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EXHIBIT 13.1
Quarterly report to shareholders
Third quarter 2025
Management’s discussion and analysis
November 5, 2025
This management’s discussion and analysis (MD&A) contains information to help the reader make investment decisions about TC Energy Corporation (TC Energy). It discusses our business, operations, financial position, risks and other factors for the three and nine months ended September 30, 2025 and should be read with the accompanying unaudited Condensed consolidated financial statements for the three and nine months ended September 30, 2025, which have been prepared in accordance with U.S. GAAP.
This MD&A should also be read in conjunction with our December 31, 2024 audited Consolidated financial statements and notes and the MD&A in our 2024 Annual Report. Capitalized and abbreviated terms that are used but not otherwise defined herein are defined in our 2024 Annual Report. Certain comparative figures have been adjusted to reflect the current period's presentation.
On October 1, 2024, TC Energy completed the spinoff of its Liquids Pipelines business into a new public company, South Bow Corporation (the Spinoff Transaction). Upon completion of the Spinoff Transaction, the Liquids Pipelines business was accounted for as a discontinued operation. Discussions throughout this MD&A are based on continuing operations unless otherwise noted. Prior year results have been recast to reflect the split between continuing and discontinued operations. Refer to our 2024 Annual Report and the Discontinued operations section for additional information.
TC Energy Third Quarter 2025 | 1

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 interim methane emissions intensity target
•expected industry, market and economic conditions, and ongoing trade negotiations, including their impact on our customers and suppliers.
Forward-looking statements do not guarantee future performance. Actual events and results could be significantly different because of assumptions, risks or uncertainties related to our business or events that happen after the date of this MD&A.
Our forward-looking information is based on the following key assumptions and subject to the following risks and uncertainties:
Assumptions
•realization of expected impacts from acquisitions and divestitures, including the Spinoff Transaction
•regulatory decisions and outcomes
•planned and unplanned outages and the utilization of our pipelines, power and storage assets
•integrity and reliability of our assets
•anticipated construction costs, schedules and completion dates
•access to capital markets, including portfolio management
•expected industry, market and economic conditions, including the impact of these on our customers and suppliers
•inflation rates, commodity and labour prices
•interest, tax and foreign exchange rates
•nature and scope of hedging.




2 | TC Energy Third Quarter 2025

Risks and uncertainties
•realization of expected impacts from acquisitions and divestitures, including the Spinoff Transaction
•our ability to successfully implement our strategic priorities and whether they will yield the expected benefits
•our ability to implement a capital allocation strategy aligned with maximizing shareholder value
•operating performance of our pipelines, power generation and storage assets
•amount of capacity sold and rates achieved in our pipeline businesses
•amount of capacity payments and revenues from power generation assets due to plant availability
•production levels within supply basins
•construction and completion of capital projects
•cost, availability of, and inflationary pressures on, labour, equipment and materials
•availability and market prices of commodities
•access to capital markets on competitive terms
•interest, tax and foreign exchange rates
•performance and credit risk of our counterparties
•regulatory decisions and outcomes of legal proceedings, including arbitration and insurance claims
•our ability to effectively anticipate and assess changes to government policies and regulations, including those related to the environment
•our ability to realize the value of tangible assets and contractual recoveries
•competition in the businesses in which we operate
•unexpected or unusual weather
•acts of civil disobedience
•cybersecurity and technological developments
•sustainability-related risks including climate-related risks and the impact of energy transition on our business
•economic and political conditions, and ongoing trade negotiations in North America, as well as globally
•global health crises, such as pandemics and epidemics, and the impacts related thereto.
You can read more about these factors and others in this MD&A and in other reports we have filed with Canadian securities regulators and the SEC, including the MD&A in our 2024 Annual Report.
As actual results could vary significantly from the forward-looking information, you should not put undue reliance on     forward-looking information and should not use future-oriented information or financial outlooks for anything other than their intended purpose. We do not update our forward-looking statements due to new information or future events unless we are required to by law.
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 2025 | 3

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. Prior year results have been recast to reflect the split between continuing and discontinued operations.
three months ended
September 30		nine months ended
September 30
(millions of $, except per share amounts)2025
20241
2025
20241
Income    
Revenues3,704 3,358 11,071 10,194 
Net income (loss) attributable to common shares
609 1,457 2,420 3,623 
from continuing operations
813 1,338 2,653 3,130 
from discontinued operations
(204)119 (233)493 
Net income (loss) per common share – basic
$0.58 $1.40 $2.33 $3.49 
from continuing operations
$0.78 $1.29 $2.55 $3.02 
from discontinued operations
($0.20)$0.11 ($0.22)$0.47 
Comparable EBITDA2
2,654 2,791 7,988 8,575 
from continuing operations
2,654 2,412 7,988 7,430 
from discontinued operations
— 379 — 1,145 
Comparable earnings2
805 1,074 2,636 3,336 
from continuing operations
805 894 2,636 2,771 
from discontinued operations
— 180 — 565 
Comparable earnings per common share2
$0.77 $1.03 $2.53 $3.21 
from continuing operations
$0.77 $0.86 $2.53 $2.67 
from discontinued operations
— $0.17 — $0.54 
Dividends declared  
per common share
$0.85 
3
$0.96 $2.55 
3
$2.88 
Basic common shares outstanding (millions)
   
– weighted average for the period 1,040 1,038 1,040 1,038 
– issued and outstanding at end of period1,041 1,038 1,041 1,038 
1Prior year results have been recast to reflect the split between continuing and discontinued operations.
2Additional information on the most directly comparable GAAP measure can be found in the Non-GAAP measures section.
3Reflects dividends declared following the Spinoff Transaction.
4 | TC Energy Third Quarter 2025

three months ended
September 30		nine months ended
September 30
(millions of $)
2025202420252024
Cash flows1
    
Net cash provided by operations2,3
1,920 1,915 5,452 5,612 
Comparable funds generated from operations2,3
1,790 1,915 5,703 6,225 
Capital spending4
1,506 2,109 4,694 5,597 
Disposition of equity interest, net of transaction costs5
— (7)— 419 
1Includes continuing and discontinued operations.
2Additional information on the most directly comparable GAAP measure can be found in the Non-GAAP measures section.
3Includes Liquids Pipelines earnings for the three and nine months ended September 30, 2024 compared to Liquids Pipelines earnings of nil for the same periods in 2025. Refer to the Discontinued operations section and our 2024 Annual Report for additional information.
4Capital spending reflects cash flows associated with our Capital expenditures, Capital projects in development and Contributions to equity investments. Refer to Note 4, Segmented information, of our Condensed consolidated financial statements for additional information.
5Included in the Financing activities section of the Condensed consolidated statement of cash flows.
TC Energy Third Quarter 2025 | 5

Consolidated results
three months ended
September 30		nine months ended
September 30
(millions of $, except per share amounts)2025
20241
2025
20241
Canadian Natural Gas Pipelines533 495 1,600 1,510 
U.S. Natural Gas Pipelines801 1,330 2,817 3,135 
Mexico Natural Gas Pipelines407 237 809 715 
Power and Energy Solutions190 354 637 826 
Corporate(3)(33)(15)(120)
Total segmented earnings (losses)1,928 2,383 5,848 6,066 
Interest expense(847)(777)(2,534)(2,340)
Allowance for funds used during construction55 210 417 551 
Foreign exchange gains (losses), net30 (38)142 (78)
Interest income and other47 61 147 204 
Income (loss) from continuing operations before income taxes
1,213 1,839 4,020 4,403 
Income tax (expense) recovery from continuing operations
(245)(307)(875)(699)
Net income (loss) from continuing operations
968 1,532 3,145 3,704 
Net income (loss) from discontinued operations, net of tax
(204)119 (233)493 
Net income (loss)
764 1,651 2,912 4,197 
Net (income) loss attributable to non-controlling interests
(127)(168)(408)(498)
Net income (loss) attributable to controlling interests
637 1,483 2,504 3,699 
Preferred share dividends(28)(26)(84)(76)
Net income (loss) attributable to common shares
609 1,457 2,420 3,623 
Net income (loss) per common share – basic
$0.58 $1.40 $2.33 $3.49 
from continuing operations$0.78 $1.29 $2.55 $3.02 
from discontinued operations
($0.20)$0.11 ($0.22)$0.47 
1Prior year results have been recast to reflect the split between continuing and discontinued operations.
three months ended
September 30		nine months ended
September 30
(millions of $)
2025
20241
2025
20241
Amounts attributable to common shares
Net income (loss) from continuing operations
968 1,532 3,145 3,704 
Net (income) loss attributable to non-controlling interests
(127)(168)(408)(498)
Net income (loss) attributable to controlling interests from continuing operations841 1,364 2,737 3,206 
Preferred share dividends(28)(26)(84)(76)
Net income (loss) attributable to common shares from continuing operations813 1,338 2,653 3,130 
Net income (loss) from discontinued operations, net of tax
(204)119 (233)493 
Net income (loss) attributable to common shares
609 1,457 2,420 3,623 
1Prior year results have been recast to reflect the split between continuing and discontinued operations.
Net income (loss) attributable to common shares from continuing operations decreased by $525 million or $0.51 per common share and $477 million or $0.47 per common share for the three and nine months ended September 30, 2025 compared to the same periods in 2024. Refer to the Non-GAAP measures section for the specific items recognized in Net income (loss) attributable to common shares from continuing operations and excluded from comparable earnings from continuing operations.
6 | TC Energy Third Quarter 2025

NON-GAAP MEASURES
This MD&A references non-GAAP measures, which are described in the table below. These measures do not have any standardized meaning as prescribed by GAAP and therefore may not be comparable to similar measures presented by other entities. These measures are reviewed regularly by our President and Chief Executive Officer, management and the Board of Directors in assessing our performance and making decisions regarding the ongoing operations of our business and its ability to generate cash flows. Some or all of these measures may also be used by investors and other external users of our financial statements as a supplemental measure to provide decision-useful information regarding our period-over-period performance and ability to generate earnings that are core to our ongoing operations. Discussions throughout this MD&A on the factors impacting comparable earnings before interest, taxes, depreciation and amortization (comparable EBITDA) and comparable earnings before interest and taxes (comparable EBIT) are consistent with the factors that impact segmented earnings, except where noted otherwise.
Comparable measures
We calculate comparable measures by adjusting certain GAAP measures for specific items we believe are significant but not reflective of our underlying operations in the period. Except as otherwise described herein, these comparable measures are calculated on a consistent basis from period to period and are adjusted for specific items in each period, as applicable.
Our decision to adjust for a specific item in reporting comparable measures is subjective and made after careful consideration. We maintain a consistent approach to adjustments, which generally fall into the categories described below:
•by their nature are unusual, infrequent and separately identifiable from our normal business operations and in our view are not reflective of our underlying operations in the period and generally include the following:
◦gains or losses on sales of assets or assets held for sale; impairment of goodwill, plant, property and equipment, equity investments and other assets; legal, contractual and other infrequent settlements; acquisition, integration and restructuring costs; expected credit loss provisions on net investment in leases and certain contract assets in Mexico; impacts resulting from changes in legislation and enacted tax rates and unusual tax refunds/payments and valuation allowance adjustments
•unrealized gains and losses related to fair value adjustments and unrealized foreign exchange on intercompany loans that do not reflect realized earnings or losses or cash impacts incurred in the current period from our underlying operations and generally include the following:
◦unrealized gains and losses from changes in the fair value of derivatives related to financial and commodity price risk management activities; unrealized fair value adjustments related to our proportionate share of Bruce Power’s risk management activities and its funds invested for post-retirement benefits; unrealized foreign exchange gains and losses on intercompany loans that impact consolidated earnings.
The following table identifies our non-GAAP measures against their most directly comparable GAAP measures. These measures are applicable to each of our continuing operations and discontinued operations. Quantitative reconciliations of our comparable measures to their GAAP measures and a discussion of specific adjustments made for the three and nine months ended September 30, 2025 and comparative periods are found throughout this MD&A.
Non-GAAP measureGAAP measure
comparable EBITDAsegmented earnings (losses)
comparable EBITsegmented earnings (losses)
comparable earningsnet income (loss) attributable to common shares
comparable earnings per common sharenet income (loss) per common share
funds generated from operationsnet cash provided by operations
comparable funds generated from operationsnet cash provided by operations
TC Energy Third Quarter 2025 | 7

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 our 2024 Consolidated financial statements. Comparable funds generated from operations is adjusted for the cash impact of specific items described in the Comparable measures section. We believe funds generated from operations and comparable funds generated from operations are useful measures of our consolidated operating cash flows because they exclude fluctuations from working capital balances, which do not necessarily reflect underlying operations in the same period, and are used to provide a consistent measure of the cash-generating ability of our businesses. Refer to the Financial condition section for a reconciliation to Net cash provided by operations.
Comparable earnings 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 in our Condensed consolidated statement of income, adjusted for specific items. We use comparable earnings as a measure of our earnings from ongoing operations as it is a useful indicator of our performance and is also presented on a consolidated basis. Refer to the following page as well as the Discontinued operations section for reconciliations to Net income (loss) attributable to common shares and Net income (loss) per common share for our continuing operations and discontinued operations.
Comparable earnings and comparable earnings per common share - from continuing operations
The following specific items were recognized in Net income (loss) attributable to common shares from continuing operations and were excluded from comparable earnings from continuing operations:
2025 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 TransCanada PipeLines Limited (TCPL) and Transportadora de Gas Natural de la Huasteca (TGNH), net of     non-controlling interest
•a pre-tax recovery of $12 million and a pre-tax expense of $79 million for the three and nine months ended September 30, 2025, respectively, on the expected credit loss provision related to TGNH net investment in leases and certain contract assets in Mexico, net of non-controlling interest.
2024 results
•a pre-tax gain of $572 million in third quarter 2024 related to the sale of Portland Natural Gas Transmission System (PNGTS), which was completed in third quarter 2024
•a pre-tax gain of $48 million in second quarter 2024 related to the sale of non-core assets in U.S. Natural Gas Pipelines and Canadian Natural Gas Pipelines
•a pre-tax expense of $5 million and a pre-tax recovery of $19 million for the three and nine months ended September 30, 2024, respectively, on the expected credit loss provision related to TGNH net investment in leases and certain contract assets in Mexico, net of non-controlling interest
•pre-tax costs of $10 million related to the ownership transfer of the NGTL System from Nova Gas Transmission Ltd to NGTL GP Ltd. on behalf of NGTL Limited Partnership (NGTL System Ownership Transfer) in second quarter 2024
8 | TC Energy Third Quarter 2025

•a pre-tax expense of $34 million related to a non-recurring third-party settlement in first quarter 2024
•a pre-tax expense of $5 million and $15 million for the three and nine months ended September 30, 2024, respectively, related to Focus Project costs
•pre-tax unrealized foreign exchange losses, net, of $52 million and nil for the three and nine months ended September 30, 2024, respectively, on the peso-denominated intercompany loan between TCPL and TGNH, net of         non-controlling interest.
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)2025
20241
2025
20241
Net income (loss) attributable to common shares from continuing operations
813 1,338 2,653 3,130 
Specific items (pre tax):
Expected credit loss provision on net investment in leases and certain contract assets in Mexico2
(12)5 79 (19)
Foreign exchange (gains) losses, net – intercompany loan3
(87)52 42 — 
(Gain) loss on sale of PNGTS— (572)— (572)
(Gain) loss on sale of non-core assets— — — (48)
Third-party settlement— — — 34 
Focus Project costs4
— 5 — 15 
NGTL System ownership transfer costs— — — 10 
Bruce Power unrealized fair value adjustments(8)(7)(26)(6)
Risk management activities5
114 (54)(141)132 
Tax related to specific items6
(15)127 29 95 
Comparable earnings from continuing operations
805 894 2,636 2,771 
Net income (loss) per common share from continuing operations
$0.78 $1.29 $2.55 $3.02 
Specific items (net of tax)
(0.01)(0.43)(0.02)(0.35)
Comparable earnings per common share from continuing operations
$0.77$0.86$2.53$2.67
1Prior year results have been recast to reflect continuing operations only.
2In 2022, TGNH and the CFE executed agreements which consolidate several natural gas pipelines under one TSA. As this TSA contains a lease, we have recognized amounts in net investment in leases on our Condensed consolidated balance sheet and have recognized an expected credit loss provision in relation to the net investment in leases and certain contract assets in Mexico, which will fluctuate from period to period based on changing economic assumptions and forward-looking information. This provision does not reflect losses or cash outflows that were incurred under this lease arrangement in the current period or from our underlying operations, and therefore, we have excluded any unrealized changes, net of non-controlling interest, from comparable measures. Refer to Note 12, Risk management and financial instruments, of our Condensed consolidated financial statements for additional information.
3In 2023, TCPL and TGNH became party to an unsecured revolving credit facility. The loan receivable and loan payable are eliminated upon consolidation; however, due to differences in the currency that each entity reports its financial results, there is an impact to net income reflecting the revaluation and translation of the loan receivable and loan payable to TC Energy's reporting currency. As the amounts do not accurately reflect what will be realized at settlement, we exclude from comparable measures the unrealized foreign exchange gains and losses on the loan receivable, as well as the corresponding unrealized foreign exchange gains and losses on the loan payable, net of non-controlling interest.
4    In 2022, we launched the Focus Project with benefits in the form of enhanced safety, productivity and cost-effectiveness expected to be realized over the long term. In 2023 and 2024, we recognized expenses in Plant operating costs and other, for external consulting and severance, some of which are not recoverable through regulatory and commercial tolling structures.
TC Energy Third Quarter 2025 | 9

5
Risk management activities
three months ended
September 30		nine months ended
September 30
(millions of $)2025202420252024
 U.S. Natural Gas Pipelines8 (13)66 (76)
Canadian Power(50)7 (72)67 
U.S. Power2 3 4 (8)
 Natural Gas Storage(7)33 (27)(37)
Foreign exchange
(68)24 169 (78)
 
Interest rate
1 — 1 — 
(114)54 141 (132)
 Income tax attributable to risk management activities27 (13)(35)33 
 
Total unrealized gains (losses) from risk management activities
(87)41 106 (99)
6
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) adjusted for the specific items described on the previous page and excludes charges for depreciation and amortization. Refer to each business segment for further information on our reconciliation of comparable EBITDA.
three months ended
September 30		nine months ended
September 30
(millions of $, except per share amounts)2025
20241
2025
20241
Canadian Natural Gas Pipelines913 845 2,726 2,537 
U.S. Natural Gas Pipelines1,062 1,002 3,518 3,311 
Mexico Natural Gas Pipelines416 265 968 765 
Power and Energy Solutions266 326 791 873 
Corporate(3)(26)(15)(56)
Comparable EBITDA from continuing operations
2,654 2,412 7,988 7,430 
Depreciation and amortization(701)(628)(2,050)(1,896)
Interest expense included in comparable earnings
(848)(777)(2,535)(2,340)
Allowance for funds used during construction55 210 417 551 
Foreign exchange gains (losses), net included in comparable earnings22 (33)67 (41)
Interest income and other
47 61147 204 
Income tax (expense) recovery included in comparable earnings(260)(180)(846)(604)
Net (income) loss attributable to non-controlling interests included in comparable earnings(136)(145)(468)(457)
Preferred share dividends(28)(26)(84)(76)
Comparable earnings from continuing operations
805 894 2,636 2,771 
Comparable earnings per common share from continuing operations$0.77 $0.86 $2.53 $2.67 
1Prior year results have been recast to reflect continuing operations only.
10 | TC Energy Third Quarter 2025

Comparable EBITDA from continuing operations – 2025 versus 2024
Comparable EBITDA increased by $242 million for the three months ended September 30, 2025 compared to the same period in 2024 primarily due to the net effect of the following:
•increased U.S. dollar-denominated EBITDA from Mexico Natural Gas Pipelines due to higher earnings in TGNH primarily related to the completion of the Southeast Gateway pipeline, partially offset by lower equity earnings from Sur de Texas as a result of peso-denominated financial exposure and higher income tax expense mainly related to foreign exchange impacts of U.S. dollar-denominated liabilities
•increased EBITDA in Canadian Natural Gas Pipelines mainly due to higher flow-through depreciation and income taxes on the NGTL System and increased contributions from Coastal GasLink
•increased U.S. dollar-denominated EBITDA from U.S. Natural Gas Pipelines mainly due to an increase in earnings from Columbia Gas as a result of higher transportation rates effective April 1, 2025, subject to refund upon completion of the current rate proceeding, incremental earnings from projects placed in service and additional contract sales, partially offset by higher operating costs and decreased earnings as a result of the sale of PNGTS completed in third quarter 2024. Refer to the Recent developments - U.S. Natural Gas Pipelines section for additional information
•increased EBITDA in Corporate primarily due to costs in 2024 related to TC Energy's corporate services and governance functions that were not allocated to discontinued operations
•decreased Power and Energy Solutions EBITDA mainly attributable to lower net contributions from Bruce Power due to reduced generation primarily resulting from the Unit 4 Major Component Replacement (MCR), partially offset by a higher contract price; and lower realized power prices in Canadian Power, partially offset by lower business development costs
•a positive foreign exchange impact of a stronger U.S. dollar on the Canadian dollar equivalent comparable EBITDA in our U.S. dollar-denominated operations, which was translated at a rate of 1.38 in 2025 versus 1.36 in 2024. Refer to the Foreign exchange section for additional information.
Comparable EBITDA increased by $558 million for the nine months ended September 30, 2025 compared to the same period in 2024 primarily due to the net effect of the following:
•increased EBITDA in Canadian Natural Gas Pipelines mainly due to higher flow-through depreciation and income taxes on the NGTL System and increased contributions from Coastal GasLink
•increased U.S. dollar-denominated EBITDA from Mexico Natural Gas Pipelines mainly due to higher earnings in TGNH primarily related to the completion of the Southeast Gateway pipeline, partially offset by lower equity earnings from Sur de Texas as a result of peso-denominated financial exposure and higher income tax expense mainly related to foreign exchange impacts of U.S. dollar-denominated liabilities
•increased U.S. dollar-denominated EBITDA from U.S. Natural Gas Pipelines mainly due to a net increase in earnings from Columbia Gas as a result of higher transportation rates effective April 1, 2025, subject to refund upon completion of the current rate proceeding, incremental earnings from projects placed in service and additional contract sales, partially offset by decreased earnings as a result of the sale of PNGTS completed in third quarter 2024, higher operational costs and lower earnings from our equity investments. Refer to the Recent developments - U.S. Natural Gas Pipelines section for additional information
•increased EBITDA in Corporate primarily due to costs in 2024 related to TC Energy's corporate services and governance functions that were not allocated to discontinued operations
•decreased Power and Energy Solutions EBITDA mainly attributable to lower realized power prices in Canadian Power, decreased net contributions from Bruce Power primarily due to the Unit 4 MCR, higher operating costs, partially offset by a higher contract price; and lower realized Alberta natural gas storage spreads, partially offset by lower business development costs
•a positive foreign exchange impact of a stronger U.S. dollar on the Canadian dollar equivalent comparable EBITDA in our U.S. dollar-denominated operations, which was translated at a rate of 1.40 in 2025 versus 1.36 in 2024. Refer to the Foreign exchange section for additional information.
TC Energy Third Quarter 2025 | 11

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 – 2025 versus 2024
Comparable earnings decreased by $89 million or $0.09 per common share for the three months ended September 30, 2025 compared to the same period in 2024 primarily due to the net effect of the following:
•changes in comparable EBITDA described above
•lower AFUDC primarily due to the completion of the Southeast Gateway pipeline
•higher income tax expense primarily due to the impact of Mexico foreign exchange exposure, a change in the geographic and business mix of earnings and higher flow-through income taxes
•higher depreciation and amortization primarily due to higher depreciation rates on the NGTL System under the 2025-2029 Revenue Requirement Settlement and on Columbia Gas related to the settlement-in-principle filed with FERC in third quarter 2025. Refer to the Recent developments - U.S. Natural Gas Pipelines section for additional information
•lower capitalized interest due to the declared commercial in-service of the Coastal GasLink pipeline in fourth quarter 2024
•risk management activities used to manage our foreign exchange exposure to net liabilities in Mexico and to U.S. dollar-denominated income and the revaluation of our peso-denominated net monetary liabilities to U.S. dollars
•lower net income attributable to non-controlling interests is primarily the result of lower net income in TGNH due to the net effect of higher EBITDA and lower AFUDC resulting from the completion of the Southeast Gateway pipeline in second quarter 2025 and the overall impact of foreign exchange. In addition, the divestiture of PNGTS in third quarter 2024, partially offset by higher net income recognized from the Columbia Gas and Columbia Gulf assets also contributed to lower net income attributable to non-controlling interests.
Comparable earnings decreased by $135 million or $0.14 per common share for the nine months ended September 30, 2025 compared to the same period in 2024 primarily due to the net effect of the following:
•changes in comparable EBITDA described above
•higher income tax expense primarily due to the impact of Mexico foreign exchange exposure, higher flow-through income taxes and a change in the geographic and business mix of earnings
•lower capitalized interest due to the declared commercial in-service of the Coastal GasLink pipeline in fourth quarter 2024
•higher depreciation and amortization primarily due to higher depreciation rates on the NGTL System under the 2025-2029 Revenue Requirement Settlement and on Columbia Gas related to the settlement-in-principle that was filed with FERC in third quarter 2025. Refer to the Recent developments - U.S. Natural Gas Pipelines section for additional information
•lower AFUDC primarily due to the completion of the Southeast Gateway pipeline in second quarter 2025 and the suspension of AFUDC on the south section of the Villa de Reyes pipeline in first quarter 2025, partially offset by higher capital expenditures on U.S. natural gas pipeline projects
•lower interest income and other due to lower interest earned on short-term investments
•higher net income attributable to non-controlling interests due to the net effect of the completion of the Southeast Gateway pipeline in second quarter 2025, the sale of the 13.01 per cent non-controlling equity interest in TGNH to the CFE in second quarter 2024, net income recognized from Columbia Gas and Columbia Gulf assets, and the divestiture of PNGTS in third quarter 2024
•risk management activities used to manage our foreign exchange exposure to net liabilities in Mexico and to U.S. dollar-denominated income, the revaluation of our peso-denominated net monetary liabilities to U.S. dollars.


12 | TC Energy Third Quarter 2025

Supplementary financial measure
Net capital expenditures
Net capital expenditures represents capital costs incurred for growth projects, maintenance capital expenditures, contributions to equity investments and projects under development, adjusted for the portion attributed to non-controlling interests in the entities we control. Net capital expenditures reflect capital costs incurred during the period, excluding the impact of timing of cash payments. We use net capital expenditures as a key measure in evaluating our performance in managing our capital spending activities in comparison to our capital plan.
Net capital expenditures does not include an adjustment related to the CFE’s minority interest in TGNH capital expenditures for projects included as part of the 2022 strategic alliance between TGNH and the CFE, including Villa de Reyes, Southeast Gateway and Tula. The CFE’s contribution in second quarter 2024 to obtain a 13.01 per cent equity interest in TGNH included consideration of its proportionate share of required capital contributions for approved projects. Net capital expenditures will be adjusted for any new capital projects approved in TGNH going forward.
Outlook
Comparable EBITDA and comparable earnings
Our overall comparable EBITDA and comparable earnings per common share outlooks for 2025 remain consistent with our 2024 Annual Report.
Consolidated capital expenditures
Our expected total capital expenditures for 2025 as outlined in our 2024 Annual Report remain materially unchanged.
TC Energy Third Quarter 2025 | 13

Capital program
We are developing quality projects under our capital program. These long-life infrastructure assets are supported by     long-term commercial arrangements with creditworthy counterparties and/or regulated business models and are expected to generate growth in earnings and cash flows.
Our capital program consists of approximately $21 billion of secured projects that represent commercially supported, committed projects that are either under construction or are in, or preparing to, commence the permitting stage.
Three years of maintenance capital expenditures for our businesses are included in the Secured projects table. Maintenance capital expenditures on our regulated Canadian and U.S. natural gas pipelines are added to rate base on which we have the opportunity to earn a return and recover these expenditures through current or future tolls, which is similar to our capacity capital projects on these pipelines.
We placed approximately $7.6 billion of natural gas pipeline capacity projects along our extensive North American asset footprint into service, including Southeast Gateway pipeline. Approximately $1.5 billion of maintenance capital expenditures were incurred in the period.
All projects are subject to cost and timing adjustments due to factors including weather, market conditions, route refinement, land acquisition, permitting conditions, scheduling and timing of regulatory permits, as well as other potential restrictions and uncertainties, including inflationary pressures on labour and materials. Amounts exclude capitalized interest and AFUDC, where applicable.
In addition to our secured projects, we are pursuing a portfolio of quality projects in various stages of development across each of our business units as discussed in our 2024 Annual Report. Projects under development have greater uncertainty with respect to timing and estimated project costs and are subject to corporate and regulatory approvals, unless otherwise noted. While each business segment also has additional areas of focus for further ongoing business development activities and growth opportunities, new opportunities will be assessed within our capital allocation framework in order to fit within our annual capital expenditure parameters. As these projects advance and reach necessary milestones they will be included in the Secured projects table on the following page. Refer to the Recent developments section for updates to our secured projects and projects under development.

14 | TC Energy Third Quarter 2025

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, 2025
(billions of $)
Canadian Natural Gas Pipelines1
NGTL System
2026
0.6 
2
0.3 
2027+
0.5 
2
— 
Regulated maintenance capital expenditures
2025-2027
2.5 0.6 
U.S. Natural Gas Pipelines
Gillis Access – Extension
2026-2027
US 0.4 US 0.1 
Heartland project
2027
US 0.9 US 0.1 
Northwoods project
2029
US 0.9 — 
Pulaski and Maysville projects
2029
US 0.8 — 
Southeast Virginia Energy Storage project
2030
US 0.3 — 
TCO Connector & Midwest Connector projects
2030-2031
US 0.4 — 
Other capital3
2025-2028
US 1.8 US 0.5 
Regulated maintenance capital expenditures
2025-2027
US 2.6 US 0.6 
Mexico Natural Gas Pipelines
Villa de Reyes – South section4
—US 0.4 US 0.3 
Tula5
—US 0.4 US 0.3 
Power and Energy Solutions
Bruce Power – Unit 3 MCR20261.1 1.0 
Bruce Power – Unit 4 MCR6
20280.9 0.3 
Bruce Power – Unit 5 MCR6
20301.1 0.2 
Bruce Power – life extension7
2025-2031
1.8 0.8 
Other
Non-recoverable maintenance capital expenditures8
2025-2027
0.5 — 
17.9 5.1 
Foreign exchange impact on secured projects9
3.5 0.7 
Total secured projects (Cdn$)
21.4 5.8 
1Our share of committed equity to fund the estimated cost of the Coastal GasLink - Cedar Link project is $37 million.
2Includes amounts related to projects within the Multi-Year Growth Plan (MYGP) that have received FID.
3Includes capital expenditures related to certain large-scope maintenance projects across our U.S. natural gas footprint due to their discrete nature for regulatory recovery.
4We are working with the CFE on completing the remaining section of the Villa de Reyes pipeline. The in-service date will be determined upon resolution of outstanding stakeholder issues.
5Estimated project cost as per contracts signed in 2022 as part of the TGNH strategic alliance between TC Energy and the CFE. We continue to evaluate the development and completion of the Tula pipeline, with the CFE, subject to a future FID and an updated cost estimate.
6Amounts are net of expected Investment Tax Credits announced by the Government of Canada in February 2024.
7Reflects amounts to be invested under the Asset Management program to 2027, other life extension projects and the incremental uprate initiative.
8Includes non-recoverable maintenance capital expenditures from all segments and is primarily related to our Power and Energy Solutions and Corporate assets.
9Reflects U.S./Canada foreign exchange rate of 1.39 at September 30, 2025.
TC Energy Third Quarter 2025 | 15

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 $)2025202420252024
NGTL System649 598 1,925 1,797 
Canadian Mainline193 193 572 576 
Other Canadian pipelines1
71 54 229 164 
Comparable EBITDA913 845 2,726 2,537 
Depreciation and amortization(380)(350)(1,126)(1,037)
Comparable EBIT
533 495 1,600 1,500 
Specific item:
Gain (loss) on sale of non-core assets— — — 10 
Segmented earnings (losses)533 495 1,600 1,510 
1Includes results from Foothills, Ventures LP, Great Lakes Canada and our proportionate share of income related to investments in Trans Québec & Maritimes (TQM) and Coastal GasLink, as well as general and administrative and business development costs related to our Canadian natural gas pipelines.
Canadian Natural Gas Pipelines segmented earnings increased by $38 million and $90 million for the three and nine months ended September 30, 2025 compared to the same periods in 2024 and included a pre-tax gain on sale of a non-core asset of $10 million in second quarter 2024, which has been excluded from our calculation of comparable EBITDA and comparable EBIT.
Net income for our rate-regulated Canadian natural gas pipelines is primarily affected by our approved ROE, investment base, the level of deemed common equity and incentive earnings. Comparable EBITDA is impacted by these factors, as well as changes in depreciation, financial charges and income taxes. These additional items do not have a significant impact on net income as they are almost entirely recovered in revenues on a flow-through basis.
NET INCOME AND AVERAGE INVESTMENT BASE
three months ended
September 30		nine months ended
September 30
(millions of $)2025202420252024
Net income
NGTL System200 193 597 585 
Canadian Mainline62 61 185 176 
Average investment base
NGTL System19,319 19,342 
Canadian Mainline3,713 3,664 
16 | TC Energy Third Quarter 2025

Net income for the NGTL System increased by $7 million and $12 million for the three and nine months ended September 30, 2025 compared to the same periods in 2024 primarily due to higher incentive earnings. The NGTL System is currently operating under the CER approved five-year negotiated revenue requirement settlement (2025-2029 NGTL Settlement), which commenced on January 1, 2025 and includes an approved ROE of 10.1 per cent on 40 per cent deemed common equity. This settlement provides the NGTL System with higher depreciation rates and the opportunity to further increase depreciation rates with an incentive if tolls fall below specified levels, or if growth projects are undertaken. It also includes incentive mechanisms to reduce both physical emissions and emission compliance costs, while also providing incentive for certain operating costs where variances from projected amounts and emissions savings are shared with customers.
Net income for the Canadian Mainline increased by $1 million and $9 million for the three and nine months ended September 30, 2025 compared to the same periods in 2024 mainly due to higher incentive earnings. The Canadian Mainline is operating under the 2021-2026 Mainline Settlement which includes an approved ROE of 10.1 per cent on 40 per cent deemed common equity and an incentive to decrease costs and increase revenues on the pipeline under a beneficial sharing mechanism with our customers.
COMPARABLE EBITDA
Comparable EBITDA for Canadian Natural Gas Pipelines increased by $68 million and $189 million for the three and nine months ended September 30, 2025 compared to the same periods in 2024 due to:
•higher flow-through depreciation and income taxes as well as higher incentive earnings, partially offset by lower flow-through financial charges on the NGTL System
•higher contributions from Coastal GasLink mainly resulting from the declared commercial in-service of the pipeline in fourth quarter 2024.
DEPRECIATION AND AMORTIZATION
Depreciation and amortization increased by $30 million and $89 million for the three and nine months ended September 30, 2025 compared to the same periods in 2024 primarily reflecting higher depreciation rates on the NGTL System under the 2025-2029 Revenue Requirement Settlement.
TC Energy Third Quarter 2025 | 17

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$, unless otherwise noted)2025202420252024
Columbia Gas1
416 372 1,300 1,176 
ANR133 138 466 464 
Columbia Gulf1
60 57 176 178 
Great Lakes33 38 142 148 
GTN65 44 187 138 
PNGTS1,2
— 14 — 66 
Other U.S. pipelines3
63 71 239 265 
Comparable EBITDA 770 734 2,510 2,435 
Depreciation and amortization(196)(169)(549)(522)
Comparable EBIT574 565 1,961 1,913 
Foreign exchange impact219 206 790 688 
Comparable EBIT (Cdn$)
793 771 2,751 2,601 
Specific items:
Gain (loss) on sale of PNGTS— 572 — 572 
Gain (loss) on sale of non-core assets— — — 38 
Risk management activities8 (13)66 (76)
Segmented earnings (losses) (Cdn$)
801 1,330 2,817 3,135 
1Includes non-controlling interest. Refer to the Corporate section for additional information.
2The sale of PNGTS was completed in August 2024.
3Reflects comparable EBITDA from our ownership in our mineral rights business (CEVCO), North Baja, Gillis Access, Tuscarora, Bison, Crossroads and our share of equity income from Northern Border, Iroquois, Millennium and Hardy Storage, our U.S. natural gas marketing business, as well as general and administrative and business development costs related to our U.S. natural gas pipelines.
U.S. Natural Gas Pipelines segmented earnings decreased by $529 million and $318 million for the three and nine months ended September 30, 2025 compared to the same periods in 2024 and included the following specific items which have been excluded from our calculation of comparable EBITDA and comparable EBIT:
•a pre-tax gain of $572 million related to the sale of PNGTS in third quarter 2024
•a pre-tax gain on sale of a non-core asset of $38 million in second quarter 2024
•unrealized gains and losses from changes in the fair value of derivatives related to our U.S. natural gas marketing business.
A stronger U.S. dollar for the three and nine months ended September 30, 2025 had a positive impact on the Canadian dollar equivalent segmented earnings from our U.S. dollar-denominated operations compared to the same period in 2024. Refer to the Foreign exchange section for additional information.
Earnings from our U.S. Natural Gas Pipelines operations are generally affected by contracted volume levels, volumes delivered and the rates charged, as well as by the cost of providing services. Columbia Gas and ANR results are also affected by the contracting and pricing of their natural gas storage capacity and incidental commodity sales. Natural gas pipeline and storage volumes and revenues are generally higher in the winter months because of the seasonal nature of the business.


18 | TC Energy Third Quarter 2025

Comparable EBITDA for U.S. Natural Gas Pipelines increased by US$36 million and US$75 million for the three and nine months ended September 30, 2025 compared to the same periods in 2024 and was primarily due to the net effect of:
•a net increase in earnings from Columbia Gas as a result of higher transportation rates effective April 1, 2025, subject to refund upon completion of the current rate proceeding. Refer to the Recent developments - U.S. Natural Gas Pipelines section for additional information
•incremental earnings from growth and modernization projects placed in service, as well as increased earnings from additional contract sales on ANR and GTN
•decreased earnings as a result of the sale of PNGTS, which was completed in third quarter 2024
•decreased equity earnings from Iroquois and Millennium
•decreased earnings due to higher operational costs, reflective of increased system utilization across our footprint and higher property taxes from projects placed in service.
DEPRECIATION AND AMORTIZATION
Depreciation and amortization increased by US$27 million for the three and nine months ended September 30, 2025 compared to the same periods in 2024 primarily due to depreciation rate changes reflected in the Columbia Gas settlement-in-principle that was filed with FERC in third quarter 2025. See Recent Developments - U.S. Natural Gas Pipelines for more details.
TC Energy Third Quarter 2025 | 19

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$, unless otherwise noted)2025202420252024
TGNH1,2
209 62 432 186 
Sur de Texas3
24 62 51 164 
Topolobampo39 40 117 118 
Guadalajara14 14 45 44 
Mazatlán17 17 51 51 
Comparable EBITDA303 195 696 563 
Depreciation and amortization(18)(17)(52)(51)
Comparable EBIT285 178 644 512 
Foreign exchange impact108 64 252 184 
Comparable EBIT (Cdn$)
393 242 896 696 
Specific item:
Expected credit loss provision on net investment in leases and certain contract assets in Mexico2
14 (5)(87)19 
Segmented earnings (losses) (Cdn$)
407 237 809 715 
1Includes the in-service sections of the Tamazunchale, Villa de Reyes, Tula and Southeast Gateway pipelines.
2Includes non-controlling interest. Refer to the Corporate section for additional information.
3Represents equity income from our 60 per cent interest and fees earned from the construction and operation of the pipeline.
Mexico Natural Gas Pipelines segmented earnings increased by $170 million and $94 million for the three and nine months ended September 30, 2025 compared to the same periods in 2024 and included a recovery of $14 million and expense of     $87 million, respectively (2024 – expense of $5 million and recovery of $19 million, respectively), on the expected credit loss provision related to the TGNH net investment in leases and certain contract assets in Mexico, which has been excluded from our calculation of comparable EBITDA and comparable EBIT. During second quarter 2025, we completed the Southeast Gateway pipeline and recognized a net investment in sales-type lease. Refer to Note 12, Risk management and financial instruments and Note 13, TGNH strategic alliance, of our Condensed consolidated financial statements for additional information.
A stronger U.S. dollar for the three and nine months ended September 30, 2025 had a positive impact on the Canadian dollar equivalent segmented earnings from our U.S. dollar-denominated operations in Mexico compared to the same periods in 2024. Refer to the Foreign exchange section for additional information.
Comparable EBITDA for Mexico Natural Gas Pipelines increased by US$108 million and US$133 million for the three and nine months ended September 30, 2025 compared with the same periods in 2024, due to the net effect of:
•higher earnings in TGNH due to the completion of the Southeast Gateway pipeline
•lower equity earnings from Sur de Texas primarily due to the foreign exchange impacts on the revaluation of
peso-denominated liabilities as a result of a stronger Mexican peso and higher income tax expense mainly related to foreign exchange impacts of U.S. dollar-denominated liabilities. We use foreign exchange derivatives to manage the     peso-denominated exposure, the impact of which is recognized in Foreign exchange (gains) losses, net in the Condensed consolidated statement of income. Refer to the Foreign exchange section for additional information.
20 | TC Energy Third Quarter 2025

DEPRECIATION AND AMORTIZATION
Depreciation and amortization was generally consistent for the three and nine months ended September 30, 2025 compared to the same periods in 2024. Under sales-type lease accounting, the completed Southeast Gateway pipeline assets are derecognized from Plant, property and equipment and recorded as a net investment in lease on our Condensed consolidated balance sheet with no depreciation expense being recognized.
TC Energy Third Quarter 2025 | 21

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 $)2025202420252024
Bruce Power1
213 282 578 613 
Canadian Power30 51 145 219 
Natural Gas Storage and other2
23 (7)68 41 
Comparable EBITDA266 326 791 873 
Depreciation and amortization(29)(22)(85)(75)
Comparable EBIT237 304 706 798 
Specific items:
Bruce Power unrealized fair value adjustments8 7 26 6 
Risk management activities (55)43 (95)22 
Segmented earnings (losses)190 354 637 826 
1Represents our share of equity income from Bruce Power.
2Includes non-controlling interest in the Fluvanna and Blue Cloud Wind Farms (Texas Wind Farms), which is comprised of Class A Membership Interests. Refer to the Corporate section for additional information.
Power and Energy Solutions segmented earnings decreased by $164 million and $189 million for the three and nine months ended September 30, 2025 compared to the same periods in 2024 and included the following specific items which have been excluded from our calculation of comparable EBITDA and comparable EBIT:
•our proportionate share of Bruce Power's unrealized gains and losses on funds invested for post-retirement benefits and risk management activities
•unrealized gains and losses from changes in the fair value of derivatives used to reduce commodity exposures.
Comparable EBITDA for Power and Energy Solutions decreased by $60 million and $82 million for the three and nine months ended September 30, 2025 compared to the same period in 2024 primarily due to the net effect of:
•decreased contributions from Bruce Power due to reduced generation primarily related to the Unit 4 MCR and higher operating costs, partially offset by a higher contract price. Refer to the Bruce Power section for additional information
•lower Canadian Power financial results primarily from lower realized power prices
•higher Natural Gas Storage and other results for the three months ended September 30, 2025 is primarily due to lower business development costs and improved realized natural gas storage spreads. Increased financial results for the nine months ended September 30, 2025 were the result of lower business development costs, partially offset by decreased contributions from our U.S. marketing business and lower realized Alberta natural gas storage spreads in first quarter 2025.
DEPRECIATION AND AMORTIZATION
Depreciation and amortization increased by $7 million and $10 million for the three and nine months ended September 30, 2025 compared to the same periods in 2024 primarily due to the in-service of maintenance projects.
22 | TC Energy Third Quarter 2025

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)2025202420252024
Items included in comparable EBITDA and comparable EBIT are comprised of:
Revenues1
546 608 1,610 1,620 
Operating expenses(236)(233)(748)(730)
Depreciation and other(97)(93)(284)(277)
Comparable EBITDA and comparable EBIT2
213 282 578 613 
Bruce Power – other information  
Plant availability3,4
94%98%93%89%
Planned outage days4
11 — 76 160 
Unplanned outage days21 8 44 29 
Sales volumes (GWh)5
4,885 5,926 14,626 16,152 
Realized power price per MWh6
$111 $102 $109 $100 
1Net of amounts recorded to reflect operating cost efficiencies shared with the IESO, if applicable.
2Represents our 48.3 per cent ownership interest and internal costs supporting our investment in Bruce Power. Excludes unrealized gains and losses on funds invested for post-retirement benefits and risk management activities.
3The percentage of time the plant was available to generate power, regardless of whether it was running.
4Excludes MCR outage days.
5Sales volumes include deemed generation, if applicable.
6Calculation based on actual and deemed generation. Realized power price per MWh includes realized gains and losses from contracting activities and cost flow-through items. Excludes unrealized gains and losses on contracting activities and non-electricity revenues.
A planned outage on Unit 5 was completed in first quarter 2025. Planned maintenance on Unit 2 commenced in September 2025 with a return to service expected in late fourth quarter 2025.
On January 31, 2025 Unit 4 was removed from service to commence its MCR program, with a return to service expected
in 2028.
TC Energy Third Quarter 2025 | 23

Corporate
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 $)2025
20241
2025
20241
Comparable EBITDA
(3)(26)(15)(56)
Depreciation and amortization
— (2)— (5)
Comparable EBIT
(3)(28)(15)(61)
Specific items:
Third-party settlement— — — (34)
Focus Project costs— (5)— (15)
NGTL System ownership transfer costs— — — (10)
Segmented earnings (losses) (3)(33)(15)(120)
1Prior year results have been recast to reflect continuing operations only.
Corporate segmented losses decreased by $30 million and $105 million for the three and nine months ended September 30, 2025 compared to the same periods in 2024. Corporate segmented losses included the following specific items, which have been excluded from our calculation of comparable EBITDA and comparable EBIT:
•a pre-tax expense of $34 million (US$25 million) in first quarter 2024 related to a non-recurring third-party settlement
•a pre-tax charge of $5 million and $15 million for the three and nine months ended September 30, 2024 related to Focus Project costs
•a pre-tax cost of $10 million in second quarter 2024 related to the NGTL System Ownership Transfer.
Comparable EBITDA for Corporate increased by $23 million and $41 million for the three and nine months ended September 30, 2025 compared to the same periods in 2024 primarily due to costs in 2024 related to TC Energy's corporate services and governance functions that were not allocated to discontinued operations.
INTEREST EXPENSE
 
three months ended
September 30		nine months ended
September 30
(millions of $)2025
20241
2025
20241
Interest expense on long-term debt and junior subordinated notes
Canadian dollar-denominated(204)(211)(601)(656)
U.S. dollar-denominated (424)(471)(1,282)(1,415)
Foreign exchange impact(159)(172)(511)(510)
(787)(854)(2,394)(2,581)
Other interest and amortization expense(63)(48)(148)(135)
Capitalized interest2 66 7 200 
Interest expense allocated to discontinued operations
— 59 — 176 
Interest expense included in comparable earnings(848)(777)(2,535)(2,340)
Specific item:
Risk management activities
1 — 1 — 
Interest expense (847)(777)(2,534)(2,340)
1Prior year results have been recast to reflect continuing operations only.
24 | TC Energy Third Quarter 2025

Interest expense increased by $70 million and $194 million for the three and nine months ended September 30, 2025 compared to the same periods in 2024 and included $1 million in third quarter 2025 of unrealized gains on derivatives used to manage our interest rate risk, which has been removed from our calculation of Interest expense included in comparable earnings. Refer to the Financial risks and financial instruments section for additional information.
Interest expense included in comparable earnings increased by $71 million and $195 million for the three and nine months ended September 30, 2025 compared to the same periods in 2024 primarily due to the net effect of:
•lower capitalized interest due to the declared commercial in-service of the Coastal GasLink pipeline in fourth quarter 2024
•no interest expense allocated to discontinued operations in 2025
•long-term debt issuances and maturities, including lower interest expense resulting from TCPL’s cash tender offers completed in fourth quarter 2024. Refer to our 2024 Annual Report and the Financial condition section for additional information
•the foreign exchange impact from a stronger U.S. dollar on translation of U.S. dollar-denominated interest expense.
ALLOWANCE FOR FUNDS USED DURING CONSTRUCTION
 three months ended
September 30		nine months ended
September 30
(millions of $)2025202420252024
Canadian dollar-denominated13 8 37 25 
U.S. dollar-denominated30 149 268 387 
Foreign exchange impact12 53 112 139 
Allowance for funds used during construction55 210 417 551 
AFUDC decreased by $155 million and $134 million for the three and nine months ended September 30, 2025 compared to the same periods in 2024.
The decrease in AFUDC for the three and nine months ended September 30, 2025 is primarily the result of the completion of the Southeast Gateway pipeline in second quarter 2025 and the suspension of AFUDC on the south section of the Villa de Reyes pipeline in first quarter 2025 due to ongoing construction delays on the project pending the resolution of outstanding stakeholder issues, partially offset by capital expenditures on our U.S. natural gas pipeline projects.
FOREIGN EXCHANGE GAINS (LOSSES), NET
three months ended
September 30		nine months ended
September 30
(millions of $)2025202420252024
Foreign exchange gains (losses), net included in comparable earnings22 (33)67 (41)
Specific items:
Foreign exchange gains (losses), net – intercompany loan1
76 (29)(94)41 
Risk management activities(68)24 169 (78)
Foreign exchange gains (losses), net
30 (38)142 (78)
1     Includes non-controlling interest. Refer to Net (income) loss attributable to non-controlling interests for additional information.
Foreign exchange gains (losses), net, changed by $68 million and $220 million for the three and nine months ended September 30, 2025 compared to the same periods in 2024. The following specific items have been removed from our calculation of Foreign exchange gains (losses), net included in comparable earnings:
•unrealized foreign exchange gains and losses on the peso-denominated intercompany loan between TCPL and TGNH
•unrealized gains and losses from changes in the fair value of derivatives used to manage our foreign exchange risk. Refer to the Financial risks and financial instruments section for additional information.
TC Energy Third Quarter 2025 | 25

Foreign exchange gains (losses), net included in comparable earnings changed by $55 million and $108 million for the three and nine months ended September 30, 2025 compared to the same periods in 2024. The changes were primarily due to the net effect of:
•risk management activities used to manage our foreign exchange exposure to net liabilities in Mexico and to U.S. dollar‑denominated income
•foreign exchange losses in 2025 compared to foreign exchange gains in 2024 on the revaluation of our peso-denominated net monetary liabilities to U.S. dollars
•a net realized gain in second quarter 2024 on the partial repayment of the peso-denominated intercompany loan between TCPL and TGNH.
INTEREST INCOME AND OTHER
 three months ended
September 30		nine months ended
September 30
(millions of $)2025
20241
2025
20241
Interest income and other47 61 147 204 
1Prior year results have been recast to reflect continuing operations only.
Interest income and other decreased by $14 million and $57 million for the three and nine months ended September 30, 2025 compared to the same periods in 2024 due to lower interest earned on short-term investments, partially offset by the change in fair value of other restricted investments.
INCOME TAX (EXPENSE) RECOVERY
 three months ended
September 30		nine months ended
September 30
(millions of $)2025
20241
2025
20241
Income tax (expense) recovery included in comparable earnings(260)(180)(846)(604)
Specific items:
Expected credit loss provision on net investment in leases and certain contract assets in Mexico
(3)1 26 (6)
Foreign exchange gains (losses), net – intercompany loan
(7)— (13)— 
Gain on sale of PNGTS— (116)— (116)
Gain on sale of non-core assets— — — 15 
Third-party settlement— — — 8 
Focus Project costs— 2 — 4 
NGTL System ownership transfer costs— — — (32)
Bruce Power unrealized fair value adjustments(2)(1)(7)(1)
Risk management activities27 (13)(35)33 
Income tax (expense) recovery(245)(307)(875)(699)
1Prior year results have been recast to reflect continuing operations only.
Income tax expense decreased by $62 million and increased by $176 million for the three and nine months ended September 30, 2025 compared to the same periods in 2024. The income tax impacts on specified items referenced throughout the MD&A have been removed from our calculation of Income tax expense included in comparable earnings.
Income tax expense included in comparable earnings increased by $80 million and $242 million for the three and nine months ended September 30, 2025 compared to the same periods in 2024 primarily due to the impact of Mexico foreign exchange exposure, higher flow-through income taxes and a change in geographic and business mix of earnings.
26 | TC Energy Third Quarter 2025

NET (INCOME) LOSS ATTRIBUTABLE TO NON-CONTROLLING INTERESTS
Non-Controlling Interests
Ownership at 
September 30, 2025
three months ended
September 30		nine months ended
September 30
(millions of $)2025202420252024
Columbia Gas and Columbia Gulf40%(131)(126)(453)(416)
Texas Wind Farms1
100%8 9 27 20 
TGNH2
13.01%(13)(21)(42)(31)
PNGTS3
—— (7)— (30)
Net (income) loss attributable to non-controlling interests included in comparable earnings
(136)(145)(468)(457)
Specific items:
Foreign exchange (gains) losses, net – intercompany loan11 (23)52 (41)
 Expected credit loss provision on net investment in leases and certain contract assets in Mexico
(2)— 8 — 
Net (income) loss attributable to non-controlling interests(127)(168)(408)(498)
1    Tax equity investors own 100 per cent of the Class A Membership Interests, to which a percentage of earnings, tax attributes and cash flows are allocated. We own 100 per cent of the Class B Membership Interests.
2    In second quarter 2024, the CFE became a partner in TGNH with a 13.01 per cent equity interest in TGNH. Refer to the Recent developments – Mexico Natural Gas Pipelines section for additional information.
3    The sale of PNGTS was completed in August 2024.
Net income attributable to non-controlling interests decreased by $41 million and $90 million for the three and nine months ended September 30, 2025 compared to the same periods in 2024 and included the following specific items which have been excluded from our calculation of Net (income) loss attributable to non-controlling interests included in comparable earnings:
•the non-controlling interest portion of the unrealized foreign exchange gains and losses on the TGNH peso-denominated intercompany loan payable to TCPL
•the expected credit loss provision related to the TGNH net investment in leases and certain contract assets in Mexico.
Net income attributable to non-controlling interests included in comparable earnings decreased by $9 million for the three months ended September 30, 2025 compared to the same period in 2024 and is primarily the result of lower net income in TGNH due to the net effect of higher EBITDA and lower AFUDC resulting from the completion of the Southeast Gateway pipeline in second quarter 2025 and the overall impact of foreign exchange. In addition, the divestiture of PNGTS in third quarter 2024 , partially offset by higher net income recognized from the Columbia Gas and Columbia Gulf assets also contributed to lower net income attributable to non-controlling interests.
Net income attributable to non-controlling interests included in comparable earnings increased by $11 million for the
nine months ended September 30, 2025 compared to the same period in 2024, due to the net effect of higher net income recognized from the Columbia Gas and Columbia Gulf assets, the divestiture of PNGTS in third quarter 2024, the completion of the Southeast Gateway pipeline in second quarter 2025 and the sale of the 13.01 per cent non-controlling equity interest in TGNH to the CFE in second quarter 2024.
TC Energy Third Quarter 2025 | 27

PREFERRED SHARE DIVIDENDS
three months ended
September 30		nine months ended
September 30
(millions of $)2025202420252024
Preferred share dividends(28)(26)(84)(76)
Preferred share dividends increased by $2 million and $8 million for the three and nine months ended September 30, 2025 compared to the same periods in 2024 primarily due to the dividend rate resets on Series 1, 7 and 9 preferred shares in 2024.
On June 30, 2025, 104,778 Series 3 preferred shares were converted, on a one-for-one basis, into Series 4 preferred shares and 1,822,829 Series 4 preferred shares were converted, on a one-for-one basis, into Series 3 preferred shares.
28 | TC Energy Third Quarter 2025

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, 2025 after considering natural offsets and economic hedges was not significant.
The components of our financial results denominated in U.S. dollars are set out in the table below, including our U.S. Natural Gas Pipelines and Mexico Natural Gas Pipelines operations. Comparable EBITDA is a non-GAAP measure.
PRE-TAX U.S. DOLLAR-DENOMINATED INCOME AND EXPENSE ITEMS – FROM CONTINUING OPERATIONS
three months ended
September 30		nine months ended
September 30
(millions of US$)2025
20241
2025
20241
Comparable EBITDA
U.S. Natural Gas Pipelines 770 734 2,510 2,435 
Mexico Natural Gas Pipelines303 195 696 563 
1,073 929 3,206 2,998 
Depreciation and amortization(214)(186)(601)(573)
Interest expense on long-term debt and junior subordinated notes(424)(471)(1,282)(1,415)
Interest expense allocated to discontinued operations— 42 — 125 
Allowance for funds used during construction30 149 268 387 
Net (income) loss attributable to non-controlling interests included in comparable earnings and other(104)(118)(339)(356)
 361 345 1,252 1,166 
Average exchange rate – U.S. to Canadian dollars
1.38 1.36 1.40 1.36 
1    Prior year results have been recast to reflect continuing operations only.
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. This exposure increases as our U.S. dollar‑denominated net monetary liabilities grow.
TC Energy Third Quarter 2025 | 29

The above exposures are managed using foreign exchange derivatives, although some unhedged exposure remains. The impacts of the foreign exchange derivatives are recorded in Foreign exchange (gains) losses, net in the Condensed consolidated statement of income. Refer to the Financial risks and financial instruments section for additional information.
The period end exchange rates for one U.S. dollar to Mexican pesos were as follows:
September 30, 202518.36 
September 30, 202419.70 
December 31, 202420.87 
December 31, 2023
16.91 
A summary of the impacts of transactional foreign exchange gains and losses from changes in the value of the Mexican peso against the U.S. dollar and associated derivatives is set out in the table below:
three months ended
September 30		nine months ended
September 30
(millions of $)2025202420252024
Comparable EBITDA - Mexico Natural Gas Pipelines1
(14)40 (68)85 
Foreign exchange gains (losses), net included in comparable earnings
32 (31)104 (32)
Income tax (expense) recovery included in comparable earnings(17)43 (76)83 
Net (income) loss attributable to non-controlling interests included in comparable earnings2
1 (4)7 (8)
2 48 (33)128 
1Includes the foreign exchange impacts from the Sur de Texas joint venture recorded in Income (loss) from equity investments in the Condensed consolidated statement of income.
2    Represents the non-controlling interest portion related to TGNH. Refer to the Corporate section for additional information.
30 | TC Energy Third Quarter 2025

Recent developments
CANADIAN NATURAL GAS PIPELINES
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 Multi-Year Growth Plan (MYGP) for expansion facilities on the NGTL System. It is comprised of multiple distinct projects with various targeted in-service dates, subject to final company and regulatory approvals. With in-service dates beginning in 2026, a total of approximately $0.7 billion of MYGP expansion facilities have received FID, including $0.4 billion in 2025. We continue to evaluate plans for each MYGP facility to optimize cost and schedule. The completion of the MYGP is expected to enable approximately 1.0 Bcf/d of incremental system throughput.
Valhalla North and Berland River Project
We continue to advance construction of the Valhalla North and Berland River project. The Valhalla section, which consists of approximately 33 km (21 miles) of new pipeline, was placed in service in third quarter 2025, with a capital cost of approximately $0.2 billion. The project is designed to provide incremental capacity on the NGTL System of approximately 428 TJ/d (400 MMcf/d) and consists of new pipeline, one new non-emitting electric compressor unit and associated facilities.
Coastal GasLink
Coastal GasLink Pipeline
In November 2024, Coastal GasLink Limited Partnership (Coastal GasLink LP) executed a commercial agreement with LNG Canada (LNGC) and each of the five LNGC Participants (LNGC Participants) that declared commercial in-service for Coastal GasLink pipeline, enabling toll collection from customers retroactive to October 1, 2024. The agreement also provided for a one-time payment of $199 million from LNGC Participants to TC Energy in recognition of completed work and final cost settlement, payable upon the earlier of three months following the LNG facility's declared in-service date or December 15, 2025.
Effective July 12, 2025, the LNG facility was declared in-service by LNGC. Pursuant to the commercial agreement, TC Energy received the one-time payment of $199 million in October 2025. This payment, which accrues entirely to TC Energy under the contractual arrangements between the Coastal GasLink LP partners, was recognized as an in-substance distribution from Coastal GasLink LP in our financial statements as at December 31, 2024.
Coastal GasLink LP has resolved all material claims with contractors with a net positive recovery overall to Coastal GasLink LP. Refer to Note 14, Commitments, contingencies and guarantees, of our Condensed consolidated financial statements for additional information.
Indigenous Equity Option
In March 2022, we announced the signing of option agreements to sell up to a 10 per cent equity interest in Coastal
GasLink LP to Indigenous communities across the project corridor, from our current 35 per cent equity ownership. In September 2025, prospective investors entered into a non-binding window, which is due to close at the end of 2025.


TC Energy Third Quarter 2025 | 31

U.S. NATURAL GAS PIPELINES
Columbia Gas Section 4 Rate Case
Columbia Gas filed a Section 4 Rate Case with FERC in September 2024 requesting an increase to its maximum transportation rates effective April 1, 2025, subject to refund upon completion of the current rate proceeding. On October 30, 2025, FERC approved the settlement filing. Previously accrued rate refund liabilities will be refunded to customers, including interest, in fourth quarter 2025.
ANR and GLGT Section 4 Rate Cases
In April 2025, ANR and GLGT each filed Section 4 Rate Cases with FERC requesting an increase to their respective maximum transportation rates effective November 1, 2025, subject to refund. We will pursue a collaborative process to find a mutually beneficial outcome with our customers through settlement.
East Lateral XPress
The East Lateral XPress project, an expansion project on the Columbia Gulf system that connects supply to U.S. Gulf Coast LNG export markets, was placed in service in May 2025, with a total project cost of approximately US$0.3 billion.
Northwoods Project
In April 2025, we approved the Northwoods project, an expansion project on our ANR system designed to provide
0.4 Bcf/d of capacity to serve natural gas-fired electric generation demand in the U.S. Midwest, including data centres and
overall economic growth. The project involves pipeline looping, compressor facility additions as well as other system updates, with an anticipated in-service date of late 2029 and an estimated project cost of approximately US$0.9 billion.
VR and WR Projects
In November 2025, we placed the VR and WR projects into service. The VR project, provides incremental capacity from Greensville County, Virginia to delivery points in Norfolk, Virginia, with a total project cost of approximately US$0.5 billion. The WR project, provides mainline capacity to multiple points of delivery on our ANR System in Wisconsin with a total project cost of approximately US$0.7 billion.
TCO Connector & Midwest Connector Projects
In October 2025, we approved the US$0.3 billion TCO Connector and US$0.1 billion Midwest Connector projects on our Columbia Gas and extended system. Together these projects are designed to provide approximately 0.6 Bcf/d of capacity to serve new natural gas-fired power generation supporting forecasted electric generation growth, including expected data centre growth across our system. The TCO Connector and Midwest Connector projects have anticipated in-service dates of 2030 and 2031, respectively.
32 | TC Energy Third Quarter 2025

MEXICO NATURAL GAS PIPELINES
TGNH Strategic Alliance with the CFE
The Southeast Gateway pipeline is in service and we commenced the collection of tolls beginning May 2025. In July 2025, the newly constituted Comisión Nacional de Energía (CNE) approved our regulated rates required to provide service to potential future interruptible service users on the Southeast Gateway pipeline other than the CFE.
During second quarter 2024, upon the CFE’s equity injection of US$340 million as well as non-cash consideration in recognition of the completion of certain contractual obligations, including land acquisition and permitting support, the CFE became a partner in TGNH with a 13.01 per cent equity interest. With the CFE's contractual support related to land acquisition, community relations and permitting, the CFE's equity in TGNH is expected to increase to a maximum of 15 per cent, subject to regulatory approvals, and will increase to approximately 35 per cent upon expiry of the contract in 2055.
POWER AND ENERGY SOLUTIONS
Bruce Power Life Extension
Bruce Power received approval of the Unit 5 MCR final cost and schedule estimate from the IESO on April 2, 2025. The     Unit 5 MCR is expected to commence in fourth quarter 2026 with a return to service in early 2030.
CORPORATE
2016 Columbia Pipeline Acquisition Lawsuit
In 2018, former shareholders of Columbia Pipeline Group Inc. (CPG) commenced a class action lawsuit related to the acquisition of CPG by TC Energy in 2016. In 2023, the Delaware Chancery Court (the Court) found that the former CPG executives breached their fiduciary duties, that the former CPG Board breached its duty of care in overseeing the sale     process and that TC Energy aided and abetted those breaches. TC Energy’s allocated share of damages was an estimated US$350 million, plus post-judgment interest. TC Energy appealed the decision to the Delaware Supreme Court and on     June 17, 2025, the Supreme Court issued its decision reversing the Court’s finding of liability against TC Energy. On         July 10, 2025, the Court granted the final order vacating its prior judgment and dismissing plaintiffs’ claims against         TC Energy. As a result, this matter is now concluded in TC Energy’s favour with no liability. There is no further right             of appeal.

TC Energy Third Quarter 2025 | 33

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, 2025, our current assets totaled $7.5 billion and current liabilities amounted to $11.9 billion, leaving us with a working capital deficit of $4.4 billion compared to a deficit of $4.8 billion at December 31, 2024, excluding discontinued operations. Our working capital deficiency is considered to be in the normal course of business and is managed through:
•our ability to generate predictable cash flows from operations
•a total of $7.9 billion of TCPL committed revolving credit facilities, of which $5.7 billion of short-term borrowing capacity remains available, net of $2.2 billion backstopping outstanding commercial paper balances, and arrangements for a further $2.0 billion of demand credit facilities, of which $1.3 billion remains available as of September 30, 2025
•additional $2.0 billion of committed revolving credit facilities at certain of our subsidiaries and affiliates, of which         $1.9 billion of short-term borrowing capacity remains available as of September 30, 2025, net of $0.1 billion backstopping outstanding commercial paper balances
•our access to capital markets, including through securities issuances, incremental credit facilities, capital rotation and DRP, if deemed appropriate.
CASH PROVIDED BY OPERATING ACTIVITIES1,2
 three months ended
September 30		nine months ended
September 30
(millions of $)2025202420252024
Net cash provided by operations1,920 1,915 5,452 5,612 
Increase (decrease) in operating working capital(130)(203)251 313 
Funds generated from operations1,790 1,712 5,703 5,925 
Specific items:
Third-party settlement, net of current income tax— — — 26 
NGTL System ownership transfer costs— — — 10 
Current income tax (recovery) expense on sale of PNGTS and non-core assets
— 139 — 148 
Liquids Pipelines business separation costs, net of current income tax
— 58 — 100 
Focus Project costs, net of current income tax— 4 — 13 
Current income tax (recovery) expense on Keystone XL asset impairment charge and other— (3)— (3)
Current income tax (recovery) expense on Keystone regulatory decisions— (3)— (3)
Current income tax (recovery) expense on risk management activities— 8 — 9 
Comparable funds generated from operations1,790 1,915 5,703 6,225 
1    Includes continuing and discontinued operations.
2    Includes Liquids Pipelines earnings for the three and nine months ended September 30, 2024 compared to Liquids Pipelines earnings of nil for the same periods in 2025. Refer to the Discontinued operations section and our 2024 Annual Report for additional information.
34 | TC Energy Third Quarter 2025

Net cash provided by operations
Net cash provided by operations was generally consistent for the three months ended September 30, 2025 compared to the same period in 2024. Net cash provided by operations decreased by $160 million for the nine months ended September 30, 2025 compared to the same period in 2024 primarily due to lower funds generated from operations, partially offset by the timing of working capital changes.
Comparable funds generated from operations
Comparable funds generated from operations, a non-GAAP measure, helps us assess the cash generating ability of our businesses by excluding the timing effects of working capital changes, as well as the cash impact of our specific items.
Comparable funds generated from operations decreased by $125 million and $522 million for the three and nine months ended September 30, 2025 compared to the same periods in 2024 primarily due to lower comparable earnings and lower distributions from our equity investments.
CASH (USED IN) PROVIDED BY INVESTING ACTIVITIES
 three months ended
September 30		nine months ended
September 30
(millions of $)2025202420252024
Capital spending
Capital expenditures(1,255)(1,756)(3,924)(4,668)
Capital projects in development (2)(8)(12)(41)
Contributions to equity investments(249)(345)(758)(888)
(1,506)(2,109)(4,694)(5,597)
Proceeds from sale of assets, net of transaction costs
— 743 — 791 
Other distributions from equity investments— 509 5 539 
Deferred amounts and other(87)2 (126)(126)
Net cash (used in) provided by investing activities(1,593)(855)(4,815)(4,393)
Net cash used in investing activities increased by $738 million and $422 million for the three and nine months ended September 30, 2025 compared to the same periods in 2024 primarily due to proceeds from sale of assets in 2024, partially offset by decreased capital spending in 2025.
Capital expenditures incurred for the nine months ended September 30, 2025 were primarily for the advancement of the Columbia Gas and ANR projects, as well as maintenance capital expenditures. Lower capital expenditures for the nine months ended September 30, 2025 compared to the same period in 2024 reflect the completion of the Southeast Gateway pipeline in second quarter 2025, partially offset by increased spending on ANR projects.
TC Energy Third Quarter 2025 | 35

CASH (USED IN) PROVIDED BY FINANCING ACTIVITIES
 three months ended
September 30		nine months ended
September 30
(millions of $)2025202420252024
Notes payable issued (repaid), net(59)(1,137)2,037 421 
Long-term debt issued, net of issue costs831 7,428 3,252 8,089 
Long-term debt repaid(805)— (4,029)(1,662)
Junior subordinated notes issued, net of issue costs989 1,465 2,043 1,465 
Dividends and distributions paid(1,025)(1,325)(3,122)(3,699)
Common shares issued, net of issue costs37 21 87 21 
Disposition of equity interest, net of transaction costs— (7)— 419 
Contributions from non-controlling interest— 11 — 16 
Cash received from factoring arrangement
101 — 101 — 
Net cash (used in) provided by financing activities 69 6,456 369 5,070 
Long-term debt issued
The following table outlines significant long-term debt issuances in the nine months ended September 30, 2025:
(millions of Canadian $, unless otherwise noted)
CompanyIssue date Type Maturity dateAmountInterest rate
TransCanada PipeLines Limited
February 2025
Medium Term Notes
February 2035
1,000 4.58%
ANR Pipeline Company
September 2025
Senior Unsecured Notes
September 2031
US 250 5.23%
September 2025
Senior Unsecured Notes
September 2035
US 350 5.69%
Columbia Pipelines Operating Company LLC
March 2025
Senior Unsecured Notes
February 2035
US 550 5.44%
March 2025
Senior Unsecured Notes
February 2055
US 450 5.96%
On October 10, 2025, Great Lakes Gas Transmission Limited Partnership issued a US$205 million unsecured term loan maturing in October 2028, bearing interest at a floating rate.
Long-term debt repaid/retired
The following table outlines significant long-term debt repaid/retired in the nine months ended September 30, 2025:
(millions of Canadian $, unless otherwise noted)
CompanyRepayment dateType AmountInterest rate
TransCanada PipeLines Limited
July 2025Medium Term Notes750 3.30%
Nova Gas Transmission Ltd.
May 2025Medium Term Notes878.90%
Columbia Pipelines Operating Company LLC
March 2025
Senior Unsecured NotesUS 1,000 4.50%
TC PipeLines, LP
March 2025
Senior Unsecured Notes
US 350 4.38%
TC Energía Mexicana, S. de R.L. de C.V.
VariousSenior Unsecured Term LoanUS 122Floating
On October 14, 2025, TCPL retired US$92 million of senior unsecured notes bearing interest at a fixed rate of 7.06 per cent.
36 | TC Energy Third Quarter 2025

Junior subordinated notes issued
The following table outlines significant junior subordinated notes issued in the nine months ended September 30, 2025:
(unaudited - millions of Canadian $, unless otherwise noted)
CompanyIssue date Type Maturity dateAmountInterest rate
TransCanada PipeLines Limited
August 2025
Junior Subordinated Notes
February 2056
 1,000 5.20%
1

February 2025
Junior Subordinated Notes
June 2065
US 750 7.00%
2
1    Fixed rate of interest per year until February 15, 2031, and resetting every five years thereafter, subject to a rate-reset minimum.
2    Fixed rate of interest per year until June 1, 2030, and resetting every five years thereafter.
In October 2025, TCPL issued US$370 million of junior subordinated notes, including the exercise of the over-allotment option, maturing in 2085 with a fixed interest rate of 6.25 per cent. We intend to use the proceeds from the issuance to redeem all issued and outstanding TC Energy Series 11 preferred shares on November 28, 2025 pursuant to their terms, to reduce indebtedness and for general corporate purposes.
Junior subordinated notes repaid/retired
In May 2025, TCPL exercised its option to fully repay and retire the US$750 million junior subordinated notes that had a maturity date of 2075, bearing interest at 5.88 per cent to TransCanada Trust (the Trust). All of the proceeds from the repayment were used by the Trust to fund the redemption price of the US$750 million in aggregate principal amount of outstanding Trust Notes - Series 2015-A, in May 2025 pursuant to their terms. Refer to Note 8, Junior subordinated notes, of our Condensed consolidated financial statements for additional information.
DIVIDENDS
On November 6, 2025, we announced a quarterly dividend on our outstanding common shares of $0.85 per share payable on January 30, 2026 to shareholders of record at the close of business on December 31, 2025.
Commencing with the dividends payable on January 31, 2025 to shareholders of record at the close of business on December 31, 2024, the amounts reflect TC Energy's proportionate allocation following the Spinoff Transaction. Refer to our 2024 Annual Report for additional information.
SHARE INFORMATION
At October 30, 2025, we had approximately 1.0 billion issued and outstanding common shares and approximately 2.4 million outstanding options to buy common shares, of which 2.0 million were exercisable.
On June 30, 2025, 104,778 Series 3 preferred shares were converted, on a one-for-one basis, into Series 4 preferred shares and 1,822,829 Series 4 preferred shares were converted, on a one-for-one basis, into Series 3 preferred shares.
CREDIT FACILITIES
At October 30, 2025, we had a total of $7.9 billion of TCPL committed revolving credit facilities, of which $5.9 billion of     short-term borrowing capacity remains available, net of $2.0 billion backstopping outstanding commercial paper balances. We also have arrangements in place for a further $2.0 billion of demand credit facilities, of which $1.2 billion remains available.
In addition, we have $2.1 billion of committed revolving credit facilities at certain of our subsidiaries and affiliates, of which $2.0 billion of borrowing capacity remains available at October 30, 2025, net of $0.1 billion backstopping outstanding commercial paper balances.
TC Energy Third Quarter 2025 | 37

CONTRACTUAL OBLIGATIONS
Capital expenditure commitments at September 30, 2025 are consistent with amounts reported at December 31, 2024, reflecting new contractual commitments entered into for construction on U.S. natural gas pipelines primarily related to the construction costs associated with ANR and other pipeline projects, offset by completion of Southeast Gateway pipeline and normal course fulfillment of construction contracts.
There were no material changes to our contractual obligations in third quarter 2025 or to payments due in the next five years or thereafter. Refer to our 2024 Annual Report for additional information about our contractual obligations.
38 | TC Energy Third Quarter 2025

Discontinued operations
On October 1, 2024, TC Energy completed the spinoff of its Liquids Pipelines business into a new public company, South Bow Corporation (South Bow). Upon completion of the Spinoff Transaction, the Liquids Pipelines business was accounted for as a discontinued operation. Prior year amounts have been recast to present the Liquids Pipelines business as a discontinued operation. Refer to our 2024 Annual Report for additional information.
RESULTS FROM DISCONTINUED OPERATIONS
three months ended
September 30		nine months ended
September 30
(millions of $, except per share amounts)
2025
20241
2025
20241
Segmented earnings (losses) from discontinued operations
(210)236 (239)825 
Interest expense— (101)— (218)
Interest income and other14 28 14 31 
Income (loss) from discontinued operations before income taxes
(196)163 (225)638 
Income tax (expense) recovery(8)(44)(8)(145)
Net income (loss) from discontinued operations, net of tax
(204)119 (233)493 
Net income (loss) per common share from discontinued operations - basic
($0.20)$0.11 ($0.22)$0.47 
1    Prior year results have been recast to reflect the Liquids Pipelines business as a discontinued operation as a result of the Spinoff Transaction.
In September 2025, we reached an agreement with South Bow with respect to liabilities we indemnified South Bow for under the Separation Agreement, releasing us from those liabilities. Inclusive of the recognition of the settlement, the net loss from discontinued operations, net of tax was $204 million for the three months ended September 30, 2025 and has been excluded from our calculation of comparable measures from discontinued operations. Payments related to the settlement will occur in fourth quarter 2025 and in 2026.
In June 2025, we received $24 million related to certain recoveries under the Separation Agreement with South Bow. At this time, we also revised our estimate of our share of future recoveries, resulting in a $29 million impairment charge, which has been included in Net income (loss) from discontinued operations, net of tax in the Condensed consolidated statement of income and excluded from our calculation of comparable measures from discontinued operations. Refer to Note 3, Discontinued operations, of our Condensed consolidated financial statements for additional information.
TC Energy Third Quarter 2025 | 39

NON-GAAP MEASURES
This MD&A references non-GAAP measures, which are described in the Non-GAAP measures section. 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.
RECONCILIATION OF NET INCOME (LOSS) FROM DISCONTINUED OPERATIONS, NET OF TAX TO COMPARABLE EARNINGS FROM DISCONTINUED OPERATIONS
three months ended
September 30		nine months ended
September 30
(millions of $, except per share amounts)2025
20241
2025
20241
Net income (loss) from discontinued operations, net of tax
(204)119 (233)493 
Specific items (pre tax):
 South Bow settlement2
196 — 196 — 
Keystone XL asset impairment charge3
— 21 29 21 
Liquids Pipelines business separation costs4
— 67 — 112 
Keystone regulatory decisions5
— 15 — 15 
Risk management activities— (31)— (67)
Taxes related to specific items6
8 (11)8 (9)
Comparable earnings from discontinued operations
— 180 — 565 
Net income (loss) per common share from discontinued operations($0.20)$0.11 ($0.22)$0.47 
Specific items (net of tax)0.20 0.06 0.22 0.07 
Comparable earnings per common share from discontinued operations
— $0.17— $0.54
1Prior year results have been recast to reflect the Liquids Pipelines business as a discontinued operation as a result of the Spinoff Transaction.
2A pre-tax charge of $196 million for the three and nine months ended September 30, 2025 resulting from the resolution reached in September 2025 under the Separation Agreement with South Bow.
3A pre-tax impairment charge of $29 million for the nine months ended September 30, 2025 related to our estimate of Keystone XL contractual recoveries.
4A pre-tax charge of $67 million and $112 million for the three and nine months ended September 30, 2024, respectively, related to Liquids Pipelines business separation costs from the Spinoff Transaction.
5A pre-tax charge of $15 million for the three and nine months ended September 30, 2024 as a result of the FERC Administrative Law Judge decision on Keystone in respect of a tolling-related complaint pertaining to amounts recognized in prior period.
6The income tax impacts on the specified items mentioned in the table above have been removed from our calculation of Income tax expense included in comparable earnings from discontinued operations below.
40 | TC Energy Third Quarter 2025

COMPARABLE EBITDA TO COMPARABLE EARNINGS - FROM DISCONTINUED OPERATIONS
Comparable EBITDA from discontinued operations represents segmented earnings (losses) from discontinued operations adjusted for the specific items described above, excluding charges for depreciation and amortization.
three months ended September 30nine months ended
September 30
(millions of $, except per share amounts)
20241
20241
Comparable EBITDA from discontinued operations
379 1,145 
Depreciation and amortization(85)(253)
Interest expense included in comparable earnings
(59)(176)
Interest income and other included in comparable earnings
— 3 
Income tax (expense) recovery included in comparable earnings
(55)(154)
Comparable earnings from discontinued operations
180 565 
Comparable earnings per common share from discontinued operations$0.17 $0.54 
1    Prior year results have been recast to reflect the Liquids Pipelines business as a discontinued operation as a result of the Spinoff Transaction.

TC Energy Third Quarter 2025 | 41

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 2024 Annual Report for additional information about the risks we face in our business which have not changed materially since December 31, 2024, 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. We hedge a portion of our net investment in foreign operations (on an after-tax basis) with U.S. dollar‑denominated debt and cross-currency interest rate swaps as appropriate.
COUNTERPARTY CREDIT RISK
We have exposure to counterparty credit risk in a number of areas including:
•cash and cash equivalents
•accounts receivable
•available-for-sale assets
•fair value of derivative assets
•net investment in leases and certain contract assets in Mexico.
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 2024 Annual Report for more information about the factors that mitigate our counterparty credit risk exposure.
42 | TC Energy Third Quarter 2025

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 any impairment, which is recognized in Plant operating costs and other. At September 30, 2025, 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 a pre-tax recovery of $14 million and pre-tax expense $87 million on the expected credit loss provision on the TGNH net investment in leases and certain contract assets in Mexico for the three and nine months ended September 30, 2025 (2024 – pre-tax expense of $5 million and pre-tax recovery of $19 million, respectively). During second quarter 2025, we completed the Southeast Gateway pipeline and recognized a net investment in sales-type lease. Refer to Note 12, Risk management and financial instruments and Note 13, TGNH strategic alliance, of our Condensed consolidated financial statements for additional information.
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 2025 | 43

Balance sheet presentation of derivative instruments
The balance sheet presentation of the fair value of derivative instruments were as follows:
(millions of $)September 30, 2025December 31, 2024
Other current assets390 347 
Other long-term assets126 122 
Accounts payable and other(393)(507)
Other long-term liabilities(136)(209)
(13)(247)
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 $)2025202420252024
Derivative Instruments Held for Trading1
Unrealized gains (losses) in the period
Commodities2
(63)21 (36)(36)
Foreign exchange(68)24 169 (78)
Realized gains (losses) in the period
Commodities20 40 (18)111 
Foreign exchange39 (58)111 (105)
Interest rate
1 — 6 — 
Derivative Instruments in Hedging Relationships
Realized gains (losses) in the period
Commodities3 6 17 24 
Foreign exchange2 — 6 — 
Interest rate(8)(14)(24)(41)
1Realized and unrealized gains (losses) on held-for-trading derivative instruments used to purchase and sell commodities are included on a net basis in Revenues. Realized and unrealized gains (losses) on foreign exchange and interest rate held-for-trading derivative instruments are included on a net basis in Foreign exchange (gains) losses, net and Interest expense, respectively, in the Condensed consolidated statement of income.
2In the three and nine months ended September 30, 2025, unrealized gains of less than $1 million and $1 million, respectively, were reclassified to Net income (loss) from AOCI related to discontinued cash flow hedges (2024 - unrealized gains of $4 million).
For further details on our non-derivative and derivative financial instruments, including classification assumptions made in the calculation of fair value and additional discussion of exposure to risks and mitigation activities, refer to Note 12, Risk management and financial instruments, of our Condensed consolidated financial statements.
44 | TC Energy Third Quarter 2025

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, 2025, 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 2025 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 2024 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.
The estimated fair value in excess of the carrying value was less than 10 per cent on our Columbia and Great Lakes reporting units at the date of our last quantitative goodwill impairment test. Any future reductions in cash flow forecasts or adverse changes in other key assumptions could result in a future impairment of our goodwill balance.
Sales-type leases
We determined that the Southeast Gateway pipeline is classified as a sales-type lease between TGNH and the CFE. We allocated the expected contract consideration to the lease and non-lease components based on the stand-alone selling price for each distinct service at the inception of the agreement in 2022. Under a sales-type lease, we derecognize the underlying asset and record a net investment in lease equal to the present value of both the future lease payments and the estimated residual value of the leased asset.
To record the net investment in lease, we were required to prepare an estimate of the fair value of the Southeast Gateway pipeline. The TGNH pipelines, which includes the Southeast Gateway pipeline, are rate-regulated and the tolls are designed to recover the cost of providing service. On this basis, we applied judgment to determine that, at the inception of the lease arrangement, the fair value of the underlying assets approximated the carrying value and the residual value approximated the remaining carrying value at the end of the lease term. We estimated that if the assets were purchased at their carrying value, they would yield a return to the purchaser that is in line with current market participant expectations.
Accounting changes
Our significant accounting policies have remained unchanged since December 31, 2024 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 2024 Annual Report.
TC Energy Third Quarter 2025 | 45

Quarterly results
SELECTED QUARTERLY CONSOLIDATED FINANCIAL DATA
 2025
20241
20231
(millions of $, except per share amounts)ThirdSecondFirstFourthThirdSecondFirstFourth
Revenues3,704 3,744 3,623 3,577 3,358 3,327 3,509 3,504 
Net income (loss) attributable to common shares609 833 978 971 1,457 963 1,203 1,463 
from continuing operations
813 862 978 1,069 1,338 804 988 1,249 
from discontinued operations
(204)(29)— (98)119 159 215 214 
Comparable earnings2
805 848 983 1,094 1,074 978 1,284 1,403 
from continuing operations
805 848 983 1,094 894 822 1,055 1,192 
from discontinued operations
— — — — 180 156 229 211 
Per share statistics:
Net income (loss) per common share – basic $0.58 $0.80 $0.94 $0.94 $1.40 $0.93 $1.16 $1.41 
from continuing operations$0.78 $0.83 $0.94 $1.03 $1.29 $0.78 $0.95 $1.20 
from discontinued operations($0.20)($0.03)— ($0.09)$0.11 $0.15 $0.21 $0.21 
Comparable earnings per common share2
$0.77 $0.82 $0.95 $1.05 $1.03 $0.94 $1.24 $1.35 
from continuing operations$0.77 $0.82 $0.95 $1.05 $0.86 $0.79 $1.02 $1.15 
from discontinued operations— — — — $0.17 $0.15 $0.22 $0.20 
Dividends declared per common share3
$0.85 $0.85 $0.85 $0.8225 $0.96 $0.96 $0.96 $0.93 
1    Results have been recast to reflect the split between continuing and discontinued operations.
2    Additional information on the most directly comparable GAAP measure can be found in the Non-GAAP measures section.
3    Commencing fourth quarter 2024 and thereafter, amounts reflect dividends declared following the Spinoff Transaction. Refer to our 2024 Annual Report for additional information.
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 expected credit losses on net investment in leases and certain contract assets in Mexico.
46 | TC Energy Third Quarter 2025

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 2025, comparable earnings from continuing operations also excluded:
•pre-tax unrealized foreign exchange gains, net, of $87 million on the peso-denominated intercompany loan between TCPL and TGNH, net of non-controlling interest
•a pre-tax recovery of $12 million on the expected credit loss provision related to TGNH net investment in leases and certain contract assets in Mexico, net of non-controlling interest.
In second quarter 2025, comparable earnings from continuing operations also excluded:
•pre-tax unrealized foreign exchange losses, net, of $132 million on the peso-denominated intercompany loan between TCPL and TGNH, net of non-controlling interest
•a pre-tax expense of $93 million on the expected credit loss provision related to TGNH net investment in leases and certain contract assets in Mexico, net of non-controlling interest.
In first quarter 2025, comparable earnings from continuing operations also excluded:
•pre-tax unrealized foreign exchange gains, net, of $3 million on the peso-denominated intercompany loan between TCPL and TGNH, net of non-controlling interest
•a pre-tax recovery of $2 million on the expected credit loss provision related to TGNH net investment in leases and certain contract assets in Mexico, net of non-controlling interest.
In fourth quarter 2024, comparable earnings from continuing operations also excluded:
•a pre-tax net gain on debt extinguishment of $228 million related to the purchase and cancellation of certain senior unsecured notes and medium term notes and the retirement of outstanding callable notes in October 2024
•pre-tax unrealized foreign exchange gains, net, of $143 million on the peso-denominated intercompany loan between TCPL and TGNH, net of non-controlling interest
•a pre-tax recovery of $3 million on the expected credit loss provision related to TGNH net investment in leases and certain contract assets in Mexico, net of non-controlling interest
•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 related to development costs incurred on Project Tundra, a next-generation technology carbon capture and storage project, following our decision to end our collaboration on the project
•a pre-tax expense of $9 million related to Focus Project costs.
TC Energy Third Quarter 2025 | 47

In third quarter 2024, comparable earnings from continuing operations also excluded:
•a pre-tax gain of $572 million related to the sale of PNGTS which was completed in August 2024
•pre-tax unrealized foreign exchange losses, net, of $52 million on the peso-denominated intercompany loan between TCPL and TGNH, net of non-controlling interest
•a pre-tax expense of $5 million on the expected credit loss provision related to TGNH net investment in leases and certain contract assets in Mexico, net of non-controlling interest
•a pre-tax expense of $5 million related to Focus Project costs.
In second quarter 2024, comparable earnings from continuing operations also excluded:
•a pre-tax gain of $48 million related to the sale of non-core assets in U.S. Natural Gas Pipelines and Canadian Natural Gas Pipelines
•pre-tax unrealized foreign exchange losses, net, of $3 million on the peso-denominated intercompany loan between TCPL and TGNH, net of non-controlling interest
•a pre-tax recovery of $3 million on the expected credit loss provision related to TGNH net investment in leases and certain contract assets in Mexico, net of non-controlling interest
•pre-tax costs of $10 million related to the NGTL System Ownership Transfer.
In first quarter 2024, comparable earnings from continuing operations also excluded:
•pre-tax unrealized foreign exchange gains, net, of $55 million on the peso-denominated intercompany loan between TCPL and TGNH
•a pre-tax recovery of $21 million on the expected credit loss provision related to TGNH net investment in leases and certain contract assets in Mexico
•a pre-tax expense of $34 million related to a non-recurring third-party settlement
•a pre-tax expense of $10 million related to Focus Project costs.
In fourth quarter 2023, comparable earnings from continuing operations also excluded:
•a $74 million income tax recovery related to a revised assessment of the valuation allowance and non-taxable capital losses on our equity investment in Coastal GasLink LP
•pre-tax unrealized foreign exchange losses, net, of $55 million on the peso-denominated intercompany loan between TCPL and TGNH
•a pre-tax expense of $36 million on the expected credit loss provision related to TGNH net investment in leases and certain contract assets in Mexico
•a pre-tax expense of $15 million related to Focus Project costs.
48 | TC Energy Third Quarter 2025