisable options to buy common shares.

At April 24, 2026, we had a total of $7.8 billion of TCPL committed revolving credit facilities, of which $6.8 billion of     short-term borrowing capacity remains available, net of $1.0 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 $1.1 billion of borrowing capacity remains available at April 24, 2026, net of $1.0 billion backstopping outstanding commercial paper balances.

Capital expenditure commitments at March 31, 2026 were approximately $1.3 billion (December 31, 2025 - approximately     $0.8 billion), reflecting 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.

There were no material changes to our contractual obligations in first quarter 2026 or to payments due in the next five years or thereafter. Refer to our 2025 Annual Report for additional information about our contractual obligations.

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.

Refer to our 2025 Annual Report for additional information about the risks we face in our business which have not changed materially since December 31, 2025, other than as noted within this MD&A.

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.

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 Condensed 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 as appropriate.

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.

Market events causing disruptions in global energy demand and supply may contribute to economic uncertainties impacting a number of our customers. While the majority of our credit exposure is to large creditworthy entities, we maintain close monitoring and communication with those counterparties experiencing greater financial pressures. Refer to our 2025 Annual Report for more information about the factors that mitigate our counterparty credit risk exposure.

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 March 31, 2026, we had no significant credit risk concentrations, with the exception of the CFE, which represents approximately 33 per cent of gross exposure. At this time, there were no significant amounts past due or impaired. We recorded a pre-tax expense of $19 million on the expected credit loss provision on the TGNH net investment in leases and certain contract assets in Mexico for the three months ended March 31, 2026 (2025 – pre-tax recovery of $2 million). Refer to Note 12, Risk management and financial instruments, of our Condensed 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.

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.

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.

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 ratepayers in subsequent years when the derivative settles.

The balance sheet presentation of the fair value of derivative instruments were as follows:

The following summary does not include hedges of our net investment in foreign operations.

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 Condensed 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 Condensed consolidated statement of income.

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 12, Risk management and financial instruments, of our Condensed consolidated financial statements.

Management, including our President and CEO and our CFO, evaluated the effectiveness of our disclosure controls and procedures as at March 31, 2026, as required by the Canadian securities regulatory authorities and by the SEC and concluded that our disclosure controls and procedures are effective at a reasonable assurance level.

There were no changes in first quarter 2026 that had or are likely to have a material impact on our internal controls over financial reporting.

When we prepare financial statements that conform with U.S. GAAP, we are required to make estimates and assumptions that affect the timing and amounts we record for our assets, liabilities, revenues and expenses because these items may be affected by future events. We base the estimates and assumptions on the most current information available, using our best judgment. We also regularly assess the assets and liabilities themselves. In addition to the items discussed below, refer to our 2025 Annual Report for a listing of critical accounting estimates.

Goodwill is tested for impairment on an annual basis, or more frequently if events or changes in circumstances indicate it might be impaired. We can initially make this assessment based on qualitative factors. 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.

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.

Our significant accounting policies have remained unchanged since December 31, 2025 other than as described in         Note 2, Accounting changes, of our Condensed consolidated financial statements. A summary of our significant accounting policies is included in our 2025 Annual Report.

1    Discontinued operations represents nine months of Liquids Pipelines earnings in 2024.

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

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

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. Refer to the Foreign exchange 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 (losses) 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.

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 the Non-GAAP measures section for additional information.

In first quarter 2026, comparable earnings from continuing operations also excluded:

•pre-tax unrealized foreign exchange gains, net, of $58 million on the peso-denominated intercompany loan between TCPL and TGNH, net of non-controlling interest

•a pre-tax expense of $33 million related to the resolution of certain legal matters within our U.S. Natural Gas Pipelines segment

•a pre-tax expense of $17 million on the expected credit loss provision related to TGNH net investment in leases, net of     non-controlling interest as well as on certain contract assets in Mexico.

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 on certain contract assets in Mexico.

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 on 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 on 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 on 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 on 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 on 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 segments

•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 on certain contract assets in Mexico

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