Earnings release
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Quarterly Report to Shareholders TC Energy reports strong third quarter 2026 operating and financial results Revising 2026 outlook higher and extending to a five-year outlook through to 2031 Announced approximately $3 billion of new growth projects CALGARY, Alberta – November 5, 2026 – TC Energy Corporation (TSX, NYSE: TRP) (TC Energy or the Company) released its third quarter results today. François Poirier, TC Energy's President and Chief Executive Officer commented, "TC Energy's 75th year continues to demonstrate the strength of our integrated North American footprint. Through the first nine months of 2026, exceptional operational performance across our natural gas systems, constructive settlement outcomes and projects placed in service ahead of schedule and under budget have supported an increase to our 2026 comparable EBITDA1 outlook to $11.8 to $12.0 billion.” Poirier continued, “Beyond 2026, we expect that our growth will be driven by the continued conversion of our origination pipeline into sanctioned capital projects. With approximately $6 billion of growth projects sanctioned year-to-date 2026 at a weighted average build multiple2 of approximately 6.5 times, along with approximately $6 billion in pending approval and more than $40 billion of additional anticipated high-return, low-risk opportunities in origination, we have confidence in providing a five-year comparable EBITDA compound annual growth rate of five to seven per cent out to 2031. Our continued delivery around project execution, operational and commercial excellence reflects our continued focus on executing our selective portfolio of growth projects to deliver solid growth, low risk and repeatable performance.” Financial Highlights (All financial figures are unaudited and in Canadian dollars unless otherwise noted) • Third quarter 2026 financial results from continuing operations: ◦ Comparable earnings1 of $1.0 billion or $0.94 per common share1 compared to $0.8 billion or $0.77 per common share in third quarter 2025 ◦ Net income attributable to common shares of $1.0 billion or $0.98 per common share compared to $0.8 billion or $0.78 per common share in third quarter 2025 ◦ Comparable EBITDA of $3.0 billion compared to $2.7 billion in third quarter 2025 ◦ Segmented earnings of $2.3 billion compared to $1.9 billion in third quarter 2025 • TC Energy’s Board of Directors declared a quarterly dividend of $0.8775 per common share for the quarter ending Dec. 31, 2026 • 2026 outlook: ◦ Comparable EBITDA is revised higher and now expected to be in the range of $11.8 to $12.0 billion3 ◦ Comparable earnings per common share (EPS) outlook is expected to be higher than 2025, consistent with our 2025 Annual Report 1 Comparable EBITDA, comparable earnings and comparable earnings per common share are non-GAAP measures used throughout this news release. These measures do not have any standardized meaning under GAAP and therefore are unlikely to be comparable to similar measures presented by other companies. The most directly comparable GAAP measures are Segmented earnings, Net income attributable to common shares and Net income per common share, respectively. We do not forecast Segmented earnings. For more information on non-GAAP measures, refer to the Non-GAAP and Supplementary financial measure section of this news release. 2 Build multiple is a non-GAAP ratio calculated by dividing capital expenditures by comparable EBITDA. Weighted average build multiple is calculated across all projects based on each project's capital expenditures. Please note our method for calculating build multiple may differ from methods used by other entities. Therefore, it may not be comparable to similar measures presented by other entities. For more information on non-GAAP measures and the supplementary financial measure, refer to the Non-GAAP and Supplementary financial measure section of this news release. 3 Based on forecasted 2026 annual average USD/CAD foreign exchange rate of 1.38.
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◦ Capital expenditures are anticipated to be at the lower end of $6.0 to $6.5 billion prior to adjustments for non-controlling interests, or $5.5 to $6.0 billion of net capital expenditures1 • 2027 and 2031 outlooks: ◦ 2027 comparable EBITDA is expected to be $12.3 to $12.5 billion ◦ 2027 capital expenditures are expected to be $6.7 to $7.2 billion prior to adjustments for non-controlling interests, or $6.0 to $6.5 billion of net capital expenditures ◦ Five-year comparable EBITDA compound annual growth rate is expected to be five to seven per cent. Operational Highlights • Canadian Natural Gas Pipelines deliveries averaged 24.3 Bcf/d, up 6 per cent compared to third quarter 2025 ◦ NGTL System receipts averaged 14.3 Bcf/d, up 2 per cent compared to third quarter 2025 ◦ Canadian Mainline Western receipts averaged 4.3 Bcf/d, up 7 per cent compared to third quarter 2025 • U.S. Natural Gas Pipelines daily average flows were 27.0 Bcf/d, up 3 per cent compared to third quarter 2025 ◦ Deliveries to power generators averaged 3.7 Bcf/d, up 2 per cent compared to third quarter 2025 • Mexico Natural Gas Pipelines flows averaged 3.7 Bcf/d, up 8 per cent compared to third quarter 2025 ◦ Power plant deliveries averaged 1.5 Bcf/d, up 4 per cent compared to third quarter 2025 • Bruce Power achieved 96.6 per cent availability in third quarter 2026 • Cogeneration power plant fleet achieved 89.6 per cent availability in third quarter 2026, primarily reflecting fall planned outages. Project Highlights • Announced approximately $3 billion of new, low-risk, in-corridor growth projects. Year-to-date, sanctioned capital projects now total approximately $6 billion at a weighted average build multiple of approximately 6.5 times ◦ Approved the Crossroads Expansion project with an expected build multiple of approximately 6.0 times. This is an expansion of our Crossroads pipeline system designed to provide incremental capacity of 1.4 Bcf/d to support growing power generation demand, including data centres, in the U.S. Midwest. The project is supported by long-term take-or-pay contracts. It has an anticipated in-service date in 2030, and the estimated project cost is approximately US$1.8 billion ◦ Approved the American Midwest project in connection with the Crossroads Expansion project with an expected weighted average build multiple of approximately 6.0 times. The project is an expansion of our Northern Border pipeline system designed to provide incremental capacity of 1.0 Bcf/d to support growing power generation demand, including data centres, in the U.S. Midwest. It is supported by long-term take-or-pay contracts. It has an anticipated in-service date in 2030 and a total estimated project cost of approximately US$0.4 billion, of which our proportionate share of equity contributions is approximately US$0.1 billion 1 Net capital expenditures are adjusted for the portion attributed to non-controlling interests and is a supplementary financial measure used throughout this news release. For more information on non-GAAP measures and the supplementary financial measure, refer to the Non-GAAP and Supplementary financial measure section of this news release.
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◦ Approved the Coastal GasLink Phase 2 Expansion following a positive final investment decision by LNG Canada and its joint venture participants. With an estimated project cost of $4.9 billion, the project will add five compressor stations and associated facility modifications, increasing firm transportation capacity by approximately 2.0 Bcf/d to approximately 4.5 Bcf/d. Construction is expected to commence in early 2027, with an anticipated in-service date in the early 2030s. LNG Canada will lead project execution and construction, and the commercial structure includes defined limits on Coastal GasLink LP's capital commitments and exposure to construction cost and schedule risk. Coastal GasLink LP secured project-level financing of up to $3.3 billion, and our proportionate share of committed equity is up to approximately $250 million ◦ Approved the ANR Optimization project, an expansion of our ANR pipeline system designed to provide approximately 0.3 Bcf/d of firm transportation service to support coal-to-gas conversion, with an anticipated in-service date in 2029 and an estimated project cost of approximately US$0.1 billion • Completed a transaction with FN CGL Pipeline Limited Partnership, an Indigenous-led investment entity representing five First Nations, providing participating communities with an economic interest in the entity that holds our limited partner interest in Coastal GasLink. A second transaction involving additional First Nations is expected to close in fourth quarter 2026 • Year-to-date, we placed approximately $2.5 billion of projects in service, and we continue to expect approximately $3.4 billion of capital to be placed in service in 2026. We also expect to place approximately $4.5 to 5.0 billion of capital into service in 2027. Projects placed in service from 2025 to 2026 year-to-date were delivered more than 10 per cent under budget in aggregate, including: ◦ Placed the Gillis Access project extension in service on Nov. 1, 2026, with a total project cost of approximately US$0.4 billion, to connect supplies from the Haynesville basin at Gillis • Bruce Power commenced the Unit 5 Major Component Replacement (MCR) in November 2026. Unit 4 MCR is ahead of schedule and under budget; calandria tube installation using robotic tooling pioneered on Unit 3 was completed 25 days faster than on Unit 3. Bruce Power also set a world record of 20 calandria tubes installed in a 24-hour period • Advanced U.S. rate case settlements. FERC approved the Great Lakes Stipulation and Agreement of Settlement on Sept. 15, 2026, and on Oct. 15, 2026, GTN filed the Stipulation and Agreement of Settlement with FERC subject to approval.
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three months ended September 30 nine months ended September 30 (millions of $, except per share amounts) 2026 2025 2026 2025 Income Net income (loss) attributable to common shares from continuing operations 1,026 813 2,912 2,653 per common share – basic $0.98 $0.78 $2.79 $2.55 Segmented earnings (losses) Canadian Natural Gas Pipelines 531 533 1,585 1,600 U.S. Natural Gas Pipelines 1,013 801 3,080 2,817 Mexico Natural Gas Pipelines 411 407 1,197 809 Power and Energy Solutions 308 190 749 637 Corporate (1) (3) (5) (15) Total segmented earnings (losses) 2,262 1,928 6,606 5,848 Comparable EBITDA from continuing operations Canadian Natural Gas Pipelines 953 913 2,833 2,726 U.S. Natural Gas Pipelines 1,246 1,062 3,961 3,518 Mexico Natural Gas Pipelines 446 416 1,287 968 Power and Energy Solutions 360 266 964 791 Corporate (1) (3) (5) (15) Comparable EBITDA from continuing operations 3,004 2,654 9,040 7,988 Depreciation and amortization (749) (701) (2,209) (2,050) Interest expense included in comparable earnings (883) (848) (2,581) (2,535) Allowance for funds used during construction 64 55 163 417 Foreign exchange gains (losses), net included in comparable earnings 11 22 40 67 Interest income and other included in comparable earnings 16 47 83 147 Income tax (expense) recovery included in comparable earnings (303) (260) (935) (846) Net (income) loss attributable to non-controlling interests included in comparable earnings (149) (136) (518) (468) Preferred share dividends (28) (28) (85) (84) Comparable earnings from continuing operations 983 805 2,998 2,636 Comparable earnings per common share from continuing operations $0.94 $0.77 $2.88 $2.53
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three months ended September 30 nine months ended September 30 (millions of $, except per share amounts) 2026 2025 2026 2025 Cash flows Net cash provided by operations 1,782 1,920 6,602 5,452 Comparable funds generated from operations1 2,236 1,790 6,568 5,703 Capital spending2 1,412 1,506 3,842 4,694 Dividends declared per common share $0.8775 $0.85 $2.6325 $2.55 Basic common shares outstanding (millions) – weighted average for the period 1,042 1,040 1,042 1,040 – issued and outstanding at end of period 1,042 1,041 1,042 1,041 1 Comparable funds generated from operations is a non-GAAP measure used throughout this news release. This measure does not have any standardized meaning under GAAP and therefore is unlikely to be comparable to similar measures presented by other companies. The most directly comparable GAAP measure is net cash provided by operations. For more information on non-GAAP measures, refer to the Non-GAAP and Supplementary financial measure section of this news release. 2 Capital 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.
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CEO Message In our 75th year, TC Energy continued to deliver strong third quarter results, reflecting the strength of our integrated North American footprint and consistent execution excellence across our businesses. Comparable EBITDA increased 13 per cent and segmented earnings increased 17 per cent compared to third quarter 2025. Based on our performance through the first nine months of the year, we have raised our 2026 comparable EBITDA outlook to $11.8 to $12.0 billion, while maintaining debt-to-EBITDA1 below our 4.75 times long-term target. This outperformance is driven primarily by strong availability across our assets, constructive settlements and commercial agreements across our U.S. natural gas systems, incremental storage and park and loan revenues, incentive earnings under our Canadian settlements, and projects placed in service ahead of schedule and under budget. Including new capital projects announced today, we have sanctioned approximately $6 billion in 2026 at a weighted average build multiple of approximately 6.5 times, within our targeted range of five to seven times and several accelerated in-service dates in 2029 and 2030. Disciplined execution continues to convert our capital program into financial results. To date we have placed approximately $2.5 billion of projects in service, and we continue to expect approximately $3.4 billion to be placed in service in 2026. Projects placed in service from 2025 to 2026 year-to-date were delivered more than 10 per cent under budget in aggregate. At Bruce Power, the Unit 5 Major Component Replacement (MCR) commenced in November. Innovations pioneered on Unit 3, including robotic tooling, continue to drive efficiencies on Unit 4, where calandria tube installation was completed 25 days faster than on Unit 3. Supportive market fundamentals and policy developments across Canada, the U.S. and Mexico continue to reinforce our long- term growth outlook. We expect North American natural gas demand to grow by approximately 51 Bcf/d from 2025 to 2035, led by LNG exports and natural gas-fired power generation, with growth concentrated in regions served by our network. In Canada, power demand is expected to double by 2050, creating opportunities to leverage our existing natural gas and power footprint where we can selectively advance opportunities supported by long-term contracts, attractive returns and disciplined risk allocation. This momentum is translating into a growing portfolio of high-quality projects at the intersection of natural gas and power. In U.S. Natural Gas Pipelines, we approved the Crossroads Expansion project and the American Midwest project, which will add 1.4 Bcf/d and 1.0 Bcf/d of capacity, respectively, into the U.S. Midwest where natural gas demand, including from data centres, is expected to grow by more than 5 Bcf/d by 2035. Together, they represent approximately US$1.9 billion of net capital at a build multiple of approximately 6.0 times, underpinned by 20-year take-or-pay contracts. These projects prove our network advantage where one expansion creates downstream opportunities for others. In Western Canada, Coastal GasLink Phase 2 is proceeding following LNG Canada's positive final investment decision on its Phase 2 expansion. Phase 2 will add five compressor stations along the existing route, nearly doubling the pipeline's capacity without the construction of new pipe and will enable incremental capital-efficient access to global markets for Canadian natural gas. Under the Phase 2 agreements, LNG Canada will lead construction as execution manager, Coastal GasLink will remain owner and operator, and Coastal GasLink's capital commitments and overall exposure to construction cost and schedule risk are limited. In October, we also completed a transaction providing five First Nations with an economic interest in the entity that holds our limited partner interest in Coastal GasLink, and a second transaction involving additional First Nations is expected to close by the end of the year. Our performance and nearly $25 billion of sanctioned projects underpin our extended five-year outlook. We now expect comparable EBITDA to grow at a compound annual growth rate of five to seven per cent from 2026 to 2031. That growth is also currently supported by approximately $6 billion of projects pending approval and more than $40 billion of additional opportunities in origination. With approximately 98 per cent of our comparable EBITDA generated from rate-regulated assets 1 Debt-to-EBITDA is a non-GAAP ratio. Adjusted debt and adjusted comparable EBITDA are non-GAAP measures used to calculate debt-to-EBITDA. For more information on non-GAAP measures, refer to the Non-GAAP and Supplementary financial measure section of this news release. These measures do not have any standardized meaning under GAAP and therefore are unlikely to be comparable to similar measures presented by other companies.
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or long-term take-or-pay contracts, our growth remains low-risk and highly visible. The outlook also builds on our track record of meeting or exceeding our comparable EBITDA outlook in each year since 2021. For 75 years, TC Energy has connected North America to the energy it needs. Our results through the first nine months of 2026 show that our strategy is working and that our assets are well positioned to serve the next generation of energy demand. As we enter our next chapter, our priorities remain unchanged: maximizing the value of our assets, executing our selective portfolio of growth projects, and ensuring financial strength and agility to create long-term value for our shareholders. Dividends TC Energy’s Board of Directors declared a quarterly dividend of $0.8775 per common share for the quarter ending Dec. 31, 2026, equivalent to $3.51 on an annualized basis. The common share dividend is payable on Jan. 29, 2027, to shareholders of record at the close of business on Dec. 31, 2026. The Board of Directors also declared dividends on the outstanding Cumulative First Preferred Shares (preferred shares). Information related to the preferred shares dividends is available on our website under TC Energy – Shareholder Information.
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Teleconference and Webcast We will hold a teleconference and webcast on Thursday, Nov. 5, 2026, to discuss our third quarter financial results. The event will also include an update to the Company’s financial outlook along with other developments. François Poirier, TC Energy President and Chief Executive Officer; Sean O’Donnell, Executive Vice-President and Chief Financial Officer and other members of the executive leadership team will discuss the financial results as well as the Company’s strategic priorities, long-term outlook and growth objectives at 8:30 a.m. ET / 7:30 a.m. ABT. Members of the investment community and other interested parties are invited to participate by calling 1-800-990-2777 (North America toll free) or 1-416-855-9085 (International toll). Conference ID: 20408. Please dial in 15 minutes prior to the start of the call. A live video webcast of the teleconference will be available on TC Energy’s website at TC Energy — Events and presentations or via the following URL: https://meetings.lumiconnect.com/400-800-630-944. The webcast will be available for replay following the meeting. The unaudited interim Condensed consolidated financial statements and Management’s Discussion and Analysis (MD&A) are available on our website at www.TCEnergy.com and will be filed today under TC Energy's profile on SEDAR+ at www.sedarplus.ca and with the U.S. Securities and Exchange Commission on EDGAR at www.sec.gov. About TC Energy W e a r e a l e a d e r i n N o r t h A m e r i c a n e n e r g y i n f r a s t r u c t u r e , s p a n n i n g C a n a d a , t h e U . S . a n d M e x i c o . F o r o v e r 7 5 y e a r s , w e h a v e p r o u d l y c o n n e c t e d t h e w o r l d t o t h e e n e r g y i t n e e d s . E v e r y d a y , w e m o v e m o r e t h a n 3 0 p e r c e n t o f t h e n a t u r a l g a s u s e d a c r o s s t h e c o n t i n e n t a n d c o n n e c t L N G e x p o r t s t o g l o b a l m a r k e t s — p o w e r i n g c o m m u n i t i e s a n d i n d u s t r i e s . C o m p l e m e n t e d b y s t r a t e g i c o w n e r s h i p a n d l o w - r i s k i n v e s t m e n t s i n p o w e r g e n e r a t i o n , o u r i n f r a s t r u c t u r e d e l i v e r s a f f o r d a b l e , r e l i a b l e a n d s u s t a i n a b l e e n e r g y a c r o s s N o r t h A m e r i c a . W e c a r r y f o r w a r d a l e g a c y o f n a t i o n ‑ b u i l d i n g e n e r g y i n f r a s t r u c t u r e a n d s t r o n g p a r t n e r s h i p s . B y w o r k i n g w i t h c o m m u n i t i e s , b u s i n e s s e s a n d l e a d e r s a c r o s s o u r e x t e n s i v e e n e r g y n e t w o r k , w e c r e a t e o p p o r t u n i t i e s t o d a y a n d f o r g e n e r a t i o n s t o c o m e . TC Energy’s common shares trade on the Toronto (TSX) and New York (NYSE) stock exchanges under the symbol TRP. To learn more, visit us at TCEnergy.com.
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Forward-Looking Information This release includes certain forward-looking information, including future oriented financial information or financial outlook, which is intended to help current and potential investors 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. Our forward-looking information in this release includes, but is not limited to, statements related to: expectations with respect to our 2026 and 2027 comparable EBITDA outlooks, our 2031 comparable EBITDA outlook and the expected five-year comparable EBITDA compound annual growth rate from 2026 to 2031, comparable earnings in total and per common share, including our expectation that 2026 comparable EPS will be higher than 2025, and the sources and drivers thereof, expectations with respect to anticipated 2026 and 2027 capital expenditures and net capital expenditures and the timing thereof, expectations with respect to identified approved and future projects and associated capital expenditures, build multiples, contractual underpinnings, timelines, in-service dates, and outcomes, expectations with respect to the commercial structure, project execution, project-level financing and our committed equity contribution for the Coastal GasLink Phase 2 Expansion, expectations with respect to the approximate value of projects pending approval and opportunities in origination and our ability to convert such opportunities into sanctioned projects, expectations with respect to completed projects and transactions and expected impacts thereof, expectations on rate case settlements, including FERC approval of the GTN Stipulation and Agreement of Settlement, and timing of approved settlement terms, expectations with respect to the approximate value of projects to be placed in-service, expectations with respect to our strategic priorities, and the execution thereof, expectation on the value of and risk profile of our incremental growth projects, expectations with respect to our ability to maximize the value of our assets through safety and operational excellence, expectations regarding financial ratio targets such as debt-to-EBITDA, including maintaining debt-to-EBITDA below our 4.75 times long-term target, expectations with respect to our environmental and sustainability targets, including our methane emissions intensity reduction target, expectations on long-term value creation, expected cost and schedules for planned projects, including projects under construction and in development, expectations about energy demand levels and drivers thereof, including expected growth in natural gas demand and power demand, and our ability to meet expected energy demand, expectations regarding the competitive positioning and long-term value contribution of specific assets and our ability to capture growth opportunities, expectations about our ability to execute our identified portfolio of growth projects and ensure financial strength and agility, our ability to deliver low-risk, solid growth and repeatable performance, expected industry, market and economic conditions, and ongoing trade negotiations, including their expected impact on our business, customers and suppliers. Our forward-looking information is based on certain key assumptions and is subject to risks and uncertainties, including but not limited to: our ability to sanction and complete projects pending approval and to convert opportunities in origination into sanctioned projects at targeted build multiples; our ability to execute long-term commercial contracts, including take-or-pay and capacity contracts, on acceptable terms and within expected timeframes; the timing, cost and completion of capital projects; the availability of project-level financing; the timing and outcome of rate case settlements and the receipt of regulatory and permitting approvals; growth in natural gas and power demand; our ability to maintain credit ratings and financial ratios consistent with our targets; foreign exchange rates, interest rates, tax rates and inflation; and industry, market, economic and trade conditions over the five-year outlook period. All forward-looking statements reflect TC Energy's beliefs and assumptions based on information available at the time the statements were made and as such are not guarantees of future performance. 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 information due to new information or future events, unless we are required to by law. For additional information on the assumptions made, and the risks and uncertainties which could cause actual results to differ from the anticipated results, refer to the most recent Quarterly Report to Shareholders and the 2025 Annual Report filed under TC Energy's profile on SEDAR+ at www.sedarplus.ca and with the U.S. Securities and Exchange Commission at www.sec.gov and
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the "Forward-looking information" section of our Report on Sustainability which is available on our website at www.TCEnergy.com.
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Non-GAAP and Supplementary Financial Measure This release contains references to the following non-GAAP measures: comparable EBITDA, comparable EBITDA CAGR, comparable earnings, comparable earnings per common share and comparable funds generated from operations. It also contains references to debt-to-EBITDA, a non-GAAP ratio, which is calculated using adjusted debt and adjusted comparable EBITDA, each of which are non-GAAP measures. These non-GAAP 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 non-GAAP measures are calculated by adjusting certain GAAP measures for specific items we believe are significant but not reflective of our underlying operations in the period. These comparable measures are calculated on a consistent basis from period to period and are adjusted for specific items in each period, as applicable except as otherwise described in the Condensed consolidated financial statements and MD&A. Refer to: (i) each business segment for a reconciliation of comparable EBITDA to segmented earnings (losses); (ii) Consolidated results section for reconciliations of comparable earnings and comparable earnings per common share to Net income attributable to common shares and Net income per common share, respectively; and (iii) Financial condition section for a reconciliation of comparable funds generated from operations to Net cash provided by operations. With respect to comparable EBITDA CAGR, it represents the compound annual growth rate in comparable EBITDA over the applicable period, calculated using beginning-period and ending-period comparable EBITDA. Refer to the Non-GAAP Measures section of the MD&A in our most recent quarterly report for more information about the non-GAAP measures we use. The MD&A is included with, and forms part of, this release. The MD&A can be found on SEDAR+ at www.sedarplus.ca under TC Energy's profile. With respect to non-GAAP measures used in the calculation of debt-to-EBITDA, adjusted debt is defined as the sum of Reported total debt, including Notes payable, Long-term debt, Current portion of long-term debt and Junior subordinated notes, as reported on our Consolidated balance sheet as well as Operating lease liabilities recognized on our Consolidated balance sheet and 50 per cent of Preferred shares as reported on our Consolidated balance sheet due to the debt-like nature of their contractual and financial obligations, less Cash and cash equivalents as reported on our Consolidated balance sheet and 50 per cent of Junior subordinated notes as reported on our Consolidated balance sheet due to the equity-like nature of their contractual and financial obligations. Adjusted comparable EBITDA is calculated as the sum of comparable EBITDA from continuing operations and comparable EBITDA from discontinued operations excluding Operating lease costs recorded in Plant operating costs and other in our Consolidated statement of income and adjusted for Distributions received in excess of (income) loss from equity investments and a Loan from affiliate as reported in our Consolidated statement of cash flows which we believe is more reflective of the cash flows available to TC Energy to service our debt and other long-term commitments. Beginning in 2025, we entered into a subordinated demand revolving credit facility to borrow funds from the Sur de Texas joint venture and received proceeds totaling $111 million during the year. We believe that debt-to-EBITDA provides investors with useful information as it reflects our ability to service our debt and other long-term commitments. See the Reconciliation section for reconciliations of adjusted debt and adjusted comparable EBITDA for the years ended Dec. 31, 2023, 2024 and 2025. This release contains references to build multiple, which is a non-GAAP ratio which is calculated using capital expenditures and comparable EBITDA, of which comparable EBITDA is a non-GAAP measure. We believe build multiple provides investors with a useful measure to evaluate capital projects. This release also contains references to net capital expenditures, which is a supplementary financial measure. Net capital expenditures represent 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.
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Reconciliation The following is a reconciliation of adjusted debt and adjusted comparable EBITDA1. year ended December 31 (millions of Canadian $) 2025 2024 2023 Reported total debt 60,086 59,366 63,201 Management adjustments: Debt treatment of preferred shares2 1,128 1,250 1,250 Equity treatment of junior subordinated notes3 (6,047) (5,524) (5,144) Cash and cash equivalents (168) (801) (3,678) Operating lease liabilities 431 511 457 Adjusted debt 55,430 54,802 56,086 Comparable EBITDA from continuing operations4 10,952 10,049 9,472 Comparable EBITDA from discontinued operations4 — 1,145 1,516 Operating lease cost 112 117 105 Distributions received in excess of (income) loss from equity investments 342 67 (123) Loan from affiliate 111 — — Adjusted Comparable EBITDA 11,517 11,378 10,970 Adjusted Debt/Adjusted Comparable EBITDA1 4.8 4.8 5.1 1 Adjusted debt and adjusted comparable EBITDA are non-GAAP measures. The calculations are based on management methodology. Individual rating agency calculations will differ. 2 50 per cent debt treatment on $2.3 billion of preferred shares as of Dec. 31, 2025. 3 50 per cent equity treatment on $12.1 billion of junior subordinated notes as of Dec. 31, 2025. U.S. dollar-denominated notes translated at Dec. 31, 2025, USD/CAD foreign exchange rate of 1.37. 4 Comparable EBITDA from continuing operations and Comparable EBITDA from discontinued operations are non-GAAP financial measures. See the Forward-looking information and Non-GAAP measures sections in our 2025 Annual Report for more information. Comparable EBITDA from discontinued operations represents nine months of Liquids Pipelines earnings in 2024 compared to a full year of earnings in 2023. Refer to the Discontinued operations section in our 2024 Annual Report for additional information. Media Inquiries: Media Relations media@tcenergy.com 403.920.7859 or 800.608.7859 Investor & Analyst Inquiries: Investor Relations investor_relations@tcenergy.com 403.920.7911 or 800.361.6522
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Quarterly report to shareholders Third quarter 2026 Management’s discussion and analysis November 3, 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 and nine months ended September 30, 2026 and should be read with the accompanying unaudited Condensed consolidated financial statements for the three and nine months ended September 30, 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. 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. Refer to our 2025 Annual Report and the Discontinued operations section for additional information. TC Energy Third Quarter 2026 | 1
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FORWARD-LOOKING INFORMATION We disclose forward-looking information to help the reader understand management's assessment of our future plans and financial outlook and our future prospects overall. Statements that are forward looking are based on certain assumptions and on what we know and expect today and generally include words like anticipate, expect, believe, may, will, should, estimate or other similar words. Forward-looking statements in this MD&A include information about the following, among other things: • our financial and operational performance, including the performance of our subsidiaries • expectations about strategies and goals for growth and expansion, including acquisitions • expected cash flows and future financing options available along with portfolio management • expectations regarding the size, structure, timing, conditions and outcome of ongoing and future transactions • expected dividend growth • expected access to and cost of capital • expected energy demand levels • expected costs and schedules for planned projects, including projects under construction and in development • expected capital expenditures, contractual obligations, commitments and contingent liabilities, including environmental remediation costs • expected regulatory processes and outcomes • expected outcomes with respect to legal proceedings, including arbitration and insurance claims • expected impact of future tax and accounting changes • commitments and targets contained in our Report on Sustainability, including statements related to our GHG emissions reduction targets, such as our methane emissions intensity target • expected industry, market and economic conditions, and ongoing trade negotiations, including their impact on our customers and suppliers. Forward-looking statements do not guarantee future performance. Actual events and results could be significantly different because of assumptions, risks or uncertainties related to our business or events that happen after the date of this MD&A. Our forward-looking information is based on the following key assumptions and subject to the following risks and uncertainties: Assumptions • realization of expected impacts from acquisitions and divestitures • regulatory decisions and outcomes • planned and unplanned outages and the utilization of our pipelines, power and storage assets • integrity and reliability of our assets • anticipated construction costs, schedules and completion dates • access to capital markets, including portfolio management • expected industry, market and economic conditions, including the impact of these on our customers and suppliers • inflation rates, commodity and labour prices • interest, tax and foreign exchange rates • nature and scope of hedging activities. 2 | TC Energy Third Quarter 2026
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Risks and uncertainties • realization of expected impacts from acquisitions and divestitures • our ability to successfully implement our strategic priorities and whether they will yield the expected benefits • our ability to implement a capital allocation strategy aligned with maximizing shareholder value • operating performance of our pipelines, power generation and storage assets • amount of capacity sold and rates achieved in our pipeline businesses • amount of capacity payments and revenues from power generation assets due to plant availability • production levels within supply basins • construction and completion of capital projects • cost, availability of, and inflationary pressures on, labour, equipment and materials • availability and market prices of commodities • access to capital markets on competitive terms • interest, tax and foreign exchange rates • performance and credit risk of our counterparties • regulatory decisions and outcomes of legal proceedings, including arbitration and insurance claims • our ability to effectively anticipate and assess changes to government policies and regulations, including those related to the environment • our ability to realize the value of tangible assets and contractual recoveries • competition in the businesses in which we operate • unexpected or unusual weather • acts of civil disobedience • cybersecurity and technological developments • sustainability-related risks including climate-related risks and the impact of energy transition on our business • economic and political conditions, and ongoing trade negotiations in North America, as well as globally • global health crises, such as pandemics and epidemics, and the impacts related thereto. You can read more about these factors and others in 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. FOR MORE INFORMATION You can find more information about TC Energy in our Annual Information Form and other disclosure documents, which are available on SEDAR+ (www.sedarplus.ca). TC Energy Third Quarter 2026 | 3
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Financial highlights We use certain financial measures that do not have a standardized meaning under GAAP because we believe they improve our ability to compare results between reporting periods and enhance understanding of our operating performance. Known as non-GAAP measures, they may not be comparable to similar measures provided by other companies. Comparable EBITDA, comparable earnings and comparable earnings per common share from continuing and discontinued operations and comparable funds generated from operations are all non-GAAP measures. Refer to 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. three months ended September 30 nine months ended September 30 (millions of $, except per share amounts) 2026 2025 2026 2025 Income Revenues 4,030 3,704 11,848 11,071 Net income (loss) attributable to common shares 1,026 609 2,912 2,420 from continuing operations 1,026 813 2,912 2,653 from discontinued operations — (204) — (233) Net income (loss) per common share – basic $0.98 $0.58 $2.79 $2.33 from continuing operations $0.98 $0.78 $2.79 $2.55 from discontinued operations — ($0.20) — ($0.22) Comparable EBITDA1 3,004 2,654 9,040 7,988 from continuing operations 3,004 2,654 9,040 7,988 from discontinued operations — — — — Comparable earnings1 983 805 2,998 2,636 from continuing operations 983 805 2,998 2,636 from discontinued operations — — — — Comparable earnings per common share1 $0.94 $0.77 $2.88 $2.53 from continuing operations $0.94 $0.77 $2.88 $2.53 from discontinued operations — — — — Dividends declared per common share $0.8775 $0.85 $2.6325 $2.55 Basic common shares outstanding (millions) – weighted average for the period 1,042 1,040 1,042 1,040 – issued and outstanding at end of period 1,042 1,041 1,042 1,041 1 Additional information on the most directly comparable GAAP measure can be found in the Non-GAAP measures section. 4 | TC Energy Third Quarter 2026
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three months ended September 30 nine months ended September 30 (millions of $) 2026 2025 2026 2025 Cash flows Net cash provided by operations1 1,782 1,920 6,602 5,452 Comparable funds generated from operations2 2,236 1,790 6,568 5,703 Capital spending3 1,412 1,506 3,842 4,694 1 Includes continuing and discontinued operations, refer to the Financial condition section for additional information. 2 Additional information on the most directly comparable GAAP measure can be found in the Non-GAAP measures section. 3 Capital 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. TC Energy Third Quarter 2026 | 5
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Consolidated results three months ended September 30 nine months ended September 30 (millions of $, except per share amounts) 2026 2025 2026 2025 Canadian Natural Gas Pipelines 531 533 1,585 1,600 U.S. Natural Gas Pipelines 1,013 801 3,080 2,817 Mexico Natural Gas Pipelines 411 407 1,197 809 Power and Energy Solutions 308 190 749 637 Corporate (1) (3) (5) (15) Total segmented earnings (losses) 2,262 1,928 6,606 5,848 Interest expense (883) (847) (2,580) (2,534) Allowance for funds used during construction 64 55 163 417 Foreign exchange gains (losses), net (4) 30 41 142 Interest income and other 91 47 158 147 Income (loss) from continuing operations before income taxes 1,530 1,213 4,388 4,020 Income tax (expense) recovery from continuing operations (312) (245) (873) (875) Net income (loss) from continuing operations 1,218 968 3,515 3,145 Net income (loss) from discontinued operations, net of tax — (204) — (233) Net income (loss) 1,218 764 3,515 2,912 Net (income) loss attributable to non-controlling interests (164) (127) (518) (408) Net income (loss) attributable to controlling interests 1,054 637 2,997 2,504 Preferred share dividends (28) (28) (85) (84) Net income (loss) attributable to common shares 1,026 609 2,912 2,420 Net income (loss) per common share – basic $0.98 $0.58 $2.79 $2.33 from continuing operations $0.98 $0.78 $2.79 $2.55 from discontinued operations — ($0.20) — ($0.22) three months ended September 30 nine months ended September 30 (millions of $) 2026 2025 2026 2025 Amounts attributable to common shares Net income (loss) from continuing operations 1,218 968 3,515 3,145 Net (income) loss attributable to non-controlling interests (164) (127) (518) (408) Net income (loss) attributable to controlling interests from continuing operations 1,054 841 2,997 2,737 Preferred share dividends (28) (28) (85) (84) Net income (loss) attributable to common shares from continuing operations 1,026 813 2,912 2,653 Net income (loss) from discontinued operations, net of tax — (204) — (233) Net income (loss) attributable to common shares 1,026 609 2,912 2,420 Net income (loss) attributable to common shares from continuing operations increased by $213 million or $0.20 per common share and $259 million or $0.24 per common share for the three and nine months ended September 30, 2026, respectively, compared to the same periods in 2025. 6 | TC Energy Third Quarter 2026
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NON-GAAP MEASURES This MD&A references non-GAAP measures, which are identified in the table below. These measures do not have any standardized meaning as prescribed by GAAP and therefore may not be comparable to similar measures presented by other entities. These measures are reviewed regularly by our President and Chief Executive Officer, management and the Board of Directors in assessing our performance and making decisions regarding the ongoing operations of our business and its ability to generate cash flows. Some or all of these measures may also be used by investors and other external users of our financial statements as a supplemental measure to provide decision-useful information regarding our period-over-period performance and ability to generate earnings that are core to our ongoing operations. Discussions throughout this MD&A on the factors impacting comparable earnings before interest, taxes, depreciation and amortization (comparable EBITDA) and comparable earnings before interest and taxes (comparable EBIT) are consistent with the factors that impact segmented earnings, except where noted otherwise. Comparable measures We calculate comparable measures by adjusting certain GAAP measures for specific items we believe are significant but not reflective of our underlying operations in the period. Except as otherwise described herein, these comparable measures are calculated on a consistent basis from period to period and are adjusted for specific items in each period, as applicable. Our decision to adjust for a specific item in reporting comparable measures is subjective and made after careful consideration. We maintain a consistent approach to adjustments, which generally fall into the categories described below: • by their nature are unusual, infrequent or non-operating, and are separately identifiable from our normal business operations and in our view are not reflective of our underlying operations in the period. Specific items 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 settlements; acquisition, integration and restructuring costs; expected credit loss (ECL) 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. These measures are applicable to our continuing and discontinued operations. Quantitative reconciliations of our comparable measures to their GAAP measures and a discussion of specific adjustments made for the three and nine months ended September 30, 2026 and comparative periods are found throughout this MD&A. Non-GAAP measure GAAP measure comparable EBITDA segmented earnings (losses) comparable EBIT segmented earnings (losses) comparable earnings net income (loss) attributable to common shares comparable earnings per common share net income (loss) per common share funds generated from operations net cash provided by operations comparable funds generated from operations net cash provided by operations TC Energy Third Quarter 2026 | 7
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Comparable EBITDA and comparable EBIT Comparable EBITDA represents segmented earnings (losses) adjusted for specific items described in the Comparable measures section, excluding charges for depreciation and amortization. We use comparable EBITDA as a measure of our earnings from ongoing operations as it is a useful indicator of our performance and is also presented on a consolidated basis. Comparable EBIT represents segmented earnings (losses) adjusted for specific items and is an effective tool for evaluating trends in each segment. Refer to each business segment and the Discontinued operations section for a reconciliation to segmented earnings (losses). Funds generated from operations and comparable funds generated from operations Funds generated from operations reflects net cash provided by operations before changes in operating working capital. The components of changes in working capital are disclosed in 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 and comparable earnings per common share Comparable earnings represents earnings attributable to common shareholders on a consolidated basis, adjusted for specific items described in the Comparable measures section. Comparable earnings is comprised of segmented earnings (losses), Interest expense, AFUDC, Foreign exchange (gains) losses, net, Interest income and other, Income tax expense (recovery), Net income (loss) attributable to non-controlling interests and Preferred share dividends on our 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 and the Discontinued operations section for reconciliations to Net income (loss) attributable to common shares and Net income (loss) per common share for our continuing operations and discontinued operations. Comparable earnings and comparable earnings per common share - from continuing operations The following specific items were recognized in Net income (loss) attributable to common shares from continuing operations and were excluded from comparable earnings from continuing operations: 2026 results • pre-tax unrealized foreign exchange losses, net, of $16 million and pre-tax unrealized foreign exchange gains, net, of $123 million for the three and nine months ended September 30, 2026, 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 • pre-tax earnings of $75 million in third quarter 2026 in connection with the Coastal GasLink Phase 2 Expansion (CGL Phase 2 Expansion) reaching FID. Refer to the Recent Developments – Canadian Natural Gas Pipelines section for additional information • a pre-tax recovery of $36 million in third quarter 2026 representing our proportionate share of a Bruce Power operating cost provision release related to prior periods • pre-tax expenses of $103 million for the nine months ended September 30, 2026 related to third-party settlements • a pre-tax asset impairment charge of $70 million in third quarter 2026 related to the carrying value of certain equipment at our Bécancour cogeneration plant. Refer to the Recent Developments – Power and Energy Solutions section for additional information • a pre-tax expense of $10 million and $15 million for the three and nine months ended September 30, 2026 related to the ECL provision on TGNH net investment in leases, net of non-controlling interest, as well as on certain contract assets in Mexico. 8 | TC Energy Third Quarter 2026
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2025 results • 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 TCPL and 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, related to the ECL provision on TGNH net investment in leases, net of non-controlling interest, as well as on certain contract assets in Mexico. RECONCILIATION OF NET INCOME (LOSS) ATTRIBUTABLE TO COMMON SHARES TO COMPARABLE EARNINGS - FROM CONTINUING OPERATIONS three months ended September 30 nine months ended September 30 (millions of $, except per share amounts) 2026 2025 2026 2025 Net income (loss) attributable to common shares from continuing operations 1,026 813 2,912 2,653 Specific items (pre tax): Foreign exchange (gains) losses, net – intercompany loan1 16 (87) (123) 42 CGL Phase 2 Expansion FID2 (75) — (75) — Bruce Power provision release3 (36) — (36) — Third-party settlements — — 103 — Asset impairment charge4 70 — 70 — Expected credit loss provision on net investment in leases and certain contract assets in Mexico5 10 (12) 15 79 Bruce Power unrealized fair value adjustments 16 (8) 11 (26) Risk management activities6 (53) 114 183 (141) Taxes on specific items7 9 (15) (62) 29 Comparable earnings from continuing operations 983 805 2,998 2,636 Net income (loss) per common share from continuing operations $0.98 $0.78 $2.79 $2.55 Specific items (net of tax) (0.04) (0.01) 0.09 (0.02) Comparable earnings per common share from continuing operations $0.94 $0.77 $2.88 $2.53 1 TCPL 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, n e t o f n o n ‑ c o n t r o l l i n g i n t e r e s t . 2 We recognized certain earnings in connection with the CGL Phase 2 Expansion reaching FID, which we have excluded from comparable measures. Refer to the Recent Developments – Canadian Natural Gas Pipelines section for additional information. 3 Our proportionate share of Bruce Power's release of an operating cost provision accrued from 2021 to 2025, following a waiver of the requirement by Ontario Power Generation. 4 We reduced the carrying value of certain equipment at our Bécancour facility that is no longer expected to be utilized and will be retired and abandoned in place. Refer to the Recent Developments – Power and Energy Solutions section for additional information. 5 We have recognized an ECL 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 TSAs, the latest of which extends through 2055. This provision does not reflect losses or cash outflows from the underlying TSA arrangements 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 14, Risk management and financial instruments, in the Condensed consolidated financial statements for additional information. TC Energy Third Quarter 2026 | 9
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6 Risk management activities three months ended September 30 nine months ended September 30 (millions of $) 2026 2025 2026 2025 U.S. Natural Gas Pipelines 37 8 (58) 66 Canadian Power 1 (50) (86) (72) U.S. Power (5) 2 (1) 4 Natural Gas Storage 35 (7) 85 (27) Interest rate — 1 1 1 Foreign exchange (15) (68) (124) 169 53 (114) (183) 141 Income tax attributable to risk management activities (12) 27 46 (35) Total unrealized gains (losses) from risk management activities 41 (87) (137) 106 7 Refer to the Corporate section for additional information. COMPARABLE EBITDA TO COMPARABLE EARNINGS - FROM CONTINUING OPERATIONS Comparable EBITDA from continuing operations represents segmented earnings (losses) from continuing operations adjusted for the specific items described 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. three months ended September 30 nine months ended September 30 (millions of $, except per share amounts) 2026 2025 2026 2025 Canadian Natural Gas Pipelines 953 913 2,833 2,726 U.S. Natural Gas Pipelines 1,246 1,062 3,961 3,518 Mexico Natural Gas Pipelines 446 416 1,287 968 Power and Energy Solutions 360 266 964 791 Corporate (1) (3) (5) (15) Comparable EBITDA from continuing operations 3,004 2,654 9,040 7,988 Depreciation and amortization (749) (701) (2,209) (2,050) Interest expense included in comparable earnings (883) (848) (2,581) (2,535) Allowance for funds used during construction 64 55 163 417 Foreign exchange gains (losses), net included in comparable earnings 11 22 40 67 Interest income and other included in comparable earnings 16 47 83 147 Income tax (expense) recovery included in comparable earnings (303) (260) (935) (846) Net (income) loss attributable to non-controlling interests included in comparable earnings (149) (136) (518) (468) Preferred share dividends (28) (28) (85) (84) Comparable earnings from continuing operations 983 805 2,998 2,636 Comparable earnings per common share from continuing operations $0.94 $0.77 $2.88 $2.53 10 | TC Energy Third Quarter 2026
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Comparable EBITDA from continuing operations – 2026 versus 2025 Comparable EBITDA from continuing operations increased by $350 million for the three months ended September 30, 2026 compared to the same period in 2025 primarily due to the net result of the following: • increased U.S. dollar-denominated EBITDA in U.S. Natural Gas Pipelines due to additional contract sales and higher earnings from ANR and Columbia Gas, partially offset by lower contract sales on GTN • increased EBITDA in Power and Energy Solutions primarily due to higher contributions from Bruce Power resulting from a higher contract price and increased generation following the return to service of Unit 3 from its Major Component Replacement (MCR) outage • increased EBITDA in Canadian Natural Gas Pipelines mainly due to higher flow-through depreciation on the NGTL System and Canadian Mainline • increased U.S. dollar-denominated EBITDA in Mexico Natural Gas Pipelines due to higher equity earnings from Sur de Texas as a result of peso-denominated financial exposure • a positive foreign exchange impact from a stronger U.S. dollar on the Canadian dollar equivalent of comparable EBITDA from our U.S. dollar-denominated operations, which was translated at a rate of 1.40 in 2026 versus 1.38 in 2025. Refer to the Foreign exchange section for additional information. Comparable EBITDA from continuing operations increased by $1,052 million for the nine months ended September 30, 2026 compared to the same period in 2025 primarily due to the net result of the following: • increased U.S. dollar-denominated EBITDA in U.S. Natural Gas Pipelines due to additional contract sales and higher earnings from ANR and Columbia Gas, partially offset by lower margins in our U.S. natural gas marketing business and lower contract sales on GTN • increased U.S. dollar-denominated EBITDA in Mexico Natural Gas Pipelines due to higher earnings from 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 EBITDA in Power and Energy Solutions primarily due to higher contributions from Bruce Power resulting from a higher contract price and increased generation following the return to service of Unit 3 from its MCR outage • increased EBITDA in Canadian Natural Gas Pipelines mainly due to higher flow-through depreciation on the NGTL System and Canadian Mainline and higher incentive earnings on the NGTL System, partially offset by lower flow-through income taxes on the Canadian Mainline and lower equity earnings from Coastal GasLink • a negative foreign exchange impact from a weakening U.S. dollar on the Canadian dollar equivalent of comparable EBITDA from our U.S. dollar-denominated operations, which was translated at a rate of 1.38 in 2026 versus 1.40 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 from continuing operations – 2026 versus 2025 Comparable earnings increased by $178 million or $0.17 per common share for the three months ended September 30, 2026 compared to the same period in 2025 primarily due to the net effect of the following: • changes in comparable EBITDA described above • higher depreciation and amortization primarily due to assets placed in service on the Canadian Mainline and NGTL System, higher depreciation rates on the NGTL System as well as depreciation rate changes associated with the Columbia Gas Settlement • higher income tax expense primarily due to changes in geographic and business mix of earnings, partially offset by the impact of our Mexico foreign exchange exposure and lower flow-through income taxes • higher interest expense primarily due to long-term debt issuances and maturities • lower interest income and other due to lower income from restricted investments TC Energy Third Quarter 2026 | 11
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• higher net income attributable to non-controlling interests primarily due to higher net income recognized from the Columbia Gas and Columbia Gulf assets • risk management activities used to manage our foreign exchange exposure to net liabilities in Mexico and to U.S. dollar- denominated income and the revaluation of our peso-denominated net monetary liabilities to U.S. dollars • higher AFUDC primarily due to capital expenditures on our U.S. natural gas pipeline projects. Comparable earnings increased by $362 million or $0.35 per common share for the nine months ended September 30, 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 in second quarter 2025 • higher depreciation and amortization primarily due to assets placed in service on the Canadian Mainline and NGTL System, higher depreciation rates on the NGTL System as well as depreciation rate changes associated with the Columbia Gas Settlement • higher income tax expense primarily due to changes in geographic and business mix of earnings and higher flow-through income taxes, partially offset by the impact of our Mexico foreign exchange exposure • lower interest income and other due to lower income from restricted investments • higher net income attributable to non-controlling interests primarily due to higher net income recognized from the Columbia Gas and Columbia Gulf assets • higher interest expense primarily due to long-term debt issuances and maturities • 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 U.S. dollar-denominated assets and liabilities to Canadian dollars as well as on our peso-denominated net monetary liabilities to U.S. dollars. 12 | TC Energy Third Quarter 2026
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Supplementary financial measure Net capital expenditures Net capital expenditures represent 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. Outlook Comparable EBITDA and comparable earnings Our overall comparable EBITDA and comparable earnings per common share outlooks for 2026 remain consistent with our 2025 Annual Report. Consolidated capital expenditures Our expected total capital expenditures for 2026 as outlined in our 2025 Annual Report remain materially unchanged. TC Energy Third Quarter 2026 | 13
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Capital program We are developing quality projects under our capital program. These long-life infrastructure assets are supported by long-term commercial arrangements with creditworthy counterparties and/or regulated business models and are expected to generate growth in earnings and cash flows. Our capital program consists of approximately $25 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 nine months ended September 30, 2026, we placed approximately $2.5 billion of projects into service, including natural gas pipeline capacity projects along our extensive North American asset footprint and Bruce Power Unit 3, which was declared commercially operational on June 12, 2026, after its MCR outage. In addition, approximately $1.7 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 progress through key approval 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. 14 | TC Energy Third Quarter 2026
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Secured projects Estimated and incurred project costs referred to in the following table include 100 per cent of the capital expenditures related to projects within entities that we own or partially own and fully consolidate, as well as our share of equity contributions to fund projects within our equity investments. Expected in-service date Estimated project cost Project costs incurred at September 30, 2026(billions of Canadian $, unless otherwise noted) Canadian Natural Gas Pipelines1 NGTL System2 2027 0.5 0.2 2028+ 0.5 — Coastal GasLink Phase 2 Expansion 2030+ 0.2 — Regulated maintenance capital expenditures 2026-2028 2.8 0.7 U.S. Natural Gas Pipelines Heartland project 2027 US 0.9 US 0.2 Northwoods project 2029 US 0.9 — Pulaski, Maysville and Clark projects 2028-2029 US 0.9 US 0.1 Central Virginia Capacity project 2028-2030 US 0.3 — Crossroads Expansion project 2030 US 1.8 — Appalachia Supply project 2030 US 1.5 — Southeast Virginia Energy Storage project 2030 US 0.3 US 0.1 Other capital3 2026-2031 US 1.6 US 0.4 Regulated maintenance capital expenditures 2026-2028 US 2.6 US 0.7 Mexico Natural Gas Pipelines Villa de Reyes – South section4 — US 0.4 US 0.3 Tula5 — US 0.4 US 0.3 Power and Energy Solutions Bruce Power – Unit 4 MCR6 2027 0.9 0.6 Bruce Power – Unit 5 MCR6 2030 1.1 0.3 Bruce Power – life extension7 2026-2031 1.7 0.8 Other Non-recoverable maintenance capital expenditures8 2026-2028 0.5 0.1 19.8 4.8 Foreign exchange impact on secured projects9 4.9 0.9 Total secured projects 24.7 5.7 1 Our share of committed equity to fund the estimated cost of the Coastal GasLink – Cedar Link project is $37 million. 2 Includes amounts related to projects within the Multi-Year Growth Plan (MYGP) that have received FID. 3 Includes capital expenditures related to certain large-scope maintenance projects across our U.S. natural gas footprint due to their discrete nature for regulatory recovery. 4 We 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. 5 Estimated 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. 6 Amounts are net of expected investment tax credits. 7 Reflects amounts to be invested under the Asset Management program to 2028, other life extension projects and the incremental uprate initiative. 8 Includes non-recoverable maintenance capital expenditures from all segments and is primarily related to our Power and Energy Solutions and Corporate assets. 9 Reflects U.S./Canada foreign exchange rate of 1.42 at September 30, 2026. TC Energy Third Quarter 2026 | 15
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Canadian Natural Gas Pipelines The following is a reconciliation of comparable EBITDA and comparable EBIT (our non-GAAP measures) to segmented earnings (losses) (the most directly comparable GAAP measure). three months ended September 30 nine months ended September 30 (millions of $) 2026 2025 2026 2025 NGTL System 659 649 1,995 1,925 Canadian Mainline 217 193 621 572 Other Canadian pipelines1 77 71 217 229 Comparable EBITDA 953 913 2,833 2,726 Depreciation and amortization (422) (380) (1,248) (1,126) Comparable EBIT and Segmented earnings (losses) 531 533 1,585 1,600 1 Includes 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 $2 million and $15 million for the three and nine months ended September 30, 2026 compared to the same periods 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 AND AVERAGE INVESTMENT BASE three months ended September 30 nine months ended September 30 (millions of $) 2026 2025 2026 2025 Net income NGTL System 198 200 604 597 Canadian Mainline 67 62 189 185 Average investment base NGTL System 18,995 19,319 Canadian Mainline 3,775 3,713 Net income for the NGTL System for the three months ended September 30, 2026 was generally consistent with the same period in 2025, and increased by $7 million for the nine months ended September 30, 2026 compared to the same period in 2025 primarily due to higher incentive earnings, partially offset by lower average investment base. 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 an incentive for certain operating costs where variances from projected amounts and emissions savings are shared with customers. 16 | TC Energy Third Quarter 2026
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Net income for the Canadian Mainline increased by $5 million and $4 million for the three and nine months ended September 30, 2026 compared to the same periods in 2025 mainly as a result of higher incentive earnings and higher average investment base. The Canadian Mainline is operating under the 2021-2026 Mainline Settlement, which includes an approved ROE of 10.1 per cent on 40 per cent deemed common equity and an incentive to decrease costs and increase revenues on the pipeline under a beneficial sharing mechanism with our customers. COMPARABLE EBITDA Comparable EBITDA for Canadian Natural Gas Pipelines increased by $40 million and $107 million for the three and nine months ended September 30, 2026 compared to the same periods in 2025 due primarily to the net effect of: • higher flow-through depreciation and higher incentive earnings on the NGTL System • higher flow-through depreciation, partially offset by lower flow-through income taxes on the Canadian Mainline • lower equity earnings from Coastal GasLink for the nine months ended September 30, 2026. DEPRECIATION AND AMORTIZATION Depreciation and amortization increased by $42 million and $122 million for the three and nine months ended September 30, 2026 compared to the same periods in 2025 mainly due to assets placed in service on the Canadian Mainline and higher depreciation rates and expansion facilities placed in service on the NGTL System. TC Energy Third Quarter 2026 | 17
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U.S. Natural Gas Pipelines The following is a reconciliation of comparable EBITDA and comparable EBIT (our non-GAAP measures) to segmented earnings (losses) (the most directly comparable GAAP measure). three months ended September 30 nine months ended September 30 (millions of US$, unless otherwise noted) 2026 2025 2026 2025 Columbia Gas1 435 416 1,424 1,300 ANR 229 133 698 466 Columbia Gulf1 66 60 235 176 Great Lakes 37 33 143 142 GTN 41 65 136 187 Other U.S. pipelines2 82 63 226 239 Comparable EBITDA 890 770 2,862 2,510 Depreciation and amortization (193) (196) (570) (549) Comparable EBIT 697 574 2,292 1,961 Foreign exchange impact 279 219 879 790 Comparable EBIT (Cdn$) 976 793 3,171 2,751 Specific items: Third-party settlements — — (33) — Risk management activities 37 8 (58) 66 Segmented earnings (losses) (Cdn$) 1,013 801 3,080 2,817 1 Includes non-controlling interest. Refer to the Corporate section for additional information. 2 Reflects 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 increased by $212 million and $263 million for the three and nine months ended September 30, 2026 compared to the same periods 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 a third-party settlement from the resolution of a certain legal matter in our U.S. Natural Gas Pipelines segment in first quarter 2026 • unrealized gains and losses from changes in the fair value of derivatives used in our U.S. natural gas marketing business. A stronger U.S. dollar for the three months ended September 30, 2026 had a positive impact on the Canadian dollar equivalent segmented earnings from our U.S. dollar-denominated operations compared to the same period in 2025, while a weaker U.S. dollar for the nine months ended September 30, 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. 18 | TC Energy Third Quarter 2026
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Comparable EBITDA for U.S. Natural Gas Pipelines increased by US$120 million and US$352 million for the three and nine months ended September 30, 2026 compared to the same periods in 2025 primarily due to the net effect of: • a net increase in earnings from ANR as a result of higher transportation rates effective November 1, 2025 and adjustments related to the ANR Settlement as well as additional contract sales. Refer to the Recent Developments – U.S. Natural Gas Pipelines section for additional information • 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 • 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 contract sales in 2026 compared to 2025 on GTN • 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 Depreciation and amortization decreased by US$3 million for the three months ended September 30, 2026 and increased by US$21 million for the nine months ended September 30, 2026 compared to the same periods in 2025 primarily due to new projects placed in service and depreciation rate changes as a result of the Columbia Gas Settlement, partially offset by a depreciation rate decrease as a result of the ANR Settlement. Refer to the Recent Developments – U.S. Natural Gas Pipelines section for additional information. TC Energy Third Quarter 2026 | 19
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Mexico Natural Gas Pipelines The following is a reconciliation of comparable EBITDA and comparable EBIT (our non-GAAP measures) to segmented earnings (losses) (the most directly comparable GAAP measure). three months ended September 30 nine months ended September 30 (millions of US$, unless otherwise noted) 2026 2025 2026 2025 TGNH1,2 190 209 606 432 Sur de Texas3 52 24 111 51 Topolobampo 39 39 117 117 Guadalajara 21 14 47 45 Mazatlán 16 17 48 51 Comparable EBITDA 318 303 929 696 Depreciation and amortization (17) (18) (53) (52) Comparable EBIT 301 285 876 644 Foreign exchange impact 121 108 338 252 Comparable EBIT (Cdn$) 422 393 1,214 896 Specific item: Expected credit loss provision on net investment in leases and certain contract assets in Mexico2 (11) 14 (17) (87) Segmented earnings (losses) (Cdn$) 411 407 1,197 809 1 Includes the operating sections of the Tamazunchale, Villa de Reyes, Tula and Southeast Gateway pipelines. 2 Includes non-controlling interest. Refer to the Corporate section for additional information. 3 Represents 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 $4 million and $388 million for the three and nine months ended September 30, 2026 compared to the same periods in 2025 and included an expense of $11 million and $17 million, respectively (2025 – recovery of $14 million and expense of $87 million, respectively) related to the ECL provision on 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 stronger U.S. dollar for the three months ended September 30, 2026 had a positive impact on the Canadian dollar equivalent segmented earnings from our U.S. dollar-denominated operations compared to the same period in 2025, while a weaker U.S. dollar for the nine months ended September 30, 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. Comparable EBITDA for Mexico Natural Gas Pipelines increased by US$15 million and US$233 million for the three and nine months ended September 30, 2026 compared to the same periods in 2025, due to the net effect of: • lower earnings in TGNH for the three months ended September 30, 2026 due to higher operating costs. Higher earnings in TGNH for the nine months ended September 30, 2026 primarily due to the completion of the Southeast Gateway pipeline in second quarter 2025 • higher equity earnings from Sur de Texas primarily due to the foreign exchange impacts on the revaluation of peso-denominated liabilities as well as lower income tax expense and lower interest expense. 20 | TC Energy Third Quarter 2026
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DEPRECIATION AND AMORTIZATION Depreciation and amortization was generally consistent for the three and nine months ended September 30, 2026 compared to the same periods in 2025. Under sales-type lease accounting, our in-service TGNH pipeline assets are derecognized from Plant, property and equipment and recorded as a net investment in lease on our Condensed consolidated balance sheet with no depreciation expense being recognized. SUR DE TEXAS Sur de Texas results reflect equity income from our 60 per cent interest and fees earned from the construction and operation of the pipeline. We use foreign exchange derivatives to manage Sur de Texas' foreign exchange exposures, and the impact of these derivatives is recognized in Foreign exchange (gains) losses, net in the Condensed consolidated statement of income. Refer to the Foreign exchange section for additional information. The following table details our proportionate share of equity income and the foreign exchange impact on Sur de Texas equity earnings from changes in the value of the Mexican peso against the U.S. dollar: three months ended September 30 nine months ended September 30 (millions of US$) 2026 2025 2026 2025 Equity income before foreign exchange impact 38 35 111 100 Foreign exchange impact included in equity earnings 14 (11) — (49) Comparable EBITDA - Sur de Texas 52 24 111 51 TC Energy Third Quarter 2026 | 21
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Power and Energy Solutions The following is a reconciliation of comparable EBITDA and comparable EBIT (our non-GAAP measures) to segmented earnings (losses) (the most directly comparable GAAP measure). three months ended September 30 nine months ended September 30 (millions of $) 2026 2025 2026 2025 Bruce Power1 313 213 754 578 Canadian Power 36 30 140 145 Natural Gas Storage and other2 11 23 70 68 Comparable EBITDA 360 266 964 791 Depreciation and amortization (33) (29) (98) (85) Comparable EBIT 327 237 866 706 Specific items: Third-party settlements — — (70) — Asset impairment charge (70) — (70) — Bruce Power provision release 36 — 36 — Bruce Power unrealized fair value adjustments (16) 8 (11) 26 Risk management activities 31 (55) (2) (95) Segmented earnings (losses) 308 190 749 637 1 Represents our share of equity income from Bruce Power. 2 Includes 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 $118 million and $112 million for the three and nine months ended September 30, 2026 compared to the same periods 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 $70 million related to a third-party contractual settlement in our Power and Energy Solutions segment in second quarter 2026 • a pre-tax asset impairment charge of $70 million related to the carrying value of certain equipment at our Bécancour cogeneration plant. Refer to the Recent Developments – Power and Energy Solutions section for additional information • a pre-tax recovery of $36 million, representing our proportionate share of a Bruce Power operating cost provision release related to prior periods • 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. 22 | TC Energy Third Quarter 2026
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Comparable EBITDA for Power and Energy Solutions increased by $94 million and $173 million for the three and nine months ended September 30, 2026 compared to the same periods in 2025 primarily due to the net effect of: • increased Bruce Power contributions primarily due to a higher contract price, increased generation partially from the return of Unit 3 from its MCR outage, and higher realized gains on funds invested for post-retirement benefits, partially offset by increased depreciation, operating and finance costs. Refer to the Bruce Power results section for additional information • lower Natural Gas Storage and other results for the three months ended September 30, 2026 reflecting decreased realized natural gas storage spreads. For the nine months ended September 30, 2026, lower business development costs were offset by decreased contributions from our U.S. marketing business • higher Canadian Power financial results for the three months ended September 30, 2026 primarily due to increased generation from our Alberta cogeneration assets and higher power prices. Lower financial results for the nine months ended September 30, 2026 primarily due to reduced contributions from our Canadian Power marketing business. DEPRECIATION AND AMORTIZATION Depreciation and amortization increased by $4 million and $13 million for the three and nine months ended September 30, 2026 compared to the same periods in 2025 as a result of higher depreciation rates on our Alberta cogeneration assets. BRUCE POWER The following is our proportionate share of the components of comparable EBITDA and comparable EBIT. three months ended September 30 nine months ended September 30 (millions of $, unless otherwise noted) 2026 2025 2026 2025 Items included in comparable EBITDA and comparable EBIT are comprised of: Revenues1 696 546 1,877 1,610 Operating expenses (253) (236) (794) (748) Depreciation and other (130) (97) (329) (284) Comparable EBITDA and comparable EBIT2 313 213 754 578 Bruce Power – other information Plant availability3,4 97% 94% 95% 93% Planned outage days4 12 11 73 76 Unplanned outage days 7 21 10 44 Sales volumes (GWh)5 5,852 4,885 15,798 14,626 Realized power price per MWh6 $118 $111 $117 $109 1 Net of amounts recorded to reflect operating cost efficiencies shared with the IESO, if applicable. 2 Represents 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, risk management activities and our share of an operating cost provision release related to prior periods. 3 The percentage of time the plant was available to generate power, regardless of whether it was running. 4 Excludes MCR outage days. 5 Sales volumes include deemed generation, if applicable. 6 Calculation 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. The Unit 3 MCR, which began in March 2023, was completed and the unit was declared commercially operational on June 12, 2026, ahead of schedule and within budget. Planned maintenance on Unit 1 began in third quarter 2026 with expected completion in fourth quarter 2026. TC Energy Third Quarter 2026 | 23
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Corporate three months ended September 30 nine months ended September 30 (millions of $) 2026 2025 2026 2025 Segmented earnings (losses) (1) (3) (5) (15) Corporate segmented losses decreased by $2 million and $10 million for the three and nine months ended September 30, 2026 compared to the same periods in 2025 primarily due to lower corporate administrative costs in 2026. INTEREST EXPENSE three months ended September 30 nine months ended September 30 (millions of $) 2026 2025 2026 2025 Interest expense on long-term debt and junior subordinated notes Canadian dollar-denominated (231) (204) (665) (601) U.S. dollar-denominated (426) (424) (1,282) (1,282) Foreign exchange impact (169) (159) (493) (511) (826) (787) (2,440) (2,394) Other interest and amortization expense (59) (63) (148) (148) Capitalized interest 2 2 7 7 Interest expense included in comparable earnings (883) (848) (2,581) (2,535) Specific item: Risk management activities — 1 1 1 Interest expense (883) (847) (2,580) (2,534) Interest expense increased by $36 million for the three months ended September 30, 2026 compared to the same period in 2025 and included nil unrealized gains (2025 – $1 million of unrealized gains) on derivatives used to manage our interest rate risk. Interest expense increased by $46 million for the nine months ended September 30, 2026 compared to the same period in 2025 and included $1 million of unrealized gains (2025 – $1 million of unrealized gains) on derivatives used to manage our interest rate risk, which have 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 $35 million and $46 million for the three and nine months ended September 30, 2026 compared to the same periods in 2025 primarily due to the net effect of: • long-term debt issuances and maturities. Refer to the Financial condition section for additional information • the foreign exchange impact on translation of U.S. dollar-denominated interest expense. 24 | TC Energy Third Quarter 2026
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ALLOWANCE FOR FUNDS USED DURING CONSTRUCTION three months ended September 30 nine months ended September 30 (millions of $) 2026 2025 2026 2025 Canadian dollar-denominated 10 13 30 37 U.S. dollar-denominated 39 30 96 268 Foreign exchange impact 15 12 37 112 Allowance for funds used during construction 64 55 163 417 AFUDC increased by $9 million and decreased by $254 million for the three and nine months ended September 30, 2026 compared to the same periods in 2025. The increase in AFUDC for the three months ended September 30, 2026 is primarily the result of capital expenditures on our U.S. natural gas pipeline projects. The decrease in AFUDC for the nine months ended September 30, 2026 is mainly the result of the completion of the Southeast Gateway pipeline in second quarter 2025. FOREIGN EXCHANGE GAINS (LOSSES), NET three months ended September 30 nine months ended September 30 (millions of $) 2026 2025 2026 2025 Foreign exchange gains (losses), net included in comparable earnings 11 22 40 67 Specific items: Foreign exchange gains (losses), net – intercompany loan1 — 76 125 (94) Risk management activities (15) (68) (124) 169 Foreign exchange gains (losses), net (4) 30 41 142 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 $34 million and $101 million for the three and nine months ended September 30, 2026 compared to the same periods 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 and $27 million for the three and nine months ended September 30, 2026 compared to the same periods 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 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 • 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. TC Energy Third Quarter 2026 | 25
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INTEREST INCOME AND OTHER three months ended September 30 nine months ended September 30 (millions of $) 2026 2025 2026 2025 Canadian dollar-denominated 8 8 16 21 U.S. dollar-denominated 6 28 49 90 Foreign exchange impact 2 11 18 36 Interest income and other included in comparable earnings 16 47 83 147 Specific item: CGL Phase 2 Expansion FID 75 — 75 — Interest income and other 91 47 158 147 Interest income and other increased by $44 million and $11 million for the three and nine months ended September 30, 2026 compared to the same periods in 2025 and included recognition of pre-tax earnings of $75 million in connection with the CGL Phase 2 Expansion reaching FID, which has been removed from our calculation of Interest income and other included in comparable earnings. Refer to the Recent Developments – Canadian Natural Gas Pipelines section for additional information. Interest income and other included in comparable earnings decreased by $31 million and $64 million for the three and nine months ended September 30, 2026 compared to the same periods in 2025 primarily due to: • lower income from restricted investments • lower interest earned on Canadian and U.S. dollar-denominated short-term investments. INCOME TAX (EXPENSE) RECOVERY three months ended September 30 nine months ended September 30 (millions of $) 2026 2025 2026 2025 Income tax (expense) recovery included in comparable earnings (303) (260) (935) (846) Specific items: Foreign exchange gains (losses), net - intercompany loan 6 (7) (6) (13) CGL Phase 2 Expansion FID (18) — (18) — Bruce Power provision release (9) — (9) — Third-party settlements — — 25 — Asset impairment charge 17 — 17 — Expected credit loss provision on net investment in leases and certain contract assets in Mexico 3 (3) 5 26 Bruce Power unrealized fair value adjustments 4 (2) 2 (7) Risk management activities (12) 27 46 (35) Income tax (expense) recovery (312) (245) (873) (875) Income tax expense included in comparable earnings increased by $43 million and $89 million for the three and nine months ended September 30, 2026 compared to the same periods in 2025 primarily due to changes in geographic and business mix of earnings, partially offset by the impact of our Mexico foreign exchange exposure. The increase also reflected lower flow-through income taxes for the three months ended September 30, 2026 and higher flow-through income taxes for the nine months ended September 30, 2026. 26 | TC Energy Third Quarter 2026
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NET (INCOME) LOSS ATTRIBUTABLE TO NON-CONTROLLING INTERESTS Non-controlling interests ownership at September 30, 2026 three months ended September 30 nine months ended September 30 (millions of $) 2026 2025 2026 2025 Columbia Gas and Columbia Gulf 40% (139) (131) (503) (453) TGNH 13.01% (17) (13) (44) (42) Texas Wind Farms1 100% 7 8 29 27 Net (income) loss attributable to non-controlling interests included in comparable earnings (149) (136) (518) (468) Specific items: Foreign exchange (gains) losses, net – intercompany loan (16) 11 (2) 52 Expected credit loss provision on net investment in leases 1 (2) 2 8 Net (income) loss attributable to non-controlling interests (164) (127) (518) (408) 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 $37 million and $110 million for the three and nine months ended September 30, 2026 compared to the same periods 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 non-controlling interest portion of the ECL provision related to the TGNH net investment in leases. Net income attributable to non-controlling interests included in comparable earnings increased by $13 million and $50 million for the three and nine months ended September 30, 2026 compared to the same periods in 2025 primarily due to higher net income from the Columbia Gas and Columbia Gulf assets. PREFERRED SHARE DIVIDENDS three months ended September 30 nine months ended September 30 (millions of $) 2026 2025 2026 2025 Preferred share dividends (28) (28) (85) (84) Preferred share dividends were generally consistent for the three and nine months ended September 30, 2026 compared to the same periods in 2025 primarily due to the offsetting impacts of the redemption of preferred shares in 2025 and dividend rate resets on and conversions of certain series of preferred shares in 2026 and 2025. TC Energy Third Quarter 2026 | 27
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Foreign exchange FOREIGN EXCHANGE RELATED TO U.S. DOLLAR-DENOMINATED OPERATIONS Certain of our businesses generate all or most of their earnings in U.S. dollars and since we report our financial results in Canadian dollars, changes in the value of the U.S. dollar against the Canadian dollar directly affect our comparable EBITDA and may also impact comparable earnings. As our U.S. dollar-denominated operations continue to grow, this exposure increases. A portion of the U.S. dollar-denominated comparable EBITDA exposure is naturally offset by U.S. dollar-denominated amounts below comparable EBITDA within Depreciation and amortization, Interest expense and other income statement line items. A portion of the remaining exposure is actively managed on a rolling forward basis up to three years using foreign exchange derivatives; however, the natural exposure beyond that period remains. The net impact of the U.S. dollar movements on comparable earnings during the three and nine months ended September 30, 2026 after considering natural offsets and economic hedges was not significant. The components of our financial results denominated in U.S. dollars are set out in the table below, including our U.S. Natural Gas Pipelines and Mexico Natural Gas Pipelines operations. Comparable EBITDA is a non-GAAP measure. PRE-TAX U.S. DOLLAR-DENOMINATED INCOME AND EXPENSE ITEMS three months ended September 30 nine months ended September 30 (millions of US$) 2026 2025 2026 2025 Comparable EBITDA U.S. Natural Gas Pipelines 890 770 2,862 2,510 Mexico Natural Gas Pipelines 318 303 929 696 1,208 1,073 3,791 3,206 Depreciation and amortization (210) (214) (623) (601) Interest expense on long-term debt and junior subordinated notes (426) (424) (1,282) (1,282) Allowance for funds used during construction 39 30 96 268 Interest income and other 6 28 49 90 Net (income) loss attributable to non-controlling interests included in comparable earnings and other (109) (104) (370) (339) 508 389 1,661 1,342 Average exchange rate – U.S. to Canadian dollars 1.40 1.38 1.38 1.40 FOREIGN EXCHANGE RELATED TO MEXICO NATURAL GAS PIPELINES Changes in the value of the Mexican peso against the U.S. dollar can affect our comparable earnings as a portion of our Mexico Natural Gas Pipelines' monetary assets and liabilities are peso-denominated, while our financial results are denominated in U.S. dollars for our Mexico operations. These peso-denominated balances are revalued to U.S. dollars, creating foreign exchange gains and losses that are included in Income (loss) from equity investments, Foreign exchange (gains) losses, net and Net income (loss) attributable to non-controlling interests in the 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. 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. 28 | TC Energy Third Quarter 2026
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The period end exchange rates for one U.S. dollar to Mexican pesos were as follows: September 30, 2026 18.06 September 30, 2025 18.36 December 31, 2025 18.00 December 31, 2024 20.87 A summary of the impacts of transactional foreign exchange gains and losses from changes in the value of the Mexican peso against the U.S. dollar and associated derivatives is set out in the table below: three months ended September 30 nine months ended September 30 (millions of $) 2026 2025 2026 2025 Comparable EBITDA - Mexico Natural Gas Pipelines1 19 (14) — (68) Foreign exchange gains (losses), net included in comparable earnings 14 32 42 104 Income tax (expense) recovery included in comparable earnings (2) (17) (14) (76) Net (income) loss attributable to non-controlling interests included in comparable earnings2 (3) 1 — 7 28 2 28 (33) 1 Includes 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. TC Energy Third Quarter 2026 | 29
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Recent developments CANADIAN NATURAL GAS PIPELINES NGTL System In the nine months ended September 30, 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. Multi-Year Growth Plan The 2025-2029 NGTL Settlement enables an investment framework that supports our Board of Directors' approval to allocate up to $3.3 billion of capital towards progression of the MYGP for expansion facilities to meet commitments on the NGTL System. It is comprised of multiple distinct projects with various targeted in-service dates, subject to final company and regulatory approvals. To date, expansion facilities representing approximately $1.2 billion of estimated project costs have received FID, with in-service dates beginning in 2026. As project execution advances, opportunities have been identified to optimize capital through efficient bundling and execution, as well as through refinements to project scope and timing. We c o n t i n u e t o e v a l u a t e s y s t e m r e q u i r e m e n t s , a n d d o n o t e x p e c t t h a t a l l f a c i l i t i e s w i t h i n t h e B o a r d ‑ a p p r o v e d c a p i t a l a l l o c a t i o n will be required to satisfy the MYGP capacity commitments of approximately 1.0 Bcf/d of incremental system throughput. Valhalla North and Berland River Project The Valhalla North section of the project was placed in service in third quarter 2025, and the Berland River compressor unit became operational on July 14, 2026, following the commissioning of the third-party power transmission connection. At a total capital cost of approximately $0.5 billion, the project includes approximately 33 km (21 miles) of pipeline and a non-emitting electric compressor unit, providing approximately 428 TJ/d (400 MMcf/d) of incremental capacity to the NGTL System. Canadian Mainline Settlement On July 9, 2026, the CER approved a four-year negotiated settlement governing the Canadian Mainline tolls and services from January 2027 through December 2030. The 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 return on equity. In addition, as part of the Mainline Settlement Growth Program (MSGP), TC Energy has committed up to $200 million of capital, subject to FID, to support incremental capacity, with targeted returns that exceed the approved return on equity. In August 2026, Canadian Mainline completed open seasons under the Mainline Settlement framework. Customer commitments received through the process support advancement of the MSGP, providing a pathway for deployment of incremental capacity expansions. Coastal GasLink Coastal GasLink Pipeline Phase 2 Expansion In March 2026, Coastal GasLink LP entered into commercial agreements with LNG Canada (LNGC), which established a framework for advancing the CGL Phase 2 Expansion, an expansion of the Coastal GasLink pipeline, to enable the delivery of incremental pipeline capacity to the LNGC export facility in Kitimat, British Columbia. In September 2026, following a positive FID by LNGC and its joint venture participants for the expansion of the LNGC facility, Coastal GasLink LP approved the CGL Phase 2 Expansion. With an estimated project cost of $4.9 billion, the project includes the addition of five compressor stations and associated facility modifications, and is expected to increase firm transportation capacity by approximately 2.0 Bcf/d, bringing total capacity to approximately 4.5 Bcf/d. 30 | TC Energy Third Quarter 2026
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Under the agreements, LNGC will lead project execution and construction, while Coastal GasLink LP will provide technical and advisory support. The commercial structure includes defined limits on Coastal GasLink LP's capital commitments and exposure to construction cost and schedule risk. Coastal GasLink LP will remain the owner, operator and permit holder of the pipeline and associated facilities. Construction is expected to commence in early 2027, with an anticipated in-service date in the early 2030s, subject to completion of plant commissioning activities at the LNGC export facility. In September 2026, Coastal GasLink LP secured project-level financing of up to $3.3 billion to support construction. Together with participant funding elections and partner equity contributions, the financing structure is expected to provide sufficient liquidity through construction while reducing future equity funding requirements. Our proportionate share of committed equity to fund the expansion is up to approximately $250 million. In connection with the CGL Phase 2 Expansion reaching FID, we recognized pre-tax earnings of $75 million in third quarter 2026 related to certain payment arrangements associated with our sale of a 65 per cent interest in Coastal GasLink LP in 2020. These earnings have been excluded from comparable measures. Additional consideration may be recognized under these arrangements over the development, construction and future operation of the expansion, with amounts subject to adjustment based on final project costs and other contractual mechanisms. Indigenous Equity Option On October 13, 2026, we announced a transaction with FN CGL Pipeline Limited Partnership, an Indigenous-led investment entity representing five First Nations along the Coastal GasLink corridor. Through the transaction, participating First Nations will obtain an economic interest in the entity holding our 35 per cent ownership interest in Coastal GasLink LP. These communities are expected to benefit from long-term, predictable financial returns associated with our limited partner interest in Coastal GasLink LP. This transaction is the first of two planned Indigenous investment transactions. A second transaction involving additional First Nations is expected to close in fourth quarter 2026. TC Energy Third Quarter 2026 | 31
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U.S. NATURAL GAS PIPELINES ANR Section 4 Rate Case 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 May 11, 2026, ANR filed the Stipulation and Agreement of Settlement with FERC, which included an overall increase relative to pre-filed rates. On July 27, 2026, FERC approved the settlement filing (ANR Settlement). Previously accrued rate refund liabilities were refunded to customers, including interest, in third quarter 2026. Great Lakes Section 4 Rate Case 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 June 24, 2026, Great Lakes filed the Stipulation and Agreement of Settlement with FERC. On September 15, 2026, FERC approved the settlement filing (GLGT Settlement). We anticipate previously accrued rate refund liabilities will be refunded to customers, including interest, in fourth quarter 2026. GTN Section 4 Rate Case On June 25, 2026, GTN filed to amend its previous rate case settlement to allow for more time to work with its customers in an effort to reach agreement prior to filing a formal rate case. On July 16, 2026, FERC issued an order approving GTN’s amendment to the 2024 Rate Case Settlement, extending the deadline for GTN to file a Section 4 Rate Case from September 30, 2026 to December 31, 2026. On October 15, 2026, GTN filed the Stipulation and Agreement of Settlement, subject to FERC approval. Bison XPress Project The Bison XPress project, an expansion project on our Northern Border and Bison systems to replace and upgrade certain facilities and provide production egress from the Bakken basin to a delivery point at the Cheyenne Hub, was placed in service in May 2026, with a total project cost of US$0.4 billion, of which our share was US$0.2 billion, representing our 50 per cent equity investment in Northern Border and 100 per cent ownership in Bison. Appalachia Supply Project 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. Clark Project In June 2026, we approved the Clark project, an expansion project of our Columbia Gulf system designed to provide up to 0.3 Bcf/d of capacity for firm transportation to an existing natural gas-fired power generation plant. The project has an anticipated in-service date of 2028 and an estimated project cost of approximately US$0.1 billion. Central Virginia Capacity Project In June 2026, we approved the Central Virginia Capacity project, an expansion project of our Columbia Gas system designed to provide up to 0.4 Bcf/d of capacity to facilitate new natural gas-fired power generation to support data centre development. The project has anticipated in-service dates in 2028 and 2030, with a total estimated project cost of approximately US$0.3 billion. ANR Optimization Project In October 2026, we approved the ANR Optimization project in our Heartland region, an expansion of our ANR pipeline system designed to provide approximately 0.3 Bcf/d of firm transportation service to support coal-to-gas conversion. The project has an anticipated in-service date in 2029 and an estimated cost of approximately US$0.1 billion. 32 | TC Energy Third Quarter 2026
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Gillis Access Project On November 1, 2026, the Gillis Access project extension, a 63 km (39 mile), 1.4 Bcf/d pipeline extension that further connects supplies from the Haynesville basin at Gillis, was placed in service. The total project cost was approximately US$0.4 billion. Crossroads Expansion Project In November 2026, we approved the Crossroads Expansion project, an expansion of our Crossroads pipeline system designed to provide incremental capacity of 1.4 Bcf/d to support growing power generation demand, including data centres, in the U.S. Midwest. The project has an anticipated in-service date in 2030 and an estimated project cost of approximately US$1.8 billion. American Midwest Project In November 2026, we approved the American Midwest project, an expansion of our Northern Border pipeline system, designed to provide incremental capacity of 1.0 Bcf/d to support growing power generation demand, including data centres, in the U.S. Midwest. The project has an anticipated in-service date in 2030 and a total estimated project cost of approximately US$0.4 billion, of which our proportionate share of equity contributions is approximately US$0.1 billion. MEXICO NATURAL GAS PIPELINES TGNH Strategic Alliance with the CFE 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. Guadalajara-Manzanillo Pipeline On September 21, 2026, we entered into an agreement to sell Energía Occidente de México, the entity that owns the Guadalajara-Manzanillo pipeline, to affiliates of ESENTIA Energy Development, S.A.B. de C.V. for a gross purchase price of $560 million (US$400 million), excluding certain closing adjustments. The sale is expected to close in the first half of 2027, subject to customary closing conditions, regulatory approvals and consents. POWER AND ENERGY SOLUTIONS Bruce Power Life Extension The Unit 3 MCR, which began in March 2023, was completed and the unit was declared commercially operational on June 12, 2026, ahead of schedule and within budget, of which our share of equity contributions was $1.1 billion. On November 1, 2026, Unit 5 was removed from service and began its MCR outage with an expected return to service in 2030. Bécancour Natural Gas Cogeneration Plant Contract On September 16, 2026, our 20-year electricity supply contract with Hydro-Québec (HQ) expired. We are in discussions with HQ regarding a potential new electricity supply arrangement and, based on our assessment of the expected future use of the facility, determined that certain equipment is not expected to be utilized and will be retired and abandoned in place. Accordingly, we recorded a pre-tax asset impairment charge of $70 million related to the carrying value of this equipment, which has been excluded from comparable measures. TC Energy Third Quarter 2026 | 33
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Financial condition We strive to maintain financial strength and flexibility in all parts of the economic cycle. We rely on our operating cash flows to sustain our business, pay dividends and fund a portion of our growth. In addition, we access capital markets and engage in portfolio management activities to meet our financing needs and to manage our capital structure and credit ratings. 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, 2026, our current assets totaled $7.3 billion and current liabilities amounted to $12.8 billion, leaving us with a working capital deficit of $5.5 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 $8.0 billion of TCPL committed revolving credit facilities, of which $6.2 billion of short-term borrowing capacity remains available, net of $1.8 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, 2026 • an additional $2.1 billion of committed revolving credit facilities at certain of our subsidiaries and affiliates, of which $1.1 billion of short-term borrowing capacity remains available as of September 30, 2026, net of $1.0 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. 34 | TC Energy Third Quarter 2026
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CASH PROVIDED BY OPERATING ACTIVITIES1 three months ended September 30 nine months ended September 30 (millions of $) 2026 2025 2026 2025 Net cash provided by operations 1,782 1,920 6,602 5,452 Increase (decrease) in operating working capital 454 (130) (112) 251 Funds generated from operations 2,236 1,790 6,490 5,703 Specific item: Third-party settlements, net of current income tax — — 78 — Comparable funds generated from operations 2,236 1,790 6,568 5,703 1 Includes continuing and discontinued operations. Net cash provided by operations Net cash provided by operations decreased by $138 million for the three months ended September 30, 2026 compared to the same period in 2025 primarily due to the timing of working capital changes, partially offset by higher funds generated from operations. Net cash provided by operations increased by $1,150 million for the nine months ended September 30, 2026 compared to the same period in 2025 primarily due to higher funds generated from operations and the timing of working capital changes. Comparable funds generated from operations Comparable funds generated from operations, a non-GAAP measure, helps us assess the cash generating ability of our businesses by excluding the timing effects of working capital changes, as well as the cash impact of our specific items. Comparable funds generated from operations increased by $446 million and $865 million for the three and nine months ended September 30, 2026 compared to the same periods in 2025 primarily due to higher comparable earnings and higher distributions from our equity investments. CASH (USED IN) PROVIDED BY INVESTING ACTIVITIES1 three months ended September 30 nine months ended September 30 (millions of $) 2026 2025 2026 2025 Capital spending Capital expenditures (1,194) (1,255) (3,153) (3,924) Capital projects in development (5) (2) (14) (12) Contributions to equity investments (213) (249) (675) (758) (1,412) (1,506) (3,842) (4,694) Other distributions from equity investments 347 — 347 5 Deferred amounts and other (62) (87) (61) (126) Net cash (used in) provided by investing activities (1,127) (1,593) (3,556) (4,815) 1 Includes continuing and discontinued operations. Net cash used in investing activities decreased by $466 million and $1,259 million for the three and nine months ended September 30, 2026 compared to the same periods in 2025 primarily due to decreased capital spending and distributions from our equity investment in Coastal GasLink as a result of its debt financing program in 2026. Capital expenditures incurred for the nine months ended September 30, 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 nine months ended September 30, 2026 compared to the same period in 2025 reflect the completion of the Southeast Gateway pipeline and ANR projects in 2025. TC Energy Third Quarter 2026 | 35
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CASH (USED IN) PROVIDED BY FINANCING ACTIVITIES three months ended September 30 nine months ended September 30 (millions of $) 2026 2025 2026 2025 Notes payable issued (repaid), net 1,933 (59) 1,526 2,037 Long-term debt issued, net of issue costs (4) 831 2,323 3,252 Long-term debt repaid (2,454) (805) (4,073) (4,029) Junior subordinated notes issued, net of issue costs — 989 1,850 2,043 Dividends and distributions paid (1,058) (1,025) (3,513) (3,122) Common shares issued, net of issue costs — 37 74 87 Cash received from factoring arrangement 84 101 84 101 Factoring arrangement settlements — — (351) — Loan from affiliate 42 — 107 — Net cash (used in) provided by financing activities (1,457) 69 (1,973) 369 Long-term debt issued The following table outlines significant long-term debt issuances in the nine months ended September 30, 2026: (millions of Canadian $, unless otherwise noted) Company Issue date Type Maturity date Amount Interest rate TransCanada PipeLines Limited June 2026 Medium Term Notes June 2036 700 4.61% June 2026 Medium Term Notes June 2056 600 5.36% Columbia Pipelines Operating Company LLC May 2026 Senior Unsecured Notes May 2036 US 750 5.51% Subsequent debt issued On October 29, 2026, TC Louisiana Intrastate Pipeline LLC entered into a US$200 million senior unsecured term loan maturing in October 2029, bearing interest at a floating rate. 36 | TC Energy Third Quarter 2026
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Long-term debt repaid/retired The following table outlines significant long-term debt repaid/retired in the nine months ended September 30, 2026: (millions of Canadian $, unless otherwise noted) Company Repayment date Type Amount Interest rate TransCanada PipeLines Limited April 2026 Medium Term Notes 400 4.35% February 2026 Medium Term Notes 241 8.29% NGTL Limited Partnership August 2026 Medium Term Notes US 33 7.50% June 2026 Medium Term Notes 45 8.46% May 2026 Medium Term Notes 45 8.88% Columbia Pipelines Holding Company LLC July 2026 Senior Unsecured Notes US 300 6.06% ANR Pipeline Company June 2026 Senior Unsecured Notes US 240 4.14% TC Energía Mexicana, S. de R.L. de C.V. Various Senior Unsecured Term Loan US 604 Floating In May 2026, TC Energía Mexicana, S. de R.L. de C.V. terminated its US$500 million senior unsecured revolving credit facility, with interest at a floating rate on which no amount was outstanding. Subsequent debt repayment On October 29, 2026, TC Energía Mexicana, S. de R.L. de C.V. fully repaid and retired its senior unsecured term loan bearing interest at a floating rate, of which US$89 million was outstanding. Junior subordinated notes issued The following table outlines significant junior subordinated notes issued in the nine months ended September 30, 2026: (millions of Canadian $, unless otherwise noted) Company Issue date Type Maturity date Amount Interest rate TransCanada PipeLines Limited April 2026 Junior Subordinated Notes October 2056 US 500 6.13% 1 April 2026 Junior Subordinated Notes October 2056 US 500 6.38% 2 February 2026 Junior Subordinated Notes August 2056 500 5.13% 3 1 Fixed rate of interest per year until October 17, 2031, and resetting every five years thereafter, subject to a rate-reset minimum. 2 Fixed rate of interest per year until October 17, 2036, and resetting every five years thereafter, subject to a rate-reset minimum. 3 Fixed rate of interest per year until August 20, 2031, and resetting every five years thereafter, subject to a rate-reset minimum. Junior subordinated notes repaid/retired In August 2026, TCPL exercised its option to fully repay and retire the US$1.2 billion junior subordinated notes that had a maturity date of 2076, bearing interest at 6.13 per cent to TransCanada Trust (the Trust). The proceeds from the repayment were used by the Trust to fund the redemption price of the US$1.2 billion in aggregate principal amount of outstanding T r u s t N o t e s – S e r i e s 2 0 1 6 ‑ A , i n A u g u s t 2 0 2 6 p u r s u a n t t o t h e i r t e r m s . TC Energy Third Quarter 2026 | 37
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DIVIDENDS Our Board of Directors has declared a quarterly dividend on our outstanding common shares of $0.8775 per common share for the quarter ending December 31, 2026. SHARE INFORMATION At October 29, 2026, we had approximately 1.0 billion issued and outstanding common shares and approximately 1.3 million outstanding and exercisable options to buy common shares. On January 30, 2026, the remaining 1,929,407 Series 6 preferred shares were converted, on a one-for-one basis, into 1,929,407 Series 5 preferred shares and Series 6 preferred shares were delisted from the TSX at the close of markets on January 30, 2026. CREDIT FACILITIES At October 29, 2026, we had a total of $7.9 billion of TCPL committed revolving credit facilities, of which $6.0 billion of short-term borrowing capacity remains available, net of $1.9 billion backstopping outstanding commercial paper balances. We also have arrangements in place for a further $2.0 billion of demand credit facilities, of which $1.3 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 October 29, 2026, net of $1.0 billion backstopping outstanding commercial paper balances. CONTRACTUAL OBLIGATIONS Capital expenditure commitments at September 30, 2026 were approximately $1.9 billion (December 31, 2025 – approximately $0.8 billion), reflecting contractual commitments entered into for construction on Canadian and U.S. natural gas pipelines, primarily related to the construction costs associated with the NGTL System, ANR and other pipeline projects. There were no material changes to our contractual obligations in third 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. 38 | TC Energy Third Quarter 2026
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Discontinued operations On October 1, 2024, TC Energy completed the spinoff of its Liquids Pipelines business into a new public company, South Bow Corporation. Upon completion of the Spinoff Transaction, the Liquids Pipelines business was accounted for as discontinued operations. Refer to our 2025 Annual Report for additional information. For the three and nine months ended September 30, 2026, we did not recognize any income or loss from discontinued operations (2025 – loss of $204 million and $233 million, respectively). For the three and nine months ended September 30, 2026 and 2025, we did not recognize any comparable EBITDA from discontinued operations or comparable earnings from discontinued operations. TC Energy Third Quarter 2026 | 39
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Financial risks and financial instruments 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. INTEREST RATE RISK We utilize both short- and long-term debt to finance our operations which exposes us to interest rate risk. We typically pay fixed rates of interest on our long-term debt and floating rates on short-term debt including our commercial paper programs and amounts drawn on our credit facilities. A small portion of our long-term debt bears interest at floating rates. In addition, we are exposed to interest rate risk on financial instruments and contractual obligations containing variable interest rate components. We actively manage our interest rate risk using interest rate derivatives. FOREIGN EXCHANGE RISK Certain of our businesses generate all or most of their earnings in U.S. dollars and since we report our financial results in Canadian dollars, changes in the value of the U.S. dollar against the Canadian dollar directly affect our comparable EBITDA and may also impact comparable earnings. A portion of our Mexico Natural Gas Pipelines' monetary assets and liabilities are peso-denominated, while our Mexico operations' financial results are denominated in U.S. dollars. Therefore, changes in the value of the Mexican peso against the U.S. dollar can affect our comparable earnings. In addition, foreign exchange gains or losses calculated for Mexico income tax purposes on the revaluation of U.S. dollar-denominated monetary assets and liabilities result in a peso-denominated income tax exposure for these entities, leading to fluctuations in Income (loss) from equity investments and Income tax expense (recovery) in the 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. COUNTERPARTY CREDIT RISK We have exposure to counterparty credit risk in a number of areas including: • cash and cash equivalents • accounts receivable • available-for-sale assets • fair value of derivative assets • net investment in leases and certain contract assets in Mexico. 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. 40 | TC Energy Third Quarter 2026
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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 September 30, 2026, we had no significant credit risk concentrations, with the exception of the CFE, which represents approximately 32 per cent of gross exposure. At this time, there were no significant amounts past due or impaired. We recorded pre-tax expenses of $11 million and $17 million related to the ECL provision on the TGNH net investment in leases and certain contract assets in Mexico for the three and nine months ended September 30, 2026 (2025 – pre-tax recovery of $14 million and pre-tax expense of $87 million). Refer to Note 14, 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 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. FINANCIAL INSTRUMENTS With the exception of Long-term debt and Junior subordinated notes, our derivative and non-derivative financial instruments are recorded on the balance sheet at fair value unless they were entered into and continue to be held for the purpose of receipt or delivery in accordance with our normal purchase and sales exemptions and are documented as such. In addition, fair value accounting is not required for other financial instruments that qualify for certain accounting exemptions. Derivative instruments We use derivative instruments to reduce volatility associated with fluctuations in commodity prices, interest rates and foreign exchange rates. Derivative instruments, including those that qualify and are designated for hedge accounting treatment, are recorded at fair value. The majority of derivative instruments that are not designated or do not qualify for hedge accounting treatment have been entered into as economic hedges to manage our exposure to market risk and are classified as held-for-trading. Changes in the fair value of held-for-trading derivative instruments are recorded in net income in the period of change. This may expose us to increased variability in reported operating results since the fair value of the held-for-trading derivative instruments can fluctuate significantly from period to period. The recognition of gains and losses on derivatives for Canadian natural gas regulated pipeline exposures is determined through the regulatory process. Gains and losses arising from changes in the fair value of derivatives accounted for as part of RRA, including those that qualify for hedge accounting treatment, are expected to be refunded or recovered through the tolls charged by us. As a result, these gains and losses are deferred as regulatory liabilities or regulatory assets and are refunded to or collected from the ratepayers in subsequent years when the derivative settles. TC Energy Third Quarter 2026 | 41
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Balance sheet presentation of derivative instruments The balance sheet presentation of the fair value of derivative instruments was as follows: (millions of $) September 30, 2026 December 31, 2025 Other current assets 455 438 Other long-term assets 137 161 Accounts payable and other (485) (380) Other long-term liabilities (497) (149) (390) 70 Unrealized and realized gains (losses) on derivative instruments The following summary does not include hedges of our net investment in foreign operations. three months ended September 30 nine months ended September 30 (millions of $) 2026 2025 2026 2025 Derivative Instruments Held for Trading1 Unrealized gains (losses) in the period Commodities2 76 (63) (67) (36) Foreign exchange (15) (68) (124) 169 Realized gains (losses) in the period Commodities (8) 20 (284) (18) Foreign exchange (30) 39 36 111 Interest rate 1 1 3 6 Derivative Instruments in Hedging Relationships Realized gains (losses) in the period Commodities 8 3 29 17 Foreign exchange 3 2 8 6 Interest rate (3) (8) (8) (24) 1 Realized 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 h e l d ‑ f o r ‑ t r a d i n g d e r i v a t i v e i n s t r u m e n t s a r e i n c l u d e d o n a n e t b a s i s i n F o r e i g n e x c h a n g e ( g a i n s ) l o s s e s , n e t a n d I n t e r e s t e x p e n s e , r e s p e c t i v e l y , i n t h e Condensed consolidated statement of income. 2 In the three and nine months ended September 30, 2026, no amounts were reclassified to Net income (loss) from AOCI related to discontinued cash flow hedges (2025 – unrealized gains of less than $1 million and $1 million, respectively). 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 14, Risk management and financial instruments, of our Condensed consolidated financial statements. 42 | TC Energy Third Quarter 2026
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Other information CONTROLS AND PROCEDURES Management, including our President and CEO and our CFO, evaluated the effectiveness of our disclosure controls and procedures as at September 30, 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 third quarter 2026 that had or are likely to have a material impact on our internal controls over financial reporting. CRITICAL ACCOUNTING ESTIMATES AND ACCOUNTING POLICY CHANGES 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. Impairment of goodwill 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. Accounting changes 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. TC Energy Third Quarter 2026 | 43
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Quarterly results SELECTED QUARTERLY CONSOLIDATED FINANCIAL DATA 2026 2025 2024 (millions of $, except per share amounts) Third Second First Fourth Third Second First Fourth Revenues 4,030 3,957 3,861 4,168 3,704 3,744 3,623 3,577 Net income (loss) attributable to common shares 1,026 987 899 980 609 833 978 971 from continuing operations 1,026 987 899 959 813 862 978 1,069 from discontinued operations1 — — — 21 (204) (29) — (98) Comparable earnings2 983 984 1,031 1,018 805 848 983 1,094 from continuing operations 983 984 1,031 1,018 805 848 983 1,094 from discontinued operations1 — — — — — — — — Per share statistics: Net income (loss) per common share – basic $0.98 $0.95 $0.86 $0.94 $0.58 $0.80 $0.94 $0.94 from continuing operations $0.98 $0.95 $0.86 $0.92 $0.78 $0.83 $0.94 $1.03 from discontinued operations1 — — — $0.02 ($0.20) ($0.03) — ($0.09) Comparable earnings per common share2 $0.94 $0.94 $0.99 $0.98 $0.77 $0.82 $0.95 $1.05 from continuing operations $0.94 $0.94 $0.99 $0.98 $0.77 $0.82 $0.95 $1.05 from discontinued operations1 — — — — — — — — Dividends declared per common share3 $0.8775 $0.8775 $0.8775 $0.85 $0.85 $0.85 $0.85 $0.8225 1 Discontinued operations represents nine months of Liquids Pipelines earnings in 2024 and associated income and losses from the Spinoff Transaction, thereafter. 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. FACTORS AFFECTING QUARTERLY FINANCIAL INFORMATION BY BUSINESS SEGMENT Quarter-over-quarter revenues and net income fluctuate for reasons that vary across our business segments. In addition to the factors below, our revenues and segmented earnings (losses) are impacted by fluctuations in foreign exchange rates, mainly related to our U.S. dollar-denominated operations and our peso-denominated exposure. 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 ECL on net investment in leases and certain contract assets in Mexico. 44 | TC Energy Third Quarter 2026
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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. FACTORS AFFECTING FINANCIAL INFORMATION BY QUARTER We calculate comparable measures by adjusting certain GAAP measures for specific items we believe are significant but not reflective of our underlying operations in the period. Except as otherwise described herein, these comparable measures are calculated on a consistent basis from period to period and are adjusted for specific items in each period, as applicable. Refer to the Non-GAAP measures section for additional information. In third quarter 2026, comparable earnings from continuing operations also excluded: • pre-tax earnings of $75 million in connection with the CGL Phase 2 Expansion reaching FID • a pre-tax recovery of $36 million representing our proportionate share of a Bruce Power operating cost provision release related to prior periods • a pre-tax asset impairment charge of $70 million related to the carrying value of certain equipment at our Bécancour cogeneration plant • pre-tax unrealized foreign exchange losses, net, of $16 million on the peso-denominated intercompany loan between TCPL and TGNH, net of non-controlling interest • a pre-tax expense of $10 million related to the ECL provision on TGNH net investment in leases, net of non-controlling interest, as well as on certain contract assets in Mexico. In second quarter 2026, comparable earnings from continuing operations also excluded: • pre-tax unrealized foreign exchange gains, net, of $81 million on the peso-denominated intercompany loan between TCPL and TGNH, net of non-controlling interest • a pre-tax recovery of $12 million related to the ECL provision on TGNH net investment in leases, net of non-controlling interest, as well as on certain contract assets in Mexico • a pre-tax expense of $70 million related to a third-party contractual settlement in our Power and Energy Solutions segment. 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 a third-party settlement from the resolution of a certain legal matter in our U.S. Natural Gas Pipelines segment • a pre-tax expense of $17 million related to the ECL provision on TGNH net investment in leases, net of non-controlling interest, as well as on certain contract assets in Mexico. TC Energy Third Quarter 2026 | 45
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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 related to the ECL provision on 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 related to the ECL provision on 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 related to the ECL provision on 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 related to the ECL provision on 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 related to the ECL provision on 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. 46 | TC Energy Third Quarter 2026
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Condensed consolidated statement of income three months ended September 30 nine months ended September 30 (unaudited - millions of Canadian $, except per share amounts) 2026 2025 2026 2025 Revenues Canadian Natural Gas Pipelines 1,528 1,478 4,490 4,304 U.S. Natural Gas Pipelines 1,840 1,637 5,392 5,199 Mexico Natural Gas Pipelines 427 426 1,283 1,012 Power and Energy Solutions 235 161 682 544 Corporate — 2 1 12 4,030 3,704 11,848 11,071 Income (Loss) from Equity Investments 489 345 1,248 980 Operating and Other Expenses Plant operating costs and other 1,166 1,151 3,381 3,343 Commodity purchases resold 52 54 189 153 Property taxes 220 215 641 657 Depreciation and amortization 749 701 2,209 2,050 Asset impairment charge 70 — 70 — 2,257 2,121 6,490 6,203 Financial Charges Interest expense 883 847 2,580 2,534 Allowance for funds used during construction (64) (55) (163) (417) Foreign exchange (gains) losses, net 4 (30) (41) (142) Interest income and other (91) (47) (158) (147) 732 715 2,218 1,828 Income (Loss) from Continuing Operations before Income Taxes 1,530 1,213 4,388 4,020 Income Tax Expense (Recovery) from Continuing Operations Current 137 118 289 224 Deferred 175 127 584 651 312 245 873 875 Net Income (Loss) from Continuing Operations 1,218 968 3,515 3,145 Net Income (Loss) from Discontinued Operations, Net of Tax — (204) — (233) Net Income (Loss) 1,218 764 3,515 2,912 Net income (loss) attributable to non-controlling interests 164 127 518 408 Net Income (Loss) Attributable to Controlling Interests 1,054 637 2,997 2,504 Preferred share dividends 28 28 85 84 Net Income (Loss) Attributable to Common Shares 1,026 609 2,912 2,420 Amounts Attributable to Common Shares Net income (loss) from continuing operations 1,218 968 3,515 3,145 Net income (loss) attributable to non-controlling interests 164 127 518 408 Net income (loss) attributable to controlling interests from continuing operations 1,054 841 2,997 2,737 Preferred share dividends 28 28 85 84 Net income (loss) attributable to common shares from continuing operations 1,026 813 2,912 2,653 Net income (loss) from discontinued operations, net of tax — (204) — (233) Net Income (Loss) Attributable to Common Shares 1,026 609 2,912 2,420 Net Income (Loss) per Common Share - Basic and Diluted Continuing operations $0.98 $0.78 $2.79 $2.55 Discontinued operations — ($0.20) — ($0.22) $0.98 $0.58 $2.79 $2.33 Weighted Average Number of Common Shares (millions) Basic 1,042 1,040 1,042 1,040 Diluted 1,042 1,040 1,042 1,040 See accompanying Notes to the Condensed consolidated financial statements. TC Energy Third Quarter 2026 | 47
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Condensed consolidated statement of comprehensive income three months ended September 30 nine months ended September 30 (unaudited - millions of Canadian $) 2026 2025 2026 2025 Net Income (Loss) 1,218 764 3,515 2,912 Other Comprehensive Income (Loss), Net of Income Taxes Foreign currency translation gains and losses on net investment in foreign operations 35 431 745 (659) Change in fair value of net investment hedges — — — 1 Change in fair value of cash flow hedges 3 24 33 (16) Reclassification to net income of (gains) losses on cash flow hedges (4) (21) (37) 17 Reclassification to net income of actuarial (gains) losses on pension and other post-retirement benefit plans — — — 1 Other comprehensive income (loss) on equity investments (54) (10) (68) (26) (20) 424 673 (682) Comprehensive Income (Loss) 1,198 1,188 4,188 2,230 Comprehensive income (loss) attributable to non-controlling interests 171 362 885 56 Comprehensive Income (Loss) Attributable to Controlling Interests 1,027 826 3,303 2,174 Preferred share dividends 28 28 85 84 Comprehensive Income (Loss) Attributable to Common Shares 999 798 3,218 2,090 See accompanying Notes to the Condensed consolidated financial statements. 48 | TC Energy Third Quarter 2026
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Condensed consolidated statement of cash flows three months ended September 30 nine months ended September 30 (unaudited - millions of Canadian $) 2026 2025 2026 2025 Cash Generated from Operations Net income (loss) 1,218 764 3,515 2,912 Depreciation and amortization 749 701 2,209 2,050 Asset impairment charge 70 — 70 — Deferred income taxes 175 135 584 659 (Income) loss from equity investments (489) (345) (1,248) (980) Distributions received from operating activities of equity investments 722 339 1,595 1,091 Employee post-retirement benefits funding, net of expense (1) 1 (8) 3 Equity allowance for funds used during construction (55) (46) (141) (291) Unrealized (gains) losses on financial instruments (61) 131 191 (133) Expected credit loss provision 10 (14) 16 88 Foreign exchange (gains) losses, net – intercompany loan — (76) (125) 94 Other (102) 200 (168) 210 (Increase) decrease in operating working capital (454) 130 112 (251) Net cash provided by operations 1,782 1,920 6,602 5,452 Investing Activities Capital expenditures (1,194) (1,255) (3,153) (3,924) Capital projects in development (5) (2) (14) (12) Contributions to equity investments (213) (249) (675) (758) Other distributions from equity investments 347 — 347 5 Deferred amounts and other (62) (87) (61) (126) Net cash (used in) provided by investing activities (1,127) (1,593) (3,556) (4,815) Financing Activities Notes payable issued (repaid), net 1,933 (59) 1,526 2,037 Long-term debt issued, net of issue costs (4) 831 2,323 3,252 Long-term debt repaid (2,454) (805) (4,073) (4,029) Junior subordinated notes issued, net of issue costs — 989 1,850 2,043 Dividends on common shares (915) (885) (2,713) (2,623) Dividends on preferred shares (29) (29) (84) (85) Common shares issued, net of issue costs — 37 74 87 Distributions to non-controlling interests and other (114) (111) (716) (414) Cash received from factoring arrangement 84 101 84 101 Factoring arrangement settlements — — (351) — Loan from affiliate 42 — 107 — Net cash (used in) provided by financing activities (1,457) 69 (1,973) 369 Effect of Foreign Exchange Rate Changes on Cash and Cash Equivalents (1) (16) 30 (5) Cash Balances Classified as Assets Held for Sale (22) — (22) — Increase (decrease) in cash and cash equivalents (825) 380 1,081 1,001 Cash and Cash Equivalents - Beginning of period 2,074 1,422 168 801 Cash and Cash Equivalents - End of period 1,249 1,802 1,249 1,802 Includes continuing and discontinued operations. Refer to Note 3, Discontinued operations, for additional information. See accompanying Notes to the Condensed consolidated financial statements. TC Energy Third Quarter 2026 | 49
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Condensed consolidated balance sheet (unaudited - millions of Canadian $) September 30, 2026 December 31, 2025 ASSETS Current Assets Cash and cash equivalents 1,249 168 Accounts receivable 2,074 2,794 Inventories 1,012 782 Assets held for sale 498 — Other current assets 2,511 2,375 Current assets of discontinued operations — 197 7,344 6,316 Plant, Property and Equipment net of accumulated depreciation of $38,657 and $36,951, respectively 73,557 71,054 Net Investment in Leases 8,391 8,110 Equity Investments 11,314 11,358 Restricted Investments 3,914 3,502 Regulatory Assets 3,047 2,913 Goodwill 13,487 13,016 Other Long-Term Assets 2,619 2,482 123,673 118,751 LIABILITIES Current Liabilities Notes payable 2,780 1,200 Accounts payable and other 4,879 5,274 Dividends payable 933 901 Accrued interest 904 858 Current portion of long-term debt 3,197 1,545 Liabilities related to assets held for sale 87 — Current liabilities of discontinued operations 41 181 12,821 9,959 Regulatory Liabilities 6,127 5,841 Other Long-Term Liabilities 1,625 1,034 Deferred Income Tax Liabilities 8,426 7,677 Long-Term Debt 44,418 45,247 Junior Subordinated Notes 12,639 12,094 86,056 81,852 EQUITY Common shares, no par value 30,300 30,218 Issued and outstanding: September 30, 2026 – 1,042 million shares December 31, 2025 – 1,041 million shares Preferred shares 2,255 2,255 Retained earnings (Accumulated deficit) (5,764) (5,925) Accumulated other comprehensive income (loss) 1,053 747 Controlling Interests 27,844 27,295 Non-Controlling Interests 9,773 9,604 37,617 36,899 123,673 118,751 Commitments, Contingencies and Guarantees (Note 15) Variable Interest Entities (Note 16) See accompanying Notes to the Condensed consolidated financial statements. 50 | TC Energy Third Quarter 2026
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Condensed consolidated statement of equity three months ended September 30 nine months ended September 30 (unaudited - millions of Canadian $) 2026 2025 2026 2025 Common Shares Balance at beginning of period 30,300 30,158 30,218 30,101 Shares issued: Exercise of stock options — 41 82 98 Balance at end of period 30,300 30,199 30,300 30,199 Preferred Shares Balance at beginning and end of period 2,255 2,499 2,255 2,499 Additional Paid-In Capital Balance at beginning of period — — — — Exercise and forfeitures of stock options — (3) (8) (7) Disposition of equity interests, net of transaction costs — (5) — (5) Reclassification of additional paid-in capital deficit to accumulated deficit — 8 8 12 Balance at end of period — — — — Accumulated Deficit Balance at beginning of period (5,876) (5,741) (5,925) (5,241) Net income (loss) attributable to controlling interests 1,054 637 2,997 2,504 Common share dividends (913) (885) (2,742) (2,653) Preferred share dividends (29) (29) (86) (82) Spinoff of Liquids Pipelines business — — — (542) Reclassification of additional paid-in capital deficit to accumulated deficit — (8) (8) (12) Balance at end of period (5,764) (6,026) (5,764) (6,026) Accumulated Other Comprehensive Income (Loss) Balance at beginning of period 1,080 604 747 233 Other comprehensive income (loss) attributable to controlling interests (27) 189 306 (330) Impact of non-controlling interests — — — 348 Spinoff of Liquids Pipelines business — — — 542 Balance at end of period 1,053 793 1,053 793 Equity Attributable to Controlling Interests 27,844 27,465 27,844 27,465 Equity Attributable to Non-Controlling Interests Balance at beginning of period 9,716 9,860 9,604 10,768 Net income (loss) attributable to non-controlling interests 164 127 518 408 Other comprehensive income (loss) attributable to non-controlling interests 7 235 367 (352) Disposition of equity interests — — — (348) Distributions declared to non-controlling interests (114) (111) (716) (365) Balance at end of period 9,773 10,111 9,773 10,111 Total Equity 37,617 37,576 37,617 37,576 See accompanying Notes to the Condensed consolidated financial statements. TC Energy Third Quarter 2026 | 51
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Notes to Condensed consolidated financial statements (unaudited) 1. BASIS OF PRESENTATION These Condensed consolidated financial statements of TC Energy Corporation (TC Energy or the Company) have been prepared by management in accordance with U.S. GAAP. The accounting policies applied are consistent with those outlined in TC Energy’s annual audited Consolidated financial statements for the year ended December 31, 2025, except as described in Note 2, Accounting changes. Capitalized and abbreviated terms that are used but not otherwise defined herein are identified in TC Energy’s 2025 Annual Report. These Condensed consolidated financial statements reflect adjustments, all of which are normal recurring adjustments that are, in the opinion of management, necessary to reflect fairly the financial position and results of operations for the respective periods. These Condensed consolidated financial statements do not include all disclosures required in the annual financial statements and should be read in conjunction with the 2025 audited Consolidated financial statements included in TC Energy’s 2025 Annual Report. On October 1, 2024, TC Energy completed the spinoff of its Liquids Pipelines business into the new public company, South Bow Corporation (South Bow) (the Spinoff Transaction). The results of the Liquids Pipelines business are presented as discontinued operations and have been excluded from continuing operations and segment disclosures for all periods presented. Earnings for interim periods may not be indicative of results for the fiscal year in certain of the Company’s segments primarily due to: • Natural gas pipelines segments – the timing of regulatory decisions and negotiated rate case settlements as well as seasonal fluctuations in short-term throughput volumes on U.S. pipelines and marketing activities • Power and Energy Solutions – the impacts of seasonal weather conditions on customer demand, market supply and prices of natural gas and power as well as maintenance outages in certain of the Company’s investments in electrical power generation plants and Canadian non-regulated natural gas storage facilities and marketing activities. In addition to the factors mentioned above, revenues and segmented earnings are impacted by fluctuations in foreign exchange rates, mainly related to the Company's U.S. dollar-denominated operations and Mexican peso-denominated exposure. Out-of-Period Adjustments During second quarter 2025, the Company recorded out-of-period adjustments to reclassify a pro rata portion of its net investment hedge losses recorded in Accumulated other comprehensive income (loss) (AOCI). The adjustments included (i) a reclassification of net investment hedge losses of $348 million from AOCI to Non-controlling interests (NCI) related to the sale of 40 per cent of Columbia Gas and Columbia Gulf on October 4, 2023, which was presented as Impact of non-controlling interests and Disposition of equity interests, respectively, in the Condensed consolidated statement of equity; and (ii) a reclassification of net investment hedge losses of $542 million related to the spinoff of the Company's Liquids Pipelines business that occurred on October 1, 2024 from AOCI to Retained earnings (Accumulated deficit). The Company determined that the impact of these out-of-period adjustments was not material, individually or in the aggregate, to any previously reported quarterly or annual financial statements and is not material to the Company's Condensed consolidated financial statements. 52 | TC Energy Third Quarter 2026
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Use of Estimates and Judgments In preparing these Condensed consolidated financial statements, TC Energy is required to make estimates and assumptions that affect both the amount and timing of recording assets, liabilities, revenues and expenses since the determination of these items may be dependent on future events. The Company uses the most current information available and exercises careful judgment in making these estimates and assumptions. In the opinion of management, these Condensed consolidated financial statements have been properly prepared within reasonable limits of materiality and within the framework of the Company’s significant accounting policies included in the annual audited Consolidated financial statements for the year ended December 31, 2025, except as described in Note 2, Accounting changes. 2. ACCOUNTING CHANGES Future Accounting Changes Disaggregation of Income Statement Expenses In November 2024, the FASB issued new guidance requiring additional disclosure on the nature of expenses included in the income statement. The new standard requires disclosures about specific types of expenses included in the expense captions presented on the face of the income statement as well as disclosures about selling expenses. The new guidance is effective for annual periods beginning January 1, 2027 and interim periods beginning January 1, 2028. Early adoption is permitted. The guidance is applied prospectively with retrospective application permitted. The Company is currently assessing the impact of the standard on the Company's consolidated financial statements. Internal-Use Software In September 2025, the FASB issued updated guidance for accounting for internal-use software costs. The updated guidance removes references to project development stages and outlines revised guidance for when capitalization begins for internal-use software costs. The guidance is effective for annual and interim periods beginning January 1, 2028. Early adoption is permitted. The guidance can be applied prospectively, retrospectively, or with a modified transition approach. The Company is currently assessing the impact of the standard on the Company's consolidated financial statements. Hedge Accounting Improvements In November 2025, the FASB issued new guidance to further align hedge accounting with the economics of an entity's risk management activities. The amendments are intended to allow entities to achieve and maintain hedge accounting for highly effective hedges of forecasted transactions. The new guidance is effective for interim and annual reporting periods beginning January 1, 2027. Early adoption is permitted. The guidance is applied on a prospective basis for all hedging relationships that exist at the date of adoption. The Company is currently assessing the impact of the standard on the Company's consolidated financial statements. Government Grants In December 2025, the FASB established authoritative guidance on the recognition, measurement and presentation requirements for government grants received. The guidance provides criteria for when government grants can be recognized, distinguishes between grants related to assets and grants related to income and provides presentation and disclosure requirements. The new guidance is effective for annual and interim periods beginning January 1, 2029. Early adoption is permitted. The guidance can be applied with a modified prospective, a modified retrospective, or a retrospective approach. The Company is currently assessing the impact of the standard on the Company's consolidated financial statements. Environmental Credits and Environmental Credit Obligations In May 2026, the FASB issued guidance on the recognition, measurement, presentation and disclosure requirements for all entities that generate, purchase, or receive environmental credits or have a regulatory compliance obligation that may be settled with environmental credits. The new guidance is effective for annual and interim periods beginning January 1, 2028. Early adoption is permitted. The guidance is applied on a retrospective basis as of the beginning of the annual reporting period of adoption. The Company is currently assessing the impact of the standard on the Company's consolidated financial statements. TC Energy Third Quarter 2026 | 53
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3. DISCONTINUED OPERATIONS Spinoff of Liquids Pipelines Business For the three and nine months ended September 30, 2026, the Company did not recognize any income or loss from discontinued operations (2025 – loss of $204 million and $233 million, respectively). For the three and nine months ended September 30, 2026, net cash was $122 million used in and $44 million provided by operations of discontinued operations, respectively (2025 – $12 million provided by and $41 million used in operations of discontinued operations, respectively). For the three and nine months ended September 30, 2026, net cash provided by investing activities of discontinued operations was nil (2025 – nil and $24 million, respectively). At September 30, 2026, the Company reported nil current assets of discontinued operations (December 31, 2025 – $197 million) and current liabilities of discontinued operations of $41 million (December 31, 2025 – $181 million). 54 | TC Energy Third Quarter 2026
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4. SEGMENTED INFORMATION three months ended September 30, 2026 Canadian Natural Gas Pipelines U.S. Natural Gas Pipelines Mexico Natural Gas Pipelines Power and Energy Solutions(unaudited - millions of Canadian $) Corporate1 Total Revenues 1,528 1,840 427 235 — 4,030 Intersegment revenues2 — 25 — 1 (26) — 1,528 1,865 427 236 (26) 4,030 Income (loss) from equity investments 25 61 68 335 — 489 Operating costs2 (600) (643) (60) (160) 25 (1,438) Depreciation and amortization (422) (270) (24) (33) — (749) Asset impairment charge — — — (70) — (70) Segmented Earnings (Losses) 531 1,013 411 308 (1) 2,262 Interest expense (883) Allowance for funds used during construction 64 Foreign exchange gains (losses), net (4) Interest income and other 91 Income (Loss) from Continuing Operations before Income Taxes 1,530 Income tax (expense) recovery from continuing operations (312) Net Income (Loss) from Continuing Operations 1,218 Net Income (Loss) from Discontinued Operations, Net of Tax — Net Income (Loss) 1,218 Net (income) loss attributable to non-controlling interests (164) Net Income (Loss) Attributable to Controlling Interests 1,054 Preferred share dividends (28) Net Income (Loss) Attributable to Common Shares 1,026 Capital Spending Capital expenditures 326 819 21 14 14 1,194 Capital projects in development — — — 5 — 5 Contributions to equity investments 1 — — 212 — 213 327 819 21 231 14 1,412 1 Includes intersegment eliminations. 2 The Company records intersegment sales at contracted rates. For segmented reporting, these transactions are included as Intersegment revenues in the segment providing the service and Operating costs in the segment receiving the service. These transactions are eliminated on consolidation. Intersegment profit is recognized when the product or service has been provided to third parties or otherwise realized. TC Energy Third Quarter 2026 | 55
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three months ended September 30, 2025 Canadian Natural Gas Pipelines U.S. Natural Gas Pipelines Mexico Natural Gas Pipelines Power and Energy Solutions(unaudited - millions of Canadian $) Corporate1 Total Revenues 1,478 1,637 426 161 2 3,704 Intersegment revenues2 — 23 — — (23) — 1,478 1,660 426 161 (21) 3,704 Income (loss) from equity investments 29 66 29 221 — 345 Operating costs2 (594) (656) (25) (163) 18 (1,420) Depreciation and amortization (380) (269) (23) (29) — (701) Segmented Earnings (Losses) 533 801 407 190 (3) 1,928 Interest expense (847) Allowance for funds used during construction 55 Foreign exchange gains (losses), net 30 Interest income and other 47 Income (Loss) from Continuing Operations before Income Taxes 1,213 Income tax (expense) recovery from continuing operations (245) Net Income (Loss) from Continuing Operations 968 Net Income (Loss) from Discontinued Operations, Net of Tax (204) Net Income (Loss) 764 Net (income) loss attributable to non-controlling interests (127) Net Income (Loss) Attributable to Controlling Interests 637 Preferred share dividends (28) Net Income (Loss) Attributable to Common Shares 609 Capital Spending Capital expenditures 304 854 81 10 6 1,255 Capital projects in development — — — 2 — 2 Contributions to equity investments — 36 — 213 — 249 304 890 81 225 6 1,506 1 Includes intersegment eliminations. 2 The Company records intersegment sales at contracted rates. For segmented reporting, these transactions are included as Intersegment revenues in the segment providing the service and Operating costs in the segment receiving the service. These transactions are eliminated on consolidation. Intersegment profit is recognized when the product or service has been provided to third parties or otherwise realized. 56 | TC Energy Third Quarter 2026
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nine months ended September 30, 2026 Canadian Natural Gas Pipelines U.S. Natural Gas Pipelines Mexico Natural Gas Pipelines Power and Energy Solutions(unaudited - millions of Canadian $) Corporate1 Total Revenues 4,490 5,392 1,283 682 1 11,848 Intersegment revenues2 — 77 — 60 (137) — 4,490 5,469 1,283 742 (136) 11,848 Income (loss) from equity investments 76 246 142 784 — 1,248 Operating costs2 (1,733) (1,845) (155) (609) 131 (4,211) Depreciation and amortization (1,248) (790) (73) (98) — (2,209) Asset impairment charge — — — (70) — (70) Segmented Earnings (Losses) 1,585 3,080 1,197 749 (5) 6,606 Interest expense (2,580) Allowance for funds used during construction 163 Foreign exchange gains (losses), net 41 Interest income and other 158 Income (Loss) from Continuing Operations before Income Taxes 4,388 Income tax (expense) recovery from continuing operations (873) Net Income (Loss) from Continuing Operations 3,515 Net Income (Loss) from Discontinued Operations, Net of Tax — Net Income (Loss) 3,515 Net (income) loss attributable to non-controlling interests (518) Net Income (Loss) Attributable to Controlling Interests 2,997 Preferred share dividends (85) Net Income (Loss) Attributable to Common Shares 2,912 Capital Spending Capital expenditures 930 2,074 72 52 25 3,153 Capital projects in development — — — 14 — 14 Contributions to equity investments 3 5 — 667 — 675 933 2,079 72 733 25 3,842 1 Includes intersegment eliminations. 2 The Company records intersegment sales at contracted rates. For segmented reporting, these transactions are included as Intersegment revenues in the segment providing the service and Operating costs in the segment receiving the service. These transactions are eliminated on consolidation. Intersegment profit is recognized when the product or service has been provided to third parties or otherwise realized. TC Energy Third Quarter 2026 | 57
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nine months ended September 30, 2025 Canadian Natural Gas Pipelines U.S. Natural Gas Pipelines Mexico Natural Gas Pipelines Power and Energy Solutions(unaudited - millions of Canadian $) Corporate1 Total Revenues 4,304 5,199 1,012 544 12 11,071 Intersegment revenues2 — 74 — 50 (124) — 4,304 5,273 1,012 594 (112) 11,071 Income (loss) from equity investments 97 217 60 606 — 980 Operating costs2 (1,675) (1,906) (191) (478) 97 (4,153) Depreciation and amortization (1,126) (767) (72) (85) — (2,050) Segmented Earnings (Losses) 1,600 2,817 809 637 (15) 5,848 Interest expense (2,534) Allowance for funds used during construction 417 Foreign exchange gains (losses), net 142 Interest income and other 147 Income (Loss) from Continuing Operations before Income Taxes 4,020 Income tax (expense) recovery from continuing operations (875) Net Income (Loss) from Continuing Operations 3,145 Net Income (Loss) from Discontinued Operations, Net of Tax (233) Net Income (Loss) 2,912 Net (income) loss attributable to non-controlling interests (408) Net Income (Loss) Attributable to Controlling Interests 2,504 Preferred share dividends (84) Net Income (Loss) Attributable to Common Shares 2,420 Capital Spending Capital expenditures 1,052 2,308 501 46 17 3,924 Capital projects in development — — — 12 — 12 Contributions to equity investments — 141 — 617 — 758 1,052 2,449 501 675 17 4,694 1 Includes intersegment eliminations. 2 The Company records intersegment sales at contracted rates. For segmented reporting, these transactions are included as Intersegment revenues in the segment providing the service and Operating costs in the segment receiving the service. These transactions are eliminated on consolidation. Intersegment profit is recognized when the product or service has been provided to third parties or otherwise realized. 58 | TC Energy Third Quarter 2026
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Total Assets by Segment (unaudited - millions of Canadian $) September 30, 2026 December 31, 2025 Canadian Natural Gas Pipelines 31,298 31,371 U.S. Natural Gas Pipelines 60,018 56,617 Mexico Natural Gas Pipelines 16,801 16,342 Power and Energy Solutions 10,956 10,764 Corporate 4,600 3,460 123,673 118,554 Discontinued Operations — 197 123,673 118,751 TC Energy Third Quarter 2026 | 59
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5. REVENUES Disaggregation of Revenues The following tables summarize total Revenues for the three and nine months ended September 30, 2026 and 2025: three months ended September 30, 2026 Canadian Natural Gas Pipelines U.S. Natural Gas Pipelines Mexico Natural Gas Pipelines Power and Energy Solutions Total(unaudited - millions of Canadian $) Revenues from contracts with customers Capacity arrangements and transportation 1,528 1,487 108 — 3,123 Power generation — — — 57 57 Natural gas storage and other1 — 271 79 100 450 1,528 1,758 187 157 3,630 Sales-type lease income — — 240 — 240 Other revenues2 — 82 — 78 160 1,528 1,840 427 235 4,030 1 The Mexico Natural Gas Pipelines segment includes $73 million of revenues generated from non-lease components for the provision of operating and maintenance services with respect to sales-type leases on the in-service TGNH pipelines. 2 Includes the Company's marketing activities, financial instruments and $26 million of operating lease income. Refer to Note 14, Risk management and financial instruments, for additional information. three months ended September 30, 2025 Canadian Natural Gas Pipelines U.S. Natural Gas Pipelines Mexico Natural Gas Pipelines Power and Energy Solutions Total(unaudited - millions of Canadian $) Revenues from contracts with customers Capacity arrangements and transportation 1,478 1,337 110 — 2,925 Power generation — — — 50 50 Natural gas storage and other1 — 261 39 104 404 1,478 1,598 149 154 3,379 Sales-type lease income — — 277 — 277 Other revenues2 — 39 — 7 46 1,478 1,637 426 161 3,702 Corporate revenues3 2 3,704 1 The Mexico Natural Gas Pipelines segment includes $34 million of revenues generated from non-lease components for the provision of operating and maintenance services with respect to sales-type leases on the in-service TGNH pipelines. 2 Includes the Company's marketing activities, financial instruments and $29 million of operating lease income. Refer to Note 14, Risk management and financial instruments, for additional information. 3 Revenues generated from the Transition Services Agreement with South Bow. 60 | TC Energy Third Quarter 2026
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nine months ended September 30, 2026 Canadian Natural Gas Pipelines U.S. Natural Gas Pipelines Mexico Natural Gas Pipelines Power and Energy Solutions Total(unaudited - millions of Canadian $) Revenues from contracts with customers Capacity arrangements and transportation 4,490 4,520 321 — 9,331 Power generation — — — 159 159 Natural gas storage and other1 — 872 232 349 1,453 4,490 5,392 553 508 10,943 Sales-type lease income — — 730 — 730 Other revenues2 — — — 174 174 4,490 5,392 1,283 682 11,847 Corporate revenues3 1 11,848 1 The Mexico Natural Gas Pipelines segment includes $208 million of revenues generated from non-lease components for the provision of operating and maintenance services with respect to sales-type leases on the in-service TGNH pipelines. 2 Includes the Company's marketing activities, financial instruments and $85 million of operating lease income. Refer to Note 14, Risk management and financial instruments, for additional information. 3 Revenues generated from the Transition Services Agreement with South Bow. nine months ended September 30, 2025 Canadian Natural Gas Pipelines U.S. Natural Gas Pipelines Mexico Natural Gas Pipelines Power and Energy Solutions Total(unaudited - millions of Canadian $) Revenues from contracts with customers Capacity arrangements and transportation 4,304 4,129 333 — 8,766 Power generation — — — 170 170 Natural gas storage and other1 — 854 143 304 1,301 4,304 4,983 476 474 10,237 Sales-type lease income — — 536 — 536 Other revenues2 — 216 — 70 286 4,304 5,199 1,012 544 11,059 Corporate revenues3 12 11,071 1 The Mexico Natural Gas Pipelines segment includes $125 million of revenues generated from non-lease components for the provision of operating and maintenance services with respect to sales-type leases on the in-service TGNH pipelines. 2 Includes the Company's marketing activities, financial instruments and $88 million of operating lease income. Refer to Note 14, Risk management and financial instruments, for additional information. 3 Revenues generated from the Transition Services Agreement with South Bow. TC Energy Third Quarter 2026 | 61
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Contract Balances (unaudited - millions of Canadian $) September 30, 2026 December 31, 2025 Affected line item on the Condensed consolidated balance sheet Receivables from contracts with customers 1,376 1,822 Accounts receivable Contract assets 336 216 Other current assets Long-term contract assets 644 627 Other long-term assets Contract liabilities1 37 46 Accounts payable and other Long-term contract liabilities 31 — Other long-term liabilities 1 During the nine months ended September 30, 2026, $29 million (2025 – $21 million) of revenues were recognized that were included in contract liabilities at the beginning of the period. Contract assets and long-term contract assets primarily relate to the Company’s right to revenues for services completed but not invoiced at the reporting date on long-term committed capacity natural gas pipelines contracts. The change in contract assets is primarily related to the transfer to Accounts receivable when these rights become unconditional and the customer is invoiced, as well as the recognition of additional revenues that remain to be invoiced. Contract liabilities and long-term contract liabilities primarily represent unearned revenue for contracted services. Future Revenues from Remaining Performance Obligations At September 30, 2026, future revenues from long-term pipeline capacity arrangements and transportation as well as natural gas storage and other contracts extending through 2055 are approximately $39.0 billion, of which approximately $4.8 billion is expected to be recognized during the remainder of 2026. Factoring Arrangement In August 2026, TC Energy entered into a factoring arrangement with the CFE and a major domestic bank in Mexico. Under the arrangement, TC Energy is factoring a portion of its monthly invoices for services provided on the TGNH system from August to November 2026. Invoices are factored to the bank without recourse to TC Energy and TC Energy will continue to receive invoiced amounts within the contractual payment period. The factoring arrangement resulted in a lease modification for accounting purposes of the TGNH Transportation Service Agreement (TSA) with the CFE. As a result, the Company remeasured and reallocated the remaining contract consideration to the lease and non-lease components based on their estimated stand-alone selling prices as of the modification date. The Company used an expected cost plus margin approach to estimate the stand-alone selling prices of the non-lease components and a residual approach to estimate the stand-alone selling prices of the lease components. Significant judgments included estimating the applicable costs and margins and determining that the fair value of the underlying assets approximated their carrying amount for purposes of reassessing lease classification and estimating unguaranteed residual values. The change in allocation is accounted for prospectively. TC Energy has recorded factored amounts in Accounts payable and other on the Condensed consolidated balance sheet. Cash amounts from the factoring arrangement are included in Financing activities in the Condensed consolidated statement of cash flows. During third quarter 2026, TC Energy assigned and received payment for receivables having an aggregate face value of $84 million (US$59 million). 62 | TC Energy Third Quarter 2026
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6. ASSETS HELD FOR SALE Guadalajara-Manzanillo Pipeline On September 21, 2026, the Company announced that it had entered into an agreement to sell Energía Occidente de México, the entity that owns the Guadalajara-Manzanillo (Guadalajara) pipeline within the Mexico Natural Gas Pipelines segment, to affiliates of ESENTIA Energy Development, S.A.B. de C.V. for a gross purchase price of $560 million (US$400 million), excluding certain closing adjustments. The sale is expected to close in the first half of 2027, subject to customary closing conditions, regulatory approvals and consents. At September 30, 2026, the related assets and liabilities classified as held for sale were as follows: (unaudited - millions of Canadian $) September 30, 2026 Assets Held for Sale Current assets 40 Property, plant and equipment, net 456 Other long-term assets 2 498 Liabilities Related to Assets Held for Sale Current liabilities 13 Other long-term liabilities 74 87 7. ASSET IMPAIRMENT CHARGE Bécancour On September 16, 2026, the Company's 20-year electricity supply contract with Hydro-Québec (HQ) expired. Based on its assessment of the expected future use of the facility, the Company determined that certain equipment is not expected to be utilized and will be retired and abandoned in place. Accordingly, the Company recorded a pre-tax, non-cash asset impairment charge of $70 million related to the carrying value of this equipment within the Power and Energy Solutions segment in the Condensed consolidated statement of income. 8. INCOME TAXES Effective Tax Rates The effective income tax rates were 20 per cent and 22 per cent for the nine months ended September 30, 2026 and 2025, respectively. The decrease in the effective income tax rate is primarily due to the impact of Mexico foreign exchange exposure partially offset by changes in geographic and business mix of earnings and higher flow-through income taxes. TC Energy Third Quarter 2026 | 63
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9. LONG-TERM DEBT Long-Term Debt Issued Long-term debt issued by the Company in the nine months ended September 30, 2026 included the following: (unaudited - millions of Canadian $, unless otherwise noted) Company Issue date Type Maturity date Amount Interest rate TransCanada PipeLines Limited June 2026 Medium Term Notes June 2036 700 4.61% June 2026 Medium Term Notes June 2056 600 5.36% Columbia Pipelines Operating Company LLC May 2026 Senior Unsecured Notes May 2036 US 750 5.51% Subsequent Debt Issued On October 29, 2026, TC Louisiana Intrastate Pipeline LLC entered into a US$200 million senior unsecured term loan maturing in October 2029, bearing interest at a floating rate. Long-Term Debt Repaid/Retired Long-term debt repaid/retired by the Company in the nine months ended September 30, 2026 included the following: (unaudited - millions of Canadian $, unless otherwise noted) Company Repayment date Type Amount Interest rate TransCanada PipeLines Limited April 2026 Medium Term Notes 400 4.35% February 2026 Medium Term Notes 241 8.29% NGTL Limited Partnership August 2026 Medium Term Notes US 33 7.50% June 2026 Medium Term Notes 45 8.46% May 2026 Medium Term Notes 45 8.88% Columbia Pipelines Holding Company LLC July 2026 Senior Unsecured Notes US 300 6.06% ANR Pipeline Company June 2026 Senior Unsecured Notes US 240 4.14% TC Energía Mexicana, S. de R.L. de C.V. Various Senior Unsecured Term Loan US 604 Floating In May 2026, TC Energía Mexicana, S. de R.L. de C.V. terminated its US$500 million senior unsecured revolving credit facility, with interest at a floating rate on which no amount was outstanding. The related unamortized debt issue costs of $2 million were included in Interest expense in the Condensed consolidated statement of income. Subsequent Debt Repayment On October 29, 2026, TC Energía Mexicana, S. de R.L. de C.V. fully repaid and retired its senior unsecured term loan bearing interest at a floating rate, of which US$89 million was outstanding. Capitalized Interest In the three and nine months ended September 30, 2026, TC Energy capitalized interest related to capital projects of $2 million and $7 million, respectively (2025 – $2 million and $7 million, respectively). 64 | TC Energy Third Quarter 2026
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10. JUNIOR SUBORDINATED NOTES Junior Subordinated Notes Issued Junior subordinated notes issued by the Company in the nine months ended September 30, 2026 included the following: (unaudited - millions of Canadian $, unless otherwise noted) Company Issue date Type Maturity date Amount Interest rate TransCanada PipeLines Limited April 2026 Junior Subordinated Notes October 2056 US 500 6.13% April 2026 Junior Subordinated Notes October 2056 US 500 6.38% February 2026 Junior Subordinated Notes August 2056 500 5.13% In April 2026, TCPL issued US$500 million of junior subordinated notes maturing in October 2056 with a fixed interest rate of 6.13 per cent until October 17, 2031, and resetting every five years thereafter. The rate on the junior subordinated notes will reset every five years commencing October 2031 until October 2056 to the then current Five-Year Treasury Rate, as defined in the document governing the subordinated notes, plus 2.25 per cent per annum, subject to a rate-reset minimum. The junior subordinated notes are callable at TCPL's option at any time from July 17, 2031 to October 17, 2031 and on each interest payment and reset date thereafter at 100 per cent of the principal amount plus accrued and unpaid interest to the date of redemption. In April 2026, TCPL issued US$500 million of junior subordinated notes maturing in October 2056 with a fixed interest rate of 6.38 per cent until October 17, 2036, and resetting every five years thereafter. The rate on the junior subordinated notes will reset every five years commencing October 2036 until October 2056 to the then current Five-Year Treasury Rate, as defined in the document governing the subordinated notes, plus 2.12 per cent per annum, subject to a rate-reset minimum. The junior subordinated notes are callable at TCPL's option at any time from July 17, 2036 to October 17, 2036 and on each interest payment and reset date thereafter at 100 per cent of the principal amount plus accrued and unpaid interest to the date of redemption. In February 2026, TCPL issued $500 million of junior subordinated notes maturing in 2056 with a fixed interest rate of 5.13 per cent per year until August 20, 2031, and resetting every five years thereafter. The rate on the junior subordinated notes will reset every five years commencing August 2031 until August 2056 to the then Five-Year Government of Canada Yield, as defined in the document governing the subordinated notes, plus 2.24 per cent per annum, subject to a rate-reset minimum. The junior subordinated notes are callable at TCPL's option at any time from May 20, 2031 to August 20, 2031 and on each interest payment and reset date thereafter at 100 per cent of the principal amount plus accrued and unpaid interest to the date of redemption. Pursuant to the terms of the junior subordinated notes issued in 2026, TCPL has the option to defer payment of interest for one or more periods of up to ten years without giving rise to an event of default and without permitting acceleration of payment. TC Energy and TCPL would be prohibited from declaring or paying dividends during any deferral period. The junior subordinated notes are subordinated in right of payment to existing and future senior indebtedness and other obligations of TCPL. Junior Subordinated Notes Repaid/Retired In August 2026, TCPL exercised its option to fully repay and retire the US$1.2 billion junior subordinated notes that had a maturity date of 2076, bearing interest at 6.13 per cent to TransCanada Trust (the Trust). The related unamortized debt issue costs of $18 million were included in Interest expense in the Condensed consolidated statement of income. The proceeds from the repayment were used by the Trust to fund the redemption price of the US$1.2 billion in aggregate principal amount o f o u t s t a n d i n g T r u s t N o t e s – S e r i e s 2 0 1 6 ‑ A , i n A u g u s t 2 0 2 6 p u r s u a n t t o t h e i r t e r m s . TC Energy Third Quarter 2026 | 65
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11. COMMON SHARES AND PREFERRED SHARES The Board of Directors of TC Energy declared quarterly dividends as follows: three months ended September 30 nine months ended September 30 (unaudited - Canadian $, rounded to two decimals unless otherwise noted) 2026 2025 2026 2025 per common share 0.8775 0.85 2.6325 2.55 per Series 1 preferred share 0.31 0.31 0.93 0.93 per Series 2 preferred share 0.26 0.28 0.78 0.91 per Series 3 preferred share 0.26 0.26 0.77 0.47 per Series 4 preferred share 0.22 0.24 0.66 0.79 per Series 5 preferred share 0.28 0.12 0.84 0.37 per Series 6 preferred share — 0.27 — 0.82 per Series 7 preferred share 0.37 0.37 1.12 1.12 per Series 9 preferred share 0.32 0.32 0.95 0.95 per Series 10 preferred share 0.29 0.32 0.86 0.97 per Series 11 preferred share — 0.21 — 0.42 On January 30, 2026, the remaining 1,929,407 Series 6 preferred shares were converted, on a one-for-one basis, into 1,929,407 Series 5 preferred shares and Series 6 preferred shares were delisted from the TSX at the close of markets on January 30, 2026. 12. OTHER COMPREHENSIVE INCOME (LOSS) AND ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS) Components of other comprehensive income (loss), including the portion attributable to non-controlling interests and related tax effects, were as follows: three months ended September 30, 2026 Before tax amount Income tax (expense) recovery Net of tax amount(unaudited - millions of Canadian $) Foreign currency translation gains and losses on net investment in foreign operations 31 4 35 Change in fair value of cash flow hedges 3 — 3 Reclassification to net income of (gains) losses on cash flow hedges (6) 2 (4) Other comprehensive income (loss) on equity investments (72) 18 (54) Other Comprehensive Income (Loss) (44) 24 (20) three months ended September 30, 2025 Before tax amount Income tax (expense) recovery Net of tax amount(unaudited - millions of Canadian $) Foreign currency translation gains and losses on net investment in foreign operations 420 11 431 Change in fair value of cash flow hedges 28 (4) 24 Reclassification to net income of (gains) losses on cash flow hedges (24) 3 (21) Other comprehensive income (loss) on equity investments (13) 3 (10) Other Comprehensive Income (Loss) 411 13 424 66 | TC Energy Third Quarter 2026
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nine months ended September 30, 2026 Before tax amount Income tax (expense) recovery Net of tax amount(unaudited - millions of Canadian $) Foreign currency translation gains and losses on net investment in foreign operations 738 7 745 Change in fair value of cash flow hedges 43 (10) 33 Reclassification to net income of (gains) losses on cash flow hedges (49) 12 (37) Other comprehensive income (loss) on equity investments (91) 23 (68) Other Comprehensive Income (Loss) 641 32 673 nine months ended September 30, 2025 Before tax amount Income tax (expense) recovery Net of tax amount(unaudited - millions of Canadian $) Foreign currency translation gains and losses on net investment in foreign operations (657) (2) (659) Change in fair value of net investment hedges 1 — 1 Change in fair value of cash flow hedges (24) 8 (16) Reclassification to net income of (gains) losses on cash flow hedges 25 (8) 17 Reclassification to net income of actuarial (gains) losses on pension and other post-retirement benefit plans 1 — 1 Other comprehensive income (loss) on equity investments (33) 7 (26) Other Comprehensive Income (Loss) (687) 5 (682) The changes in AOCI by component, net of tax, were as follows: three months ended September 30, 2026 Currency translation adjustments Cash flow hedges Pension and other post- retirement benefit plans adjustments Equity investments Total(unaudited - millions of Canadian $) AOCI balance at July 1, 2026 372 (10) 101 617 1,080 Other comprehensive income (loss) before reclassifications1 28 3 — (52) (21) Amounts reclassified from AOCI — (4) — (2) (6) Net current period other comprehensive income (loss) 28 (1) — (54) (27) AOCI balance at September 30, 2026 400 (11) 101 563 1,053 1 Other comprehensive income (loss) before reclassifications on currency translation adjustments is net of non-controlling interest gains of $7 million (2025 – gains of $235 million). TC Energy Third Quarter 2026 | 67
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nine months ended September 30, 2026 Currency translation adjustments Cash flow hedges Pension and other post- retirement benefit plans adjustments Equity investments Total(unaudited - millions of Canadian $) AOCI balance at January 1, 2026 22 (7) 101 631 747 Other comprehensive income (loss) before reclassifications1 378 33 — (67) 344 Amounts reclassified from AOCI2 — (37) — (1) (38) Net current period other comprehensive income (loss) 378 (4) — (68) 306 AOCI balance at September 30, 2026 400 (11) 101 563 1,053 1 Other comprehensive income (loss) before reclassifications on currency translation adjustments is net of non-controlling interest gains of $367 million (2025 – losses of $352 million). 2 Gains related to cash flow hedges reported in AOCI and expected to be reclassified to net income in the next 12 months are estimated to be $11 million ($8 million after tax) at September 30, 2026. These estimates assume constant commodity prices, interest rates and foreign exchange rates over time; however, the amounts reclassified will vary based on the actual value of these factors at the date of settlement. Details about reclassifications out of AOCI into the Condensed consolidated statement of income were as follows: three months ended September 30 nine months ended September 30 Affected line item in the Condensed consolidated statement of income1(unaudited - millions of Canadian $) 2026 2025 2026 2025 Cash flow hedges Commodities 6 2 18 17 Revenues (Power and Energy Solutions) Foreign exchange 3 25 40 (33) Interest expense and Foreign exchange gains (losses), net Interest rate (3) (3) (9) (9) Interest expense 6 24 49 (25) Total before tax (2) (3) (12) 8 Income tax (expense) recovery 4 21 37 (17) Net of tax Pension and other post-retirement benefit plans Amortization of actuarial gains (losses) — — — (1) Plant operating costs and other2 — — — — Income tax (expense) recovery — — — (1) Net of tax Equity investments Equity income (loss) 3 — 2 2 Income (loss) from equity investments (1) — (1) — Income tax (expense) recovery 2 — 1 2 Net of tax 1 All amounts in parentheses indicate expenses to the Condensed consolidated statement of income. 2 These AOCI components are included in the computation of net benefit cost (recovery). Refer to Note 13, Employee post-retirement benefits, for additional information. 68 | TC Energy Third Quarter 2026
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13. EMPLOYEE POST-RETIREMENT BENEFITS The components of the net benefit cost (recovery) recognized for the Company’s pension benefit plans and other post-retirement benefit plans were as follows: three months ended September 30 nine months ended September 30 Pension benefit plans Other post-retirement benefit plans Pension benefit plans Other post-retirement benefit plans (unaudited - millions of Canadian $) 2026 2025 2026 2025 2026 2025 2026 2025 Service cost1 22 25 — — 65 75 1 1 Other components of net benefit cost (recovery)1 Interest cost 41 41 3 4 124 122 10 11 Expected return on plan assets (63) (62) (4) (4) (189) (187) (12) (12) Amortization of past service costs — — (1) — — — (2) (1) Amortization of regulatory asset — — — — — — (1) — (22) (21) (2) — (65) (65) (5) (2) Net Benefit Cost (Recovery) — 4 (2) — — 10 (4) (1) 1 Service cost and other components of net benefit cost (recovery) are included in Plant operating costs and other in the Condensed consolidated statement of income. TC Energy Third Quarter 2026 | 69
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14. RISK MANAGEMENT AND FINANCIAL INSTRUMENTS Risk Management Overview TC Energy has exposure to market risk and counterparty credit risk and has strategies, policies and limits in place to manage the impact of these risks on its earnings, cash flows and, ultimately, shareholder value. Counterparty Credit Risk TC Energy’s exposure to counterparty credit risk includes its cash and cash equivalents, accounts receivable, available-for-sale assets, the fair value of derivative assets, net investment in leases and certain contract assets in Mexico. Market events causing disruptions in global energy demand and supply may contribute to economic uncertainties impacting a number of TC Energy's customers. While the majority of the Company's credit exposure is to large creditworthy entities, TC Energy maintains close monitoring and communication with those counterparties experiencing greater financial pressures. Refer to TC Energy's 2025 Annual Report for more information about the factors that mitigate the Company's counterparty credit risk exposure. The Company reviews financial assets carried at amortized cost for impairment using the lifetime expected loss of the financial asset at initial recognition and throughout the life of the financial asset. TC Energy uses historical credit loss and recovery data, adjusted for management's judgment regarding current economic and credit conditions, along with reasonable and supportable forecasts to determine any impairment, which is recognized in Plant operating costs and other. For the three and nine months ended September 30, 2026, the Company recorded an expense of $10 million and $16 million (2025 – recovery of $14 million and an expense of $90 million, respectively) on the expected credit loss (ECL) provision before tax with respect to the net investment in leases associated with in-service TGNH pipelines. At September 30, 2026, the balance of the ECL provision was $163 million (December 31, 2025 – $141 million) with respect to the net investment in leases associated with in-service TGNH pipelines. The ECL provision is driven primarily by a probability of default measure for the counterparty, which is calculated using information published by an external third party. Other than the ECL provision noted above, the Company had no significant credit losses at September 30, 2026, and there were no significant credit risk concentrations or amounts past due or impaired. TC Energy has significant credit and performance exposure to financial institutions that hold cash deposits and provide committed credit lines and letters of credit that help manage the Company's exposure to counterparties and provide liquidity in commodity, foreign exchange and interest rate derivative markets. TC Energy's portfolio of financial sector exposure consists primarily of highly-rated investment grade, systemically important financial institutions. Net Investment in Foreign Operations The Company hedges a portion of its net investment in foreign operations (on an after-tax basis) with U.S. dollar-denominated debt as appropriate. The notional amounts and fair values of U.S. dollar-denominated debt designated as a net investment hedge were as follows: (unaudited - millions of Canadian $, unless otherwise noted) September 30, 2026 December 31, 2025 Notional amount 24,300 (US 17,100) 25,700 (US 18,700) Fair value 23,500 (US 16,500) 25,800 (US 18,800) 70 | TC Energy Third Quarter 2026
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Non-Derivative Financial Instruments Fair value of non-derivative financial instruments Available-for-sale assets are recorded at fair value which is calculated using quoted market prices where available in addition to the Company's LMCI equity securities which are classified in Level I of the fair value hierarchy. Certain other non-derivative financial instruments included in Cash and cash equivalents, Accounts receivable, Other current assets, Net investment in leases, Restricted investments, Other long-term assets, Notes payable, Accounts payable and other, Dividends payable, Accrued interest and Other long-term liabilities have carrying amounts that approximate their fair value due to the nature of the item or the short time to maturity. Credit risk has been taken into consideration when calculating the fair value of non-derivative financial instruments. Balance sheet presentation of non-derivative financial instruments The following table details the fair value of non-derivative financial instruments, excluding those where carrying amounts approximate fair value and would be classified in Level II of the fair value hierarchy: September 30, 2026 December 31, 2025 (unaudited - millions of Canadian $) Carrying amount Fair value Carrying amount Fair value Long-term debt, including current portion1,2 (47,615) (46,091) (46,792) (47,720) Junior subordinated notes (12,639) (12,380) (12,094) (12,061) (60,254) (58,471) (58,886) (59,781) 1 Long-term debt is recorded at amortized cost, except for $4.9 billion (December 31, 2025 – $4.0 billion) that is attributed to hedged risk and recorded at fair value. 2 Net income (loss) for the three and nine months ended September 30, 2026 included unrealized gains of $208 million and $285 million, respectively (2025 – unrealized losses of $10 million and $140 million, respectively) for fair value adjustments attributable to the hedged interest rate risk associated with interest rate swap fair value hedging relationships. The following tables summarize additional information about the Company's restricted investments that were classified as available-for-sale assets and equity securities with readily determinable fair values: September 30, 2026 December 31, 2025 (unaudited - millions of Canadian $) LMCI restricted investments Other restricted investments1 LMCI restricted investments Other restricted investments1 Fair value of fixed income securities2,3 Maturing within 1 year — 22 — 94 Maturing within 1-5 years 51 186 26 251 Maturing within 5-10 years 1,941 97 1,846 4 Maturing after 10 years 9 45 — 16 Fair value of equity securities2,4 1,447 108 1,252 94 3,448 458 3,124 459 1 Other restricted investments have been set aside to fund insurance claim losses to be paid by the Company's wholly-owned captive subsidiary and to pay for certain active employee medical benefits. 2 Available-for-sale assets and equity securities with readily determinable fair values are recorded at fair value and included in Other current assets and Restricted investments on the Company's Condensed consolidated balance sheet. 3 Classified in Level II of the fair value hierarchy. 4 Classified in Level I of the fair value hierarchy. TC Energy Third Quarter 2026 | 71
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September 30, 2026 September 30, 2025 (unaudited - millions of Canadian $) LMCI restricted investments1 Other restricted investments2 LMCI restricted investments1 Other restricted investments2 Net unrealized gains (losses) in the period three months ended (67) (8) 119 (14) nine months ended 112 (1) 192 (6) Net realized gains (losses) in the period3 three months ended 2 (1) 13 21 nine months ended 28 (1) 1 21 1 Unrealized and realized gains (losses) arising from changes in the fair value of LMCI restricted investments impact the subsequent amounts to be collected through tolls to cover future pipeline abandonment costs. As a result, the Company records these gains and losses as regulatory liabilities or regulatory assets. 2 Unrealized and realized gains (losses) on other restricted investments are included in Interest income and other in the Condensed consolidated statement of income. 3 Realized gains (losses) on the sale of LMCI restricted investments are determined using the average cost basis. Derivative Instruments Fair value of derivative instruments The fair value of foreign exchange and interest rate derivatives has been calculated using the income approach which uses period-end market rates and applies a discounted cash flow valuation model. The fair value of commodity derivatives has been calculated using quoted market prices where available. In the absence of quoted market prices, third-party broker quotes or other valuation techniques have been used. The fair value of options has been calculated using the Black-Scholes pricing model. Credit risk has been taken into consideration when calculating the fair value of derivative instruments. Unrealized gains and losses on derivative instruments are not necessarily representative of the amounts that will be realized on settlement. In some cases, even though the derivatives are considered to be effective economic hedges, they do not meet the specific criteria for hedge accounting treatment or are not designated as a hedge and are accounted for at fair value with changes in fair value recorded in net income in the period of change. This may expose the Company to increased variability in reported earnings because the fair value of the derivative instruments can fluctuate significantly from period to period. The recognition of gains and losses on derivatives for Canadian natural gas regulated pipeline exposures is determined through the regulatory process. Gains and losses arising from changes in the fair value of derivatives accounted for as part of rate-regulated accounting, including those that qualify for hedge accounting treatment, are expected to be refunded or recovered through the tolls charged by the Company. As a result, these gains and losses are deferred as regulatory liabilities or regulatory assets and are refunded to or collected from the ratepayers in subsequent years when the derivative settles. 72 | TC Energy Third Quarter 2026
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Balance sheet presentation of derivative instruments The balance sheet classification of the fair value of derivative instruments was as follows: at September 30, 2026 Cash flow hedges Fair value hedges Held for trading Total fair value of derivative instruments1(unaudited - millions of Canadian $) Other current assets Commodities2 15 — 391 406 Foreign exchange 8 — 39 47 Interest rate — 2 — 2 23 2 430 455 Other long-term assets Commodities2 3 — 130 133 Foreign exchange — — 4 4 3 — 134 137 Total Derivative Assets 26 2 564 592 Accounts payable and other Commodities2 — — (333) (333) Foreign exchange — — (124) (124) Interest rate — (28) — (28) — (28) (457) (485) Other long-term liabilities Commodities2 — — (171) (171) Foreign exchange (33) — (17) (50) Interest rate — (276) — (276) (33) (276) (188) (497) Total Derivative Liabilities (33) (304) (645) (982) Total Derivatives (7) (302) (81) (390) 1 Fair value equals carrying value. 2 Includes purchases and sales of power and natural gas. TC Energy Third Quarter 2026 | 73
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at December 31, 2025 Cash flow hedges Fair value hedges Held for trading Total fair value of derivative instruments1(unaudited - millions of Canadian $) Other current assets Commodities2 13 — 371 384 Foreign exchange 9 — 42 51 Interest rate — 3 — 3 22 3 413 438 Other long-term assets Commodities2 2 — 122 124 Foreign exchange — — 15 15 Interest rate — 22 — 22 2 22 137 161 Total Derivative Assets 24 25 550 599 Accounts payable and other Commodities2 (1) — (341) (342) Foreign exchange — — (30) (30) Interest rate — (8) — (8) (1) (8) (371) (380) Other long-term liabilities Commodities2 (1) — (61) (62) Foreign exchange (51) — (2) (53) Interest rate — (34) — (34) (52) (34) (63) (149) Total Derivative Liabilities (53) (42) (434) (529) Total Derivatives (29) (17) 116 70 1 Fair value equals carrying value. 2 Includes purchases and sales of power and natural gas. The majority of derivative instruments held for trading have been entered into for risk management purposes and all are subject to the Company's risk management strategies, policies and limits. These include derivatives that have not been designated as hedges or do not qualify for hedge accounting treatment but have been entered into as economic hedges to manage the Company's exposures to market risk. Non-derivatives in fair value hedging relationships The following table details amounts recorded on the Condensed consolidated balance sheet in relation to cumulative adjustments for fair value hedges included in the carrying amount of the hedged liabilities: Carrying amount Fair value hedging adjustments1 (unaudited - millions of Canadian $) September 30, 2026 December 31, 2025 September 30, 2026 December 31, 2025 Long-term debt (4,683) (4,068) 264 (22) 1 At September 30, 2026, adjustments for discontinued hedging relationships included in these balances was a liability of $38 million (December 31, 2025 – $39 million). 74 | TC Energy Third Quarter 2026
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Notional and maturity summary The maturity and notional amount or quantity outstanding related to the Company's derivative instruments was as follows: at September 30, 2026 Power Natural gas Foreign exchange Interest rate(unaudited) Net sales (purchases)1 10,030 105 — — Millions of U.S. dollars — — 7,435 3,200 Millions of Canadian dollars — — — 400 Millions of Mexican pesos — — 18,000 — Maturity dates 2026-2044 2026-2032 2026-2030 2030-2039 1 Volumes for power and natural gas derivatives are in GWh and Bcf, respectively. at December 31, 2025 Power Natural gas Foreign exchange Interest rate(unaudited) Net sales (purchases)1 10,221 26 — — Millions of U.S. dollars — — 6,342 2,950 Millions of Mexican pesos — — 15,750 — Maturity dates 2026-2044 2026-2032 2026-2030 2030-2034 1 Volumes for power and natural gas derivatives are in GWh and Bcf, respectively. Unrealized and Realized Gains (Losses) on Derivative Instruments The following summary does not include hedges of the net investment in foreign operations: three months ended September 30 nine months ended September 30 (unaudited - millions of Canadian $) 2026 2025 2026 2025 Derivative Instruments Held for Trading1 Unrealized gains (losses) in the period Commodities2 76 (63) (67) (36) Foreign exchange (15) (68) (124) 169 Realized gains (losses) in the period Commodities (8) 20 (284) (18) Foreign exchange (30) 39 36 111 Interest rate 1 1 3 6 Derivative Instruments in Hedging Relationships Realized gains (losses) in the period Commodities 8 3 29 17 Foreign exchange 3 2 8 6 Interest rate (3) (8) (8) (24) 1 Realized 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 h e l d ‑ f o r ‑ t r a d i n g d e r i v a t i v e i n s t r u m e n t s a r e i n c l u d e d o n a n e t b a s i s i n F o r e i g n e x c h a n g e ( g a i n s ) l o s s e s , n e t a n d I n t e r e s t e x p e n s e , r e s p e c t i v e l y , i n t h e Condensed consolidated statement of income. 2 In the three and nine months ended September 30, 2026, no amounts were reclassified to Net income (loss) from AOCI related to discontinued cash flow hedges (2025 – unrealized gains of less than $1 million and $1 million, respectively). TC Energy Third Quarter 2026 | 75
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Derivatives in cash flow hedging relationships The components of OCI (Note 12) related to the change in fair value of derivatives in cash flow hedging relationships before tax were as follows: three months ended September 30 nine months ended September 30 (unaudited - millions of Canadian $, pre tax) 2026 2025 2026 2025 Gains (losses) in fair value of derivative instruments recognized in OCI Commodities 5 3 23 4 Foreign exchange (2) 25 20 (28) 3 28 43 (24) Effect of fair value and cash flow hedging relationships The following table details amounts presented in the Condensed consolidated statement of income in which the effects of fair value or cash flow hedging relationships were recorded: three months ended September 30 nine months ended September 30 (unaudited - millions of Canadian $) 2026 2025 2026 2025 Fair Value Hedges Interest rate contracts1 Hedged items (58) (44) (167) (133) Derivatives designated as hedging instruments (3) (8) (8) (24) Cash Flow Hedges Reclassification of gains (losses) on derivative instruments from AOCI to Net income (loss)2 Commodities3 6 2 18 17 Foreign exchange4 3 25 40 (33) Interest rate1 (3) (3) (9) (9) 1 Presented within Interest expense in the Condensed consolidated statement of income. 2 Refer to Note 12, Other comprehensive income (loss) and accumulated other comprehensive income (loss), for the components of OCI related to derivatives in cash flow hedging relationships. 3 Presented within Revenues (Power and Energy Solutions) in the Condensed consolidated statement of income. In the three and nine months ended September 30, 2026, no amounts were reclassified to Net income (loss) from AOCI related to discontinued cash flow hedges (2025 – unrealized gains of less than $1 million and $1 million, respectively). 4 Presented within Interest expense and Foreign exchange (gains) losses, net in the Condensed consolidated statement of income. 76 | TC Energy Third Quarter 2026
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Offsetting of derivative instruments The Company enters into derivative contracts with the right to offset in the normal course of business as well as in the event of default. TC Energy has no master netting agreements; however, similar contracts are entered into containing rights to offset. The Company has elected to present the fair value of derivative instruments with the right to offset on a gross basis on the Condensed consolidated balance sheet. The following tables show the impact on the presentation of the fair value of derivative instrument assets and liabilities had the Company elected to present these contracts on a net basis: at September 30, 2026 Gross derivative instruments Amounts available for offset1 Net amounts(unaudited - millions of Canadian $) Derivative instrument assets Commodities 539 (415) 124 Foreign exchange 51 (51) — Interest rate 2 (2) — 592 (468) 124 Derivative instrument liabilities Commodities (504) 415 (89) Foreign exchange (174) 51 (123) Interest rate (304) 2 (302) (982) 468 (514) 1 Amounts available for offset do not include cash collateral pledged or received. at December 31, 2025 Gross derivative instruments Amounts available for offset1 Net amounts(unaudited - millions of Canadian $) Derivative instrument assets Commodities 508 (367) 141 Foreign exchange 66 (48) 18 Interest rate 25 (5) 20 599 (420) 179 Derivative instrument liabilities Commodities (404) 367 (37) Foreign exchange (83) 48 (35) Interest rate (42) 5 (37) (529) 420 (109) 1 Amounts available for offset do not include cash collateral pledged or received. With respect to the derivative instruments presented above, the Company provided cash collateral of $119 million and letters of credit of $58 million at September 30, 2026 (December 31, 2025 – $93 million and $73 million, respectively) to its counterparties. At September 30, 2026, the Company held cash collateral of $1 million and $88 million of letters of credit (December 31, 2025 – less than $1 million and $102 million, respectively) from counterparties on asset exposures. Only cash collateral that has been transferred and held at the reporting date is included in collateral disclosures. Margin payable but not yet posted of $31 million at September 30, 2026 (December 31, 2025 – $4 million) represents a financial obligation and is excluded from provided cash collateral balances. TC Energy Third Quarter 2026 | 77
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Credit-risk-related contingent features of derivative instruments Derivative contracts entered into to manage market risk often contain financial assurance provisions that allow parties to the contracts to manage credit risk. These provisions may require collateral to be provided if a credit-risk-related contingent event occurs, such as a downgrade in the Company’s credit rating to non-investment grade. The Company may also need to provide collateral if the fair value of its derivative financial instruments exceeds pre-defined exposure limits. Based on contracts in place and market prices at September 30, 2026, the aggregate fair value of all derivative instruments with credit-risk-related contingent features that were in a net liability position was $5 million (December 31, 2025 – net liability of $5 million), for which the Company has provided no collateral in the normal course of business. If the c r e d i t ‑ r i s k ‑ r e l a t e d c o n t i n g e n t f e a t u r e s i n t h e s e a g r e e m e n t s w e r e t r i g g e r e d o n September 30, 2026, the Company would have been required to provide collateral equal to the fair value of the related derivative instruments discussed above. Collateral may also need to be provided should the fair value of derivative instruments exceed pre-defined contractual exposure limit thresholds. The Company has sufficient liquidity in the form of cash and undrawn committed revolving credit facilities to meet these contingent obligations should they arise. Fair Value Hierarchy The Company’s financial assets and liabilities recorded at fair value have been categorized into three categories based on a fair value hierarchy. Levels How fair value has been determined Level I Quoted prices in active markets for identical assets and liabilities that the Company has the ability to access at the measurement date. An active market is a market in which frequency and volume of transactions provides pricing information on an ongoing basis. Level II This category includes interest rate and foreign exchange derivative assets and liabilities where fair value is determined using the income approach and commodity derivatives where fair value is determined using the market approach. Inputs include published exchange rates, interest rates, interest rate swap curves, yield curves and broker quotes from external data service providers. Level III This category includes long-dated commodity transactions in certain markets where liquidity is low. The Company uses the most observable inputs available or alternatively long-term broker quotes or negotiated commodity prices that have been contracted for under similar terms in determining an appropriate estimate of these transactions. Where appropriate, these long-dated prices are discounted to reflect the expected pricing from the applicable markets. There is uncertainty caused by using unobservable market data which may not accurately reflect possible future changes in fair value. The fair value of the Company’s derivative assets and liabilities measured on a recurring basis, including both current and n o n ‑ c u r r e n t p o r t i o n s , w e r e c a t e g o r i z e d a s f o l l o w s : at September 30, 2026 Quoted prices in active markets (Level I) Significant other observable inputs (Level II)1 Significant unobservable inputs (Level III)1(unaudited - millions of Canadian $) Total Derivative instrument assets Commodities 149 361 29 539 Foreign exchange — 51 — 51 Interest rate — 2 — 2 Derivative instrument liabilities Commodities (104) (351) (49) (504) Foreign exchange — (174) — (174) Interest rate — (304) — (304) 45 (415) (20) (390) 1 There were no transfers from Level II to Level III for the nine months ended September 30, 2026. 78 | TC Energy Third Quarter 2026
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at December 31, 2025 Quoted prices in active markets (Level I) Significant other observable inputs (Level II)1 Significant unobservable inputs (Level III)1(unaudited - millions of Canadian $) Total Derivative instrument assets Commodities 154 279 75 508 Foreign exchange — 66 — 66 Interest rate — 25 — 25 Derivative instrument liabilities Commodities (151) (252) (1) (404) Foreign exchange — (83) — (83) Interest rate — (42) — (42) 3 (7) 74 70 1 There were no transfers from Level II to Level III for the year ended December 31, 2025. The Company has entered into contracts which commenced in 2025 and 2026 to sell 50 MW of power with terms ranging from 15 to 20 years provided from specified renewable sources in the Province of Alberta. The fair value of these contracts is classified in Level III of the fair value hierarchy and is based on the assumption that the contract volumes will be sourced approximately 70 per cent from wind generation, 10 per cent from solar generation and 20 per cent from the market (December 31, 2025 – 80 per cent wind generation, 10 per cent solar generation and 10 per cent market). The following table presents the net change in fair value of derivative assets and liabilities classified as Level III of the fair value hierarchy: three months ended September 30 nine months ended September 30 (unaudited - millions of Canadian $) 2026 2025 2026 2025 Balance at beginning of period (30) 80 74 72 Net gains (losses) included in Net income (loss)1 14 (52) (80) (36) Transfers to Level II (2) (3) (6) (5) Purchases — — (2) — Settlements (2) (3) (6) (8) Foreign exchange — 1 — — Balance at end of period (20) 23 (20) 23 1 For the three and nine months ended September 30, 2026, there were unrealized gains of $15 million and losses of $77 million, respectively, recognized in Revenues attributed to derivatives in the Level III category that were held at September 30, 2026 (2025 – unrealized losses of $52 million and $36 million, respectively). TC Energy Third Quarter 2026 | 79
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15. COMMITMENTS, CONTINGENCIES AND GUARANTEES Commitments Capital expenditure commitments include obligations related to the construction of growth projects and are based on the projects proceeding as planned. At September 30, 2026, TC Energy had approximately $1.9 billion of capital expenditure commitments (December 31, 2025 – approximately $0.8 billion) reflecting contractual commitments entered into for construction on Canadian and U.S. natural gas pipelines, primarily related to the construction costs associated with the NGTL System, ANR and other pipeline projects. Contingencies TC Energy and its subsidiaries are subject to various legal proceedings, arbitrations and actions arising in the normal course of business. While the final outcome of such legal proceedings and actions cannot be predicted with certainty, it is the opinion of management that the resolution of such normal course proceedings and actions will not have a material impact on the Company's consolidated financial position or results of operations. Guarantees TC Energy and its partner on the Sur de Texas pipeline, IEnova, have jointly guaranteed the financial performance of the entity which owns the pipeline. Such agreements include a guarantee and a letter of credit which are primarily related to the delivery of natural gas. TC Energy and its joint venture partner on Bruce Power, BPC Generation Infrastructure Trust, have each severally guaranteed certain contingent financial obligations of Bruce Power related to a lease agreement and contractor and supplier services. The Company and its partners in certain other jointly-owned entities have either (i) jointly and severally, (ii) jointly or (iii) severally guaranteed the financial performance of these entities. Such agreements include guarantees and letters of credit which are primarily related to construction services and the payment of liabilities. For certain of these entities, any payments made by TC Energy under these guarantees in excess of its ownership interest are to be reimbursed by its partners. The carrying value of these guarantees has been included in Other long-term liabilities on the Condensed consolidated balance sheet. Information regarding the Company’s guarantees is as follows: September 30, 2026 December 31, 2025 (unaudited - millions of Canadian $) Term Potential exposure1 Carrying value Potential exposure1 Carrying value Bruce Power Renewable to 2065 88 — 88 — Sur de Texas Renewable to 2053 81 — 78 — Other jointly-owned entities to 2041 62 1 54 1 231 1 220 1 1 TC Energy's share of the potential estimated current or contingent exposure. 80 | TC Energy Third Quarter 2026
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16. VARIABLE INTEREST ENTITIES Consolidated VIEs A significant portion of the Company’s assets are held through VIEs in which the Company holds a 100 per cent voting interest, the VIE meets the definition of a business and the VIE’s assets can be used for general corporate purposes. The consolidated VIEs whose assets cannot be used for purposes other than for the settlement of the VIE’s obligations, or are not considered a business, were as follows: (unaudited - millions of Canadian $) September 30, 2026 December 31, 2025 ASSETS Current Assets Cash and cash equivalents 237 167 Accounts receivable 848 989 Inventories 224 211 Other current assets 199 65 1,508 1,432 Plant, Property and Equipment 51,300 49,445 Equity Investments 1,037 979 Restricted Investments 1,294 1,150 Regulatory Assets 153 109 Goodwill 472 456 Other Long-Term Assets 131 93 55,895 53,664 LIABILITIES Current Liabilities Notes Payable 1,035 535 Accounts payable and other 1,627 1,703 Accrued interest 258 216 Current portion of long-term debt 790 575 3,710 3,029 Regulatory Liabilities 1,566 1,458 Other Long-Term Liabilities 59 51 Deferred Income Tax Liabilities 9 7 Long-Term Debt 14,670 13,904 20,014 18,449 TC Energy Third Quarter 2026 | 81
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Non-Consolidated VIEs The carrying value of non-consolidated VIEs and the maximum exposure to loss as a result of the Company's involvement with these VIEs are as follows: (unaudited - millions of Canadian $) September 30, 2026 December 31, 2025 Balance Sheet Exposure Equity investments Bruce Power 7,931 7,780 Coastal GasLink 437 896 Other pipeline equity investments 157 158 Off-Balance Sheet Exposure1 Bruce Power 1,831 1,955 Coastal GasLink2 450 200 Other pipeline equity investments 22 — Maximum Exposure to Loss 10,828 10,989 1 Includes maximum potential exposure to guarantees and future funding commitments. 2 During third quarter 2026, TC Energy committed up to $250 million to fund its proportionate share of the equity requirements for the Coastal GasLink Pipeline Phase 2 Expansion. 82 | TC Energy Third Quarter 2026