TransCanada Pipelines 6-K Quarterly Report to Shareholders

EXHIBIT 13.1

Quarterly report to shareholders

Third quarter 2024

Financial highlights

	three months ended September 30		nine months ended September 30
(millions of $, except per share amounts)	2024	2023	2024	2023
Income
Revenues	4,083	3,940	12,411	11,698
Net income (loss) attributable to common shares	1,457	(197)	3,623	1,366
per common share – basic	$1.40	($0.19)	$3.49	$1.33
Comparable EBITDA1	2,791	2,632	8,575	7,881
Comparable earnings	1,074	1,035	3,336	3,249
per common share	$1.03	$1.00	$3.21	$3.16
Cash flows
Net cash provided by operations	1,915	1,824	5,612	5,408
Comparable funds generated from operations	1,915	1,755	6,225	5,575
Capital spending2	2,109	3,289	5,597	9,313
Acquisitions, net of cash acquired	—	—	—	(302)
Dividends declared
per common share	$0.96	$0.93	$2.88	$2.79
Basic common shares outstanding (millions)
– weighted average for the period	1,038	1,035	1,038	1,028
– issued and outstanding at end of period	1,038	1,037	1,038	1,037

1Additional information on Segmented earnings (losses), the most directly comparable GAAP measure, can be found in the Consolidated results section.

2Capital spending reflects cash flows associated with our Capital expenditures, Capital projects in development and Contributions to equity investments. Refer to Note 4, Segmented information, of our Condensed consolidated financial statements for additional information.

Management’s discussion and analysis

November 6, 2024

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, 2024 and should be read with the accompanying unaudited Condensed consolidated financial statements for the three and nine months ended September 30, 2024, which have been prepared in accordance with U.S. GAAP.

This MD&A should also be read in conjunction with our December 31, 2023 audited Consolidated financial statements and notes and the MD&A in our 2023 Annual Report. Capitalized and abbreviated terms that are used but not otherwise defined herein are defined in our 2023 Annual Report. Certain comparative figures have been adjusted to reflect the current period's presentation.

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, including our asset divestiture program

•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

•statements related to our GHG emissions reduction goals

•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 and GHG Emissions Reduction Plan

•expected industry, market and economic conditions, 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.

2 | TC Energy Third Quarter 2024

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

Assumptions

•realization of expected benefits from acquisitions, divestitures, the spinoff of our Liquids Pipelines business (the spinoff Transaction) and energy transition

•regulatory decisions and outcomes

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

•integrity and reliability of our assets

•anticipated construction costs, schedules and completion dates

•access to capital markets, including portfolio management

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

•inflation rates, commodity and labour prices

•interest, tax and foreign exchange rates

•nature and scope of hedging.

Risks and uncertainties

•realization of expected benefits from acquisitions, divestitures, the spinoff Transaction and energy transition

•our ability to successfully implement our strategic priorities, including the Focus Project, 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

•impact of energy transition on our business

•economic conditions 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 2023 Annual Report.

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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).

NON-GAAP MEASURES

This MD&A references the following non-GAAP measures:

•comparable EBITDA

•comparable EBIT

•comparable earnings

•comparable earnings per common share

•funds generated from operations

•comparable funds generated from operations

•net capital expenditures.

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. Discussions throughout this MD&A on the factors impacting comparable earnings are consistent with the factors that impact net income (loss) attributable to common shares, except where noted otherwise. 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 adjust for the following specific items:

•gains or losses on sales of assets or assets held for sale

•valuation allowances and adjustments resulting from changes in legislation and enacted tax rates

•legal, contractual, bankruptcy and other settlements, including non-recurring third-party settlements

•impairment of goodwill, plant, property and equipment, equity investments and other assets

•acquisition, integration and restructuring costs, including costs related to our Focus Project, the spinoff Transaction and the ownership transfer of the NGTL System from Nova Gas Transmission Ltd. (NGTL Ltd.) to NGTL GP Ltd. (NGTL GP) on behalf of NGTL Limited Partnership (NGTL LP) (NGTL System Ownership Transfer)

•unrealized fair value adjustments related to Bruce Power's risk management activities and its funds invested for post-retirement benefits

•unrealized gains and losses from changes in the fair value of derivatives related to financial and commodity price risk management activities.

We exclude from comparable measures the unrealized gains and losses from changes in the fair value of derivatives related to financial and commodity price risk management activities. These derivatives generally provide effective economic hedges but do not meet the criteria for hedge accounting. The changes in fair value, including our proportionate share of changes in fair value related to Bruce Power are recorded in net income. As these amounts do not accurately reflect the gains and losses that will be realized at settlement, we do not consider them reflective of our underlying operations.

4 | TC Energy Third Quarter 2024

In third quarter 2023, we announced plans to separate into two independent, investment-grade, publicly listed companies through the spinoff Transaction, which was completed on October 1, 2024. A separation management office was established to guide the successful coordination and governance between the two entities, including the development of a separation agreement and transition services agreement. Liquids Pipelines business separation costs related to the spinoff Transaction include internal costs related to separation activities; legal, tax, audit and other consulting fees, and net financial charges related to debt issued and held in escrow, which are recognized in the results of our Liquids Pipelines and Corporate segments. These items have been excluded from comparable measures as we do not consider them reflective of our ongoing underlying operations.

TransCanada PipeLines Limited (TCPL) and Transportadora de Gas Natural de la Huasteca (TGNH) are 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 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.

In 2023, we accrued an amount for environmental remediation costs related to the Milepost 14 incident. A portion of these insurance proceeds were collected from our wholly-owned captive insurance subsidiary, which resulted in an impact to net income in the consolidated financial results of TC Energy in second quarter 2023. This amount has been excluded from comparable measures as it is not reflective of our ongoing underlying operations.

In 2022, TGNH and the CFE executed agreements which consolidate a number of operating and in-development natural gas pipelines in central and southeast Mexico under one TSA. As this TSA contains a lease, we have recognized amounts in net investment in leases on our Condensed consolidated balance sheet. In accordance with the requirements of U.S. GAAP, we have recognized an expected credit loss provision related to net investment in leases and certain contract assets in Mexico. The amount of this provision will fluctuate from period to period based on changing economic assumptions and forward-looking information. The provision is an estimate of losses that may occur over the duration of the TSA through 2055. As this provision, as well as a provision related to certain contract assets in Mexico, do not reflect losses or cash outflows that were incurred under this lease arrangement in the current period or from our underlying operations, we have excluded any unrealized changes, net of non-controlling interest, from comparable measures.

The following table identifies our non-GAAP measures against their most directly comparable GAAP measures:

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

Quantitative reconciliations of our comparable measures to their GAAP measures are found throughout this MD&A.

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Comparable EBITDA and comparable EBIT

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

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 above. Comparable earnings is comprised of segmented earnings (losses), Interest expense, AFUDC, Foreign exchange (gains) losses, net, Interest income and other, Income tax expense (recovery), Net income (loss) attributable to non-controlling interests and Preferred share dividends on our Condensed consolidated statement of income, adjusted for specific items. Refer to the Consolidated results section for reconciliations to Net income (loss) attributable to common shares and Net income (loss) per common share.

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 2023 Consolidated financial statements. We believe funds generated from operations is a useful measure of our consolidated operating cash flows because it excludes fluctuations from working capital balances, which do not necessarily reflect underlying operations in the same period, and is used to provide a consistent measure of the cash-generating ability of our businesses. Comparable funds generated from operations is adjusted for the cash impact of specific items described in the Comparable measures section above. Refer to the Financial condition section for a reconciliation to Net cash provided by operations.

Net capital expenditures

Net capital expenditures represents capital expenditures, including 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. We use net capital expenditures as we believe it is a useful measure of our cash flow used for capital reinvestment.

6 | TC Energy Third Quarter 2024

Consolidated results

	three months ended September 30		nine months ended September 30
(millions of $, except per share amounts)	2024	2023	2024	2023
Canadian Natural Gas Pipelines	495	(799)	1,510	(782)
U.S. Natural Gas Pipelines	1,330	782	3,135	2,576
Mexico Natural Gas Pipelines	237	210	715	646
Liquids Pipelines	240	253	826	702
Power and Energy Solutions	354	234	826	741
Corporate	(37)	(36)	(121)	(74)
Total segmented earnings (losses)	2,619	644	6,891	3,809
Interest expense	(878)	(865)	(2,558)	(2,418)
Allowance for funds used during construction	210	164	551	443
Foreign exchange gains (losses), net	(38)	(45)	(78)	231
Interest income and other	89	63	235	121
Income (loss) before income taxes	2,002	(39)	5,041	2,186
Income tax (expense) recovery	(351)	(134)	(844)	(733)
Net income (loss)	1,651	(173)	4,197	1,453
Net (income) loss attributable to non-controlling interests	(168)	(1)	(498)	(18)
Net income (loss) attributable to controlling interests	1,483	(174)	3,699	1,435
Preferred share dividends	(26)	(23)	(76)	(69)
Net income (loss) attributable to common shares	1,457	(197)	3,623	1,366
Net income (loss) per common share – basic	$1.40	($0.19)	$3.49	$1.33

Net income (loss) attributable to common shares increased by $1,654 million or $1.59 per common share and $2,257 million or $2.16 per common share for the three and nine months ended September 30, 2024 compared to the same periods in 2023. The following specific items were recognized in Net income (loss) attributable to common shares and were excluded from comparable earnings:

2024 results

•an after-tax gain of $456 million for the three and nine months ended September 30, 2024 related to the sale of Portland Natural Gas Transmission System (PNGTS) which was completed on August 15, 2024

•an after-tax gain of $63 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 $4 million after-tax expense and a $13 million after-tax recovery for the three and nine months ended September 30, 2024 on the expected credit loss provision related to the TGNH net investment in leases and certain contract assets in Mexico, net of non-controlling interest

•an after-tax charge of $56 million and $95 million for the three and nine months ended September 30, 2024 due to Liquids Pipelines business separation costs related to the spinoff Transaction

•after-tax costs of $42 million for the nine months ended September 30, 2024 related to the NGTL System Ownership Transfer

•an after-tax expense of $26 million related to a non-recurring third-party settlement in first quarter 2024

•a $16 million after-tax expense for the three and nine months ended September 30, 2024 related to Keystone XL asset disposition and termination activities

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•a $12 million after-tax charge for the three and nine months ended September 30, 2024 related to the FERC Administrative Law Judge decision on Keystone in respect of a tolling-related complaint pertaining to amounts recognized in prior periods

•a $3 million and $11 million after-tax expense for the three and nine months ended September 30, 2024 related to Focus Project costs

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

2023 results

•an after-tax impairment charge of $1,179 million and $2,017 million for the three and nine months ended September 30, 2023 related to our equity investment in Coastal GasLink Pipeline Limited Partnership (Coastal GasLink LP)

•a $48 million after-tax charge as a result of the FERC Administrative Law Judge initial decision on Keystone issued in February 2023 in respect of a tolling-related complaint pertaining to amounts recognized in prior periods, which consists of a one-time, pre-tax charge of $57 million and accrued pre-tax carrying charges of $5 million

•a $14 million and $39 million after-tax expense for the three and nine months ended September 30, 2023 related to Focus Project costs

•a $36 million after-tax accrued insurance expense recorded in second quarter 2023 related to the Milepost 14 incident

•an $11 million after-tax expense due to Liquids Pipelines business separation costs incurred in third quarter 2023 related to the spinoff Transaction

•preservation and other costs for Keystone XL pipeline project assets of $2 million and $10 million after tax for the three and nine months ended September 30, 2023

•after-tax unrealized foreign exchange gains, net, of $20 million and $11 million for the three and nine months ended September 30, 2023 on the peso-denominated intercompany loan between TCPL and TGNH

•an $80 million after-tax recovery for the nine months ended September 30, 2023 on the expected credit loss provision related to the TGNH net investment in leases and certain contract assets in Mexico.

Net income in both periods included unrealized gains and losses on our proportionate share of Bruce Power's fair value adjustment on funds invested for post-retirement benefits and derivatives related to its risk management activities, as well as unrealized gains and losses from changes in our risk management activities, all of which we exclude along with the above noted items, to arrive at comparable earnings. A reconciliation of Net income (loss) attributable to common shares to comparable earnings is shown in the following table.

8 | TC Energy Third Quarter 2024

RECONCILIATION OF NET INCOME (LOSS) ATTRIBUTABLE TO COMMON SHARES TO COMPARABLE EARNINGS

	three months ended September 30		nine months ended September 30
(millions of $, except per share amounts)	2024	2023	2024	2023
Net income (loss) attributable to common shares	1,457	(197)	3,623	1,366
Specific items (net of tax):
(Gain) loss on sale of PNGTS	(456)	—	(456)	—
(Gain) loss on sale of non-core assets	—	—	(63)	—
Expected credit loss provision on net investment in leases and certain contract assets in Mexico	4	—	(13)	(80)
Liquids Pipelines business separation costs	56	11	95	11
NGTL System ownership transfer costs	—	—	42	—
Third-party settlement	—	—	26	—
Keystone XL asset impairment charge and other	16	—	16	—
Keystone regulatory decisions	12	—	12	48
Focus Project costs	3	14	11	39
Foreign exchange (gains) losses, net – intercompany loan	52	(20)	—	(11)
Coastal GasLink impairment charge	—	1,179	—	2,017
Milepost 14 insurance expense	—	—	—	36
Keystone XL preservation and other	—	2	—	10
Bruce Power unrealized fair value adjustments	(6)	6	(5)	—
Risk management activities1	(64)	40	48	(187)
Comparable earnings	1,074	1,035	3,336	3,249
Net income (loss) per common share	$1.40	($0.19)	$3.49	$1.33
Specific items (net of tax):
(Gain) loss on sale of PNGTS	(0.44)	—	(0.44)	—
(Gain) loss on sale of non-core assets	—	—	(0.06)	—
Expected credit loss provision on net investment in leases and certain contract assets in Mexico	0.01	—	(0.01)	(0.08)
Liquids Pipelines business separation costs	0.05	0.01	0.09	0.01
NGTL System ownership transfer costs	—	—	0.04	—
Third-party settlement	—	—	0.03	—
Keystone XL asset impairment charge and other	0.01	—	0.01	—
Keystone regulatory decisions	0.01	—	0.01	0.05
Focus Project costs	—	0.01	0.01	0.04
Foreign exchange (gains) losses, net – intercompany loan	0.05	(0.02)	—	(0.01)
Coastal GasLink impairment charge	—	1.14	—	1.96
Milepost 14 insurance expense	—	—	—	0.03
Keystone XL preservation and other	—	—	—	0.01
Bruce Power unrealized fair value adjustments	—	0.01	—	—
Risk management activities	(0.06)	0.04	0.04	(0.18)
Comparable earnings per common share	$1.03	$1.00	$3.21	$3.16

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1	Risk management activities	three months ended September 30		nine months ended September 30
	(millions of $)	2024	2023	2024	2023
	U.S. Natural Gas Pipelines	(13)	36	(76)	109
	Liquids Pipelines	31	(59)	67	(54)
	Canadian Power	7	(4)	67	(25)
	U.S. Power	3	4	(8)	5
	Natural Gas Storage	33	12	(37)	73
	Foreign exchange	24	(40)	(78)	142
	Income tax attributable to risk management activities	(21)	11	17	(63)
	Total unrealized gains (losses) from risk management    activities	64	(40)	(48)	187

COMPARABLE EBITDA TO COMPARABLE EARNINGS

Comparable EBITDA represents segmented earnings (losses) adjusted for the specific items described above and excludes charges for depreciation and amortization. For further information on our reconciliation of comparable EBITDA to segmented earnings (losses) refer to the financial results section for each business segment.

	three months ended September 30		nine months ended September 30
(millions of $, except per share amounts)	2024	2023	2024	2023
Comparable EBITDA
Canadian Natural Gas Pipelines	845	781	2,537	2,301
U.S. Natural Gas Pipelines	1,002	968	3,311	3,160
Mexico Natural Gas Pipelines	265	232	765	597
Liquids Pipelines	360	398	1,095	1,078
Power and Energy Solutions	326	256	873	754
Corporate	(7)	(3)	(6)	(9)
Comparable EBITDA	2,791	2,632	8,575	7,881
Depreciation and amortization	(713)	(690)	(2,149)	(2,061)
Interest expense included in comparable earnings	(836)	(865)	(2,516)	(2,413)
Allowance for funds used during construction	210	164	551	443
Foreign exchange gains (losses), net included in comparable earnings	(33)	(25)	(41)	78
Interest income and other included in comparable earnings	61	63	207	157
Income tax (expense) recovery included in comparable earnings	(235)	(220)	(758)	(749)
Net (income) loss attributable to non-controlling interests included in comparable earnings	(145)	(1)	(457)	(18)
Preferred share dividends	(26)	(23)	(76)	(69)
Comparable earnings	1,074	1,035	3,336	3,249
Comparable earnings per common share	$1.03	$1.00	$3.21	$3.16

10 | TC Energy Third Quarter 2024

Comparable EBITDA – 2024 versus 2023

Comparable EBITDA increased by $159 million for the three months ended September 30, 2024 compared to the same period in 2023 primarily due to the net effect of the following:

•increased Power and Energy Solutions EBITDA mainly attributable to higher contributions from Bruce Power due to increased generation and a higher contract price, partially offset by lower realized power prices, net of lower natural gas fuel costs in Canadian Power and increased business development costs

•increased EBITDA in Canadian Natural Gas Pipelines mainly due to higher flow-through costs and increased rate-base earnings on the NGTL System and Foothills

•increased U.S. dollar-denominated EBITDA from Mexico Natural Gas Pipelines primarily due to higher equity earnings from Sur de Texas as a result of the impact of peso-denominated financial exposure and lower income tax expense, as well as incremental earnings from the lateral section of the Villa de Reyes pipeline which was placed in service in August 2023

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

•decreased EBITDA from Liquids Pipelines primarily due to lower margins from liquids marketing activities, partially offset by higher volumes on the U.S. Gulf Coast section of the Keystone Pipeline System

•the positive foreign exchange impact of a stronger U.S. dollar on the Canadian dollar equivalent comparable EBITDA in our U.S. dollar-denominated operations. U.S. dollar-denominated comparable EBITDA decreased by US$2 million compared to 2023 and was translated at a rate of 1.36 in 2024 versus 1.34 in 2023. Refer to the Foreign exchange section for additional information.

Comparable EBITDA increased by $694 million for the nine months ended September 30, 2024 compared to the same period in 2023 primarily due to the net effect of the following:

•increased EBITDA in Canadian Natural Gas Pipelines mainly due to higher flow-through costs and increased rate-base earnings on the NGTL System and Foothills

•increased U.S. dollar-denominated EBITDA from Mexico Natural Gas Pipelines primarily due to higher equity earnings from Sur de Texas as a result of the impact of peso-denominated financial exposure and lower income tax expense, as well as incremental earnings from the lateral section of the Villa de Reyes pipeline which was placed in service in third quarter 2023

•increased Power and Energy Solutions EBITDA mainly attributable to increased contributions from Bruce Power due to a higher contract price and increased generation, partially offset by increased operating and depreciation costs; higher realized Alberta natural gas storage spreads and higher contributions from our U.S. marketing business, partially offset by lower realized power prices, net of lower natural gas fuel costs in Canadian Power and increased business development costs

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

•increased EBITDA from Liquids Pipelines primarily due to higher volumes on the Keystone Pipeline System, partially offset by lower margins from liquids marketing activities

•the positive foreign exchange impact of a stronger U.S. dollar on the Canadian dollar equivalent comparable EBITDA in our U.S. dollar-denominated operations. U.S. dollar-denominated comparable EBITDA increased by US$204 million compared to 2023 which was translated at a rate of 1.36 in 2024 versus 1.35 in 2023. Refer to the Foreign exchange section for additional information.

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

TC Energy Third Quarter 2024 | 11

Comparable earnings – 2024 versus 2023

Comparable earnings increased by $39 million or $0.03 per common share for the three months ended September 30, 2024 compared to the same period in 2023 and was primarily the net effect of:

•changes in comparable EBITDA described above

•higher net income attributable to non-controlling interests primarily due to the sale of a 40 per cent non-controlling equity interest in Columbia Gas Transmission, LLC (Columbia Gas) and Columbia Gulf Transmission, LLC (Columbia Gulf) in fourth quarter 2023 and the CFE's 13.01 per cent non-controlling equity interest in TGNH completed in second quarter 2024

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

•higher income tax expense due to higher earnings, net of non-controlling interests, and lower foreign income tax rate differentials, partially offset by the impact of our Mexico foreign exchange exposure

•the impact of hedging activities to manage our foreign exchange exposure to net liabilities in Mexico, partially offset by the revaluation of our peso-denominated net monetary liabilities to U.S. dollars and derivatives used to manage our net exposure to foreign exchange rate fluctuations on U.S. dollar-denominated income

•higher AFUDC primarily due to spending on the Southeast Gateway pipeline project, partially offset by projects placed in service

•lower interest expense primarily due to reduced levels of short-term borrowing and higher capitalized interest, partially offset by the foreign exchange impact from a stronger U.S. dollar on translation of U.S. dollar-denominated interest expense and long-term debt issuances, net of maturities.

Comparable earnings increased by $87 million or $0.05 per common share for the nine months ended September 30, 2024 compared to the same period in 2023 primarily due to the net effect of the following:

•changes in comparable EBITDA described above

•higher net income attributable to non-controlling interests primarily due to the sale of a 40 per cent non-controlling equity interest in Columbia Gas and Columbia Gulf in fourth quarter 2023 and the CFE's 13.01 per cent non-controlling equity interest in TGNH completed in second quarter 2024

•the impact of hedging activities to manage our foreign exchange exposure to net liabilities in Mexico, partially offset by the revaluation of our peso-denominated net monetary liabilities to U.S. dollars, derivatives used to manage our net exposure to foreign exchange rate fluctuations on U.S. dollar-denominated income and a net realized gain on the partial repayment of the peso-denominated intercompany loan between TCPL and TGNH

•higher interest expense primarily due to long-term debt issuances, net of maturities and the foreign exchange impact from a stronger U.S. dollar on translation of U.S. dollar-denominated interest expense, partially offset by reduced levels of short-term borrowing and higher capitalized interest

•higher depreciation and amortization reflecting expansion facilities and new projects placed in service, and the acquisitions of Fluvanna Wind Farm and Blue Cloud Wind Farm (Texas Wind Farms) in 2023

•higher income tax expense primarily due to lower foreign income tax rate differentials and higher earnings, net of non-controlling interests, largely offset by the impact of our Mexico foreign exchange exposure and lower flow-through income taxes

•higher AFUDC primarily due to spending on the Southeast Gateway pipeline project, partially offset by projects placed in service

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

Comparable earnings per common share for the three and nine months ended September 30, 2024 reflect the dilutive effect of common shares issued in 2023.

12 | TC Energy Third Quarter 2024

Outlook

Comparable EBITDA and comparable earnings

Our overall comparable EBITDA and comparable earnings per common share outlooks for 2024 remain consistent with our 2023 Annual Report and now include the impact of the spinoff of our Liquids Pipelines business into a separate, publicly traded entity.

We continue to monitor developments in energy markets, our construction projects and regulatory proceedings for any potential impacts on our 2024 comparable EBITDA and comparable earnings per common share.

Consolidated capital expenditures

Our total capital expenditures for 2024 are now expected to be lower than the range outlined in our 2023 Annual Report as a result of advancing our capital program with continued focus on cost optimization. Prior to adjustments for non-controlling interests, we expect to incur gross capital expenditures of approximately $8.1 to $8.4 billion. We anticipate our net capital expenditures in 2024 to be approximately $7.4 to $7.7 billion after considering capital expenditures attributable to non-controlling interests of entities we control.

TC Energy Third Quarter 2024 | 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 that are expected to generate significant growth in earnings and cash flows. In addition, many of these projects are expected to advance our goals to reduce our own carbon footprint, as well as that of our customers.

Our capital program consists of approximately $31 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.

As of October 1, 2024, after the completion of the spinoff Transaction, the committed capital related to the Liquids Pipelines business is the responsibility of South Bow Corporation (South Bow) and will be removed from the Secured projects table in subsequent reporting periods. As at September 30, 2024, our capital program for our Liquids Pipelines business was approximately $0.5 billion.

During the nine months ended September 30, 2024, we placed approximately $1.2 billion of natural gas pipeline capacity projects into service along our extensive North American asset footprint. In addition, approximately $1.6 billion of maintenance capital expenditures were incurred.

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 2023 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 below. Refer to the Recent developments section for updates to our secured projects and projects under development.

14 | TC Energy Third Quarter 2024

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, primarily Coastal GasLink and Bruce Power.

	Expected in-service date	Estimated project cost	Project costs incurred at September 30, 2024
(billions of $)
Canadian Natural Gas Pipelines
NGTL System	2024	0.7	0.6
	2025	0.1	—
	2026+	1.0	0.1
Coastal GasLink Pipeline1,2	2024/2028	5.5	4.8
Regulated maintenance capital expenditures	2024-2026	2.3	0.5
U.S. Natural Gas Pipelines
Modernization and other3	2024-2026	US 1.5	US 1.1
Delivery market projects	2025	US 1.3	US 0.4
Heartland project	2027	US 0.9	—
Other capital	2024-2028	US 1.5	US 0.4
Regulated maintenance capital expenditures	2024-2026	US 2.5	US 0.7
Mexico Natural Gas Pipelines
Villa de Reyes – south section4	—	US 0.4	US 0.3
Tula5	—	US 0.4	US 0.3
Southeast Gateway	2025	US 4.0	US 3.5
Liquids Pipelines
Blackrod Connection project	2026	0.3	0.1
Recoverable maintenance capital expenditures	2024-2026	0.2	0.1
Power and Energy Solutions
Bruce Power – Unit 3 MCR	2026	1.1	0.8
Bruce Power – Unit 4 MCR	2028	0.9	0.2
Bruce Power – life extension6	2024-2027	1.8	0.9
Other
Non-recoverable maintenance capital expenditures7	2024-2026	0.5	0.1
		26.9	14.9
Foreign exchange impact on secured projects8		4.4	2.3
Total secured projects (Cdn$)		31.3	17.2

1    Mechanical completion was achieved in November 2023. Commercial in-service of the Coastal GasLink pipeline will occur after completion of plant commissioning activities at the LNG Canada facility and upon receiving notice from LNG Canada. Refer to the Recent developments – Canadian Natural Gas Pipelines section for additional information.

2    The estimated project cost represents our share of anticipated partner equity contributions to the project, including approximately $50 million for the Cedar Link project.

3    Includes 100 per cent of the capital expenditures related to our modernization program on Columbia Gas, as well as certain large-scope maintenance projects across our U.S. natural gas pipelines footprint due to their discrete nature and timing for regulatory recovery.

4    We are working with the CFE on completing the remaining section of the Villa de Reyes pipeline. The in-service date will be determined upon resolution of outstanding stakeholder issues. Refer to the Recent developments – Mexico Natural Gas Pipelines section for additional information.

5    Estimated project cost as per contracts signed in 2022 as part of the TGNH strategic alliance between TC Energy and the CFE. We continue to evaluate the development and completion of the Tula pipeline, with the CFE, subject to a future FID and updated cost estimate. Refer to the Recent developments – Mexico Natural Gas Pipelines section for additional information.

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

7    Includes non-recoverable maintenance capital expenditures from all segments and are primarily related to our Power and Energy Solutions and other assets.

8    Reflects U.S./Canada foreign exchange rate of 1.35 at September 30, 2024.

TC Energy Third Quarter 2024 | 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 $)	2024	2023	2024	2023
NGTL System	598	546	1,797	1,621
Canadian Mainline	193	199	576	578
Other Canadian pipelines1	54	36	164	102
Comparable EBITDA	845	781	2,537	2,301
Depreciation and amortization	(350)	(336)	(1,037)	(983)
Comparable EBIT	495	445	1,500	1,318
Specific items:
Gain (loss) on sale of non-core assets	—	—	10	—
Coastal GasLink impairment charge	—	(1,244)	—	(2,100)
Segmented earnings (losses)	495	(799)	1,510	(782)

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.

For the three months ended September 30, 2024, Canadian Natural Gas Pipelines segmented earnings were $495 million compared to segmented losses of $799 million for the same period in 2023. For the nine months ended September 30, 2024, Canadian Natural Gas Pipelines segmented earnings were $1,510 million compared to segmented losses of $782 million for the same period in 2023. These amounts included the following specific items which have been excluded from our calculation of comparable EBITDA and comparable EBIT:

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

•a pre-tax impairment charge of $1,244 million and $2,100 million for the three and nine months ended September 30, 2023, respectively, related to our equity investment in Coastal GasLink LP. Refer to Note 6, Coastal GasLink, of our Condensed consolidated financial statements for additional information.

Net income and comparable EBITDA for our rate-regulated Canadian natural gas pipelines are primarily affected by our approved ROE, investment base, the level of deemed common equity and incentive earnings. Changes in depreciation, financial charges and income taxes also impact comparable EBITDA, but 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 $)	2024	2023	2024	2023
Net income
NGTL System	193	191	585	572
Canadian Mainline	61	58	176	169
Average investment base
NGTL System			19,342	18,843
Canadian Mainline			3,664	3,685

16 | TC Energy Third Quarter 2024

Net income for the NGTL System increased by $2 million and $13 million for the three and nine months ended September 30, 2024 compared to the same periods in 2023 mainly due to a higher average investment base resulting from continued system expansions. The NGTL System is operating under the 2020-2024 Revenue Requirement Settlement which includes an approved ROE of 10.1 per cent on 40 per cent deemed common equity. This settlement provides the NGTL System the opportunity to increase depreciation rates if tolls fall below specified levels and an incentive mechanism for certain operating costs where variances from projected amounts are shared with our customers.

Net income for the Canadian Mainline increased by $3 million and $7 million for the three and nine months ended September 30, 2024 compared to the same periods in 2023 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 $64 million and $236 million for the three and nine months ended September 30, 2024 compared to the same periods in 2023 due to the net effect of:

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

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

DEPRECIATION AND AMORTIZATION

Depreciation and amortization increased by $14 million and $54 million for the three and nine months ended September 30, 2024 compared to the same periods in 2023, primarily reflecting incremental depreciation on the NGTL System from expansion facilities that were placed in service.

TC Energy Third Quarter 2024 | 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$, unless otherwise noted)	2024	2023	2024	2023
Columbia Gas1	372	359	1,176	1,113
ANR	138	147	464	473
Columbia Gulf1	57	49	178	157
Great Lakes	38	38	148	123
GTN	44	54	138	154
Portland1,2	14	23	66	77
Other U.S. pipelines3	71	52	265	251
Comparable EBITDA	734	722	2,435	2,348
Depreciation and amortization	(169)	(167)	(522)	(516)
Comparable EBIT	565	555	1,913	1,832
Foreign exchange impact	206	191	688	635
Comparable EBIT (Cdn$)	771	746	2,601	2,467
Specific items:
Gain (loss) on sale of PNGTS	572	—	572	—
Gain (loss) on sale of non-core assets	—	—	38	—
Risk management activities	(13)	36	(76)	109
Segmented earnings (losses) (Cdn$)	1,330	782	3,135	2,576

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

2The sale of PNGTS was completed on August 15, 2024. Refer to the Recent developments – U.S. Natural Gas Pipelines section for additional information.

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 increased by $548 million and $559 million for the three and nine months ended September 30, 2024 compared to the same periods in 2023 and included the following specific items which have been excluded from our calculation of comparable EBITDA and comparable EBIT:

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

•a pre-tax gain on the 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, 2024 had a positive impact on the Canadian dollar equivalent segmented earnings from our U.S. dollar-denominated operations compared to the same periods in 2023. 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 2024

Comparable EBITDA for U.S. Natural Gas Pipelines increased by US$12 million and US$87 million for the three and nine months ended September 30, 2024 compared to the same periods in 2023 and was primarily due to the net effect of:

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

•increased equity earnings from Iroquois and Northern Border

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

•decreased earnings as a result of the sale of PNGTS, which was completed on August 15, 2024.

DEPRECIATION AND AMORTIZATION

Depreciation and amortization increased by US$2 million and US$6 million for the three and nine months ended September 30, 2024 compared to the same periods in 2023 due to new projects placed in service.

TC Energy Third Quarter 2024 | 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$, unless otherwise noted)	2024	2023	2024	2023
TGNH1,2	62	58	186	171
Topolobampo	40	40	118	119
Guadalajara	14	16	44	49
Mazatlán	17	21	51	54
Sur de Texas3	62	38	164	50
Comparable EBITDA	195	173	563	443
Depreciation and amortization	(17)	(17)	(51)	(50)
Comparable EBIT	178	156	512	393
Foreign exchange impact	64	53	184	137
Comparable EBIT (Cdn$)	242	209	696	530
Specific item:
Expected credit loss provision on net investment in leases and certain contract assets in Mexico2	(5)	1	19	116
Segmented earnings (losses) (Cdn$)	237	210	715	646

1TGNH includes the operating sections of the Tamazunchale, Villa de Reyes and Tula 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 $27 million and $69 million for the three and nine months ended September 30, 2024 compared to the same periods in 2023 and included an unrealized loss of $5 million and an unrealized recovery of $19 million, respectively (2023 – recovery of $1 million and $116 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. Refer to Note 13, Risk management and financial instruments, of our Condensed consolidated financial statements for additional information.

A stronger U.S. dollar for the three and nine months ended September 30, 2024 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 2023. Refer to the Foreign exchange section for additional information.

Comparable EBITDA for Mexico Natural Gas Pipelines increased by US$22 million and US$120 million for the three and nine months ended September 30, 2024 compared to the same periods in 2023 due to the net effect of:

•higher equity earnings primarily due to the foreign exchange impacts on the revaluation of peso-denominated liabilities as a result of a weaker Mexican peso and lower income tax expense. 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

•higher earnings in TGNH primarily related to the lateral section of the Villa de Reyes pipeline which was placed in commercial service in third quarter 2023.

DEPRECIATION AND AMORTIZATION

Depreciation and amortization was generally consistent for the three and nine months ended September 30, 2024 compared to the same periods in 2023.

20 | TC Energy Third Quarter 2024

Liquids 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 $)	2024	2023	2024	2023
Keystone Pipeline System	344	379	1,048	1,028
Intra-Alberta pipelines1	18	18	52	53
Other	(2)	1	(5)	(3)
Comparable EBITDA	360	398	1,095	1,078
Depreciation and amortization	(87)	(83)	(258)	(252)
Comparable EBIT	273	315	837	826
Specific items:
Liquids Pipelines business separation costs	(28)	—	(42)	—
Keystone XL asset impairment charge and other	(21)	—	(21)	—
Keystone regulatory decisions	(15)	—	(15)	(57)
Keystone XL preservation and other	—	(3)	—	(13)
Risk management activities	31	(59)	67	(54)
Segmented earnings (losses)	240	253	826	702
Comparable EBITDA denominated as follows:
Canadian dollars	100	97	294	282
U.S. dollars	190	226	589	592
Foreign exchange impact	70	75	212	204
Comparable EBITDA	360	398	1,095	1,078

1Intra-Alberta pipelines include Grand Rapids and White Spruce.

Liquids Pipelines segmented earnings decreased by $13 million and increased by $124 million for the three and nine months ended September 30, 2024 compared to the same periods in 2023 and included the following specific items which have been excluded from our calculation of comparable EBITDA and comparable EBIT:

•a pre-tax charge of $28 million and $42 million for the three and nine months ended September 30, 2024 (2023 – nil) incurred due to Liquids Pipelines business separation costs related to the spinoff Transaction. Refer to the Recent developments – Liquids Pipelines section for additional information

•a $21 million pre-tax expense for the three and nine months ended September 30, 2024 related to Keystone XL asset disposition and termination activities

•a pre-tax charge of $15 million for the three and nine months ended September 30, 2024 (2023 – nil and $57 million, respectively) as a result of the FERC Administrative Law Judge decision on Keystone in respect of a tolling-related complaint pertaining to amounts recognized in prior periods

•pre-tax preservation and other costs of $3 million and $13 million for the three and nine months ended September 30, 2023 related to the preservation and storage of the Keystone XL pipeline project assets

•unrealized gains and losses from changes in the fair value of derivatives related to our liquids marketing business.

A stronger U.S. dollar for the three and nine months ended September 30, 2024 had a positive impact on the Canadian dollar equivalent segmented earnings from our U.S. operations compared to the same periods in 2023. Refer to the Foreign exchange section for additional information.

TC Energy Third Quarter 2024 | 21

Comparable EBITDA for Liquids Pipelines decreased by $38 million and increased by $17 million for the three and nine months ended September 30, 2024 compared to the same periods in 2023 primarily due to the net effect of:

•lower margins from liquids marketing activities due to the commencement of incremental WCSB egress capacity

•lower uncontracted volumes on the Keystone Pipeline System in third quarter 2024 compared to the same period in 2023

•higher uncontracted volumes for the nine months ended September 30, 2024 compared to the same period in 2023 as a result of Milepost 14 incident-related capacity impacts in 2023

•higher throughput on the U.S. Gulf Coast section of the Keystone Pipeline System driven by an increase in contracted volumes.

DEPRECIATION AND AMORTIZATION

Depreciation and amortization increased by $4 million and $6 million for the three and nine months ended September 30, 2024 compared to the same periods in 2023 primarily as a result of a stronger U.S. dollar.

22 | TC Energy Third Quarter 2024

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 $)	2024	2023	2024	2023
Bruce Power1	282	178	613	512
Canadian Power	51	74	219	256
Natural Gas Storage and other2	(7)	4	41	(14)
Comparable EBITDA	326	256	873	754
Depreciation and amortization	(22)	(26)	(75)	(66)
Comparable EBIT	304	230	798	688
Specific items:
Bruce Power unrealized fair value adjustments	7	(8)	6	—
Risk management activities	43	12	22	53
Segmented earnings (losses)	354	234	826	741

1Represents our share of equity income from Bruce Power.

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

Power and Energy Solutions segmented earnings increased by $120 million and $85 million for the three and nine months ended September 30, 2024 compared to the same periods in 2023 and included the following specific items which have been excluded from our calculation of comparable EBITDA and comparable EBIT:

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

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

Comparable EBITDA for Power and Energy Solutions increased by $70 million and $119 million for the three and nine months ended September 30, 2024 compared to the same periods in 2023 primarily due to the net effect of:

•improved contributions from Bruce Power primarily due to a higher contract price and increased generation, partially offset by increased operating and depreciation costs. Refer to the Bruce Power section for additional information

•decreased Canadian Power financial results primarily from lower realized power prices, net of lower natural gas fuel costs, partially offset by higher contributions from trading activities in second quarter 2024

•decreased Natural Gas Storage and other results for the three months ended September 30, 2024 primarily due to increased business development costs. Increased financial results for the nine months ended September 30, 2024 were the result of higher realized Alberta natural gas storage spreads and higher contributions from our U.S. marketing business, partially offset by increased business development costs.

DEPRECIATION AND AMORTIZATION

Depreciation and amortization decreased by $4 million for the three months ended September 30, 2024 due to revised assumptions for the useful lives of our Texas Wind Farms in 2024 and increased by $9 million for the nine months ended September 30, 2024 compared to the same periods in 2023 primarily due to the acquisition of the Texas Wind Farms in the first half of 2023.

TC Energy Third Quarter 2024 | 23

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)	2024		2023		2024		2023
Items included in comparable EBITDA and comparable EBIT are comprised of:
Revenues1	608		474		1,620		1,453
Operating expenses	(233)		(211)		(730)		(686)
Depreciation and other	(93)		(85)		(277)		(255)
Comparable EBITDA and comparable EBIT2	282		178		613		512
Bruce Power – other information
Plant availability3,4	98	%	94	%	89	%	94	%
Planned outage days4	—		15		160		28
Unplanned outage days	8		9		29		47
Sales volumes (GWh)5	5,926		5,060		16,152		15,301
Realized power price per MWh6	$102		$92		$100		$94

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

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

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

4Excludes MCR outage days.

5Sales volumes include deemed generation, if applicable.

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

Bruce Power's 2024 planned maintenance, excluding the MCR program, was completed in second quarter.

24 | TC Energy Third Quarter 2024

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 $)	2024	2023	2024	2023
Comparable EBITDA and EBIT	(7)	(3)	(6)	(9)
Specific items:
Liquids Pipelines business separation costs	(25)	(15)	(56)	(15)
Third-party settlement	—	—	(34)	—
Focus Project costs	(5)	(18)	(15)	(50)
NGTL System ownership transfer costs	—	—	(10)	—
Segmented earnings (losses)	(37)	(36)	(121)	(74)

Corporate segmented losses were consistent for the three months ended September 30, 2024 and increased by $47 million for the nine months ended September 30, 2024 compared to the same periods in 2023. Corporate segmented losses included the following specific items, which have been excluded from our calculation of comparable EBITDA and comparable EBIT:

•a pre-tax charge of $25 million and $56 million for the three and nine months ended September 30, 2024      (2023 – $15 million and $15 million, respectively) from Liquids Pipelines business separation costs related to the spinoff Transaction. Refer to the Recent developments – Liquids Pipelines section for additional information

•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 (2023 – $18 million and $50 million, respectively) related to Focus Project costs. Refer to the Recent developments – Corporate section for additional information

•a pre-tax charge of $10 million in second quarter 2024 related to the NGTL System Ownership Transfer. Refer to the Recent developments – Corporate section for additional information.

Comparable EBITDA and comparable EBIT for Corporate decreased by $4 million and increased by $3 million for the three and nine months ended September 30, 2024 compared to the same periods in 2023, primarily due to higher litigation expenses in 2024, partially offset by U.S. state tax refunds in second quarter 2024.

INTEREST EXPENSE

	three months ended September 30		nine months ended September 30
(millions of $)	2024	2023	2024	2023
Interest expense on long-term debt and junior subordinated notes
Canadian dollar-denominated	(211)	(227)	(656)	(668)
U.S. dollar-denominated	(471)	(458)	(1,415)	(1,219)
Foreign exchange impact	(172)	(157)	(510)	(421)
	(854)	(842)	(2,581)	(2,308)
Other interest and amortization expense	(48)	(76)	(135)	(230)
Capitalized interest	66	53	200	125
Interest expense included in comparable earnings	(836)	(865)	(2,516)	(2,413)
Specific items:
Liquids Pipelines business separation costs	(42)	—	(42)	—
Keystone regulatory decisions	—	—	—	(5)
Interest expense	(878)	(865)	(2,558)	(2,418)

TC Energy Third Quarter 2024 | 25

Interest expense increased by $13 million and $140 million for the three and nine months ended September 30, 2024 compared to the same periods in 2023 and included the following specific items, which have been excluded from our calculation of comparable EBITDA and comparable EBIT:

•pre-tax Liquids Pipelines business separation costs of $42 million for the three and nine months ended September 30, 2024 related to interest expense from the South Bow debt issuance on August 28, 2024

•carrying charges of $5 million for the nine months ended September 30, 2023 related to a pre-tax charge resulting from the FERC Administrative Law Judge decision on Keystone in respect of a tolling-related complaint pertaining to amounts recognized in prior periods.

Interest expense included in comparable earnings decreased by $29 million and increased by $103 million for the three and nine months ended September 30, 2024 compared to the same periods in 2023 primarily due to the net effect of:

•long-term debt issuances, net of maturities. Refer to 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

•reduced levels of short-term borrowing

•higher capitalized interest, largely due to funding related to our investment in Coastal GasLink LP.

ALLOWANCE FOR FUNDS USED DURING CONSTRUCTION

	three months ended September 30		nine months ended September 30
(millions of $)	2024	2023	2024	2023
Canadian dollar-denominated	8	28	25	81
U.S. dollar-denominated	149	102	387	269
Foreign exchange impact	53	34	139	93
Allowance for funds used during construction	210	164	551	443

AFUDC increased by $46 million and $108 million for the three and nine months ended September 30, 2024 compared to the same periods in 2023. The decrease in Canadian dollar-denominated AFUDC is primarily related to NGTL System expansion projects placed in service during 2023. The increase in U.S. dollar-denominated AFUDC is mainly the result of capital expenditures on the Southeast Gateway pipeline project, partially offset by the suspension of AFUDC on the assets under construction for the Tula pipeline project due to the delay of an FID and placing the lateral section of Villa de Reyes pipeline in service in August 2023.

FOREIGN EXCHANGE GAINS (LOSSES), NET

	three months ended September 30		nine months ended September 30
(millions of $)	2024	2023	2024	2023
Foreign exchange gains (losses), net included in comparable earnings	(33)	(25)	(41)	78
Specific items:
Foreign exchange gains (losses), net – intercompany loan1	(29)	20	41	11
Risk management activities	24	(40)	(78)	142
Foreign exchange gains (losses), net	(38)	(45)	(78)	231

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

26 | TC Energy Third Quarter 2024

Foreign exchange losses, net, were $38 million and $78 million for the three and nine months ended September 30, 2024 compared to foreign exchange losses, net, of $45 million and foreign exchange gains, net, of $231 million in the same periods in 2023. The following specific items have been removed from our calculation of Foreign exchange gains (losses), net, included in comparable earnings:

•unrealized foreign exchange gains and losses on the peso-denominated intercompany loan between TCPL and TGNH

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

Foreign exchange losses, net, included in comparable earnings were $33 million for the three months ended September 30, 2024 compared to $25 million in the same period in 2023. The changes were primarily due to the net effect of:

•higher realized losses on derivatives used to manage our foreign exchange exposure to net liabilities in Mexico

•higher foreign exchange gains on the revaluation of our peso-denominated net monetary liabilities to U.S. dollars

•lower net realized losses on derivatives used to manage our net exposure to foreign exchange rate fluctuation on U.S. dollar‑denominated income.

Foreign exchange losses, net, included in comparable earnings were $41 million for the nine months ended September 30, 2024 compared to foreign exchange gains, net, of $78 million in the same period in 2023. The changes were primarily due to the net effect of:

•realized losses in 2024 compared to realized gains in 2023 on derivatives used to manage our foreign exchange exposure to net liabilities in Mexico

•foreign exchange gains in 2024 compared to foreign exchange losses in 2023 on the revaluation of our peso-denominated net monetary liabilities to U.S. dollars

•lower net realized losses on derivatives used to manage our net exposure to foreign exchange rate fluctuation on U.S. dollar‑denominated income

•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 $)	2024	2023	2024	2023
Interest income and other included in comparable earnings	61	63	207	157
Specific items:
Liquids Pipelines business separation costs	28	—	28	—
Milepost 14 insurance expense	—	—	—	(36)
Interest income and other	89	63	235	121

Interest income and other increased by $26 million and $114 million for the three and nine months ended September 30, 2024 compared to the same periods in 2023. The following specific items have been removed from our calculation of Interest income and other included in comparable earnings:

•pre-tax interest income of $28 million for the three and nine months ended September 30, 2024 on proceeds from the South Bow debt issuance on August 28, 2024, which were held in escrow

•a $36 million after-tax accrued insurance expense recorded in second quarter 2023 related to the Milepost 14 incident.

Interest income and other included in comparable earnings decreased by $2 million and increased by $50 million for the three and nine months ended September 30, 2024 compared to the same periods in 2023 due to higher interest earned on     short-term investments and the change in fair value of other restricted investments.

TC Energy Third Quarter 2024 | 27

INCOME TAX (EXPENSE) RECOVERY

	three months ended September 30		nine months ended September 30
(millions of $)	2024	2023	2024	2023
Income tax (expense) recovery included in comparable earnings	(235)	(220)	(758)	(749)
Specific items:
Gain (loss) on sale of PNGTS	(116)	—	(116)	—
Gain (loss) on sale of non-core assets	—	—	15	—
Expected credit loss provision on net investment in leases and certain contract assets in Mexico	1	(1)	(6)	(36)
Liquids Pipelines business separation costs	11	4	17	4
NGTL System ownership transfer costs	—	—	(32)	—
Third-party settlement	—	—	8	—
Keystone XL asset impairment charge and other	5	—	5	—
Keystone regulatory decisions	3	—	3	14
Focus Project costs	2	4	4	11
Coastal GasLink impairment charge	—	65	—	83
Keystone XL preservation and other	—	1	—	3
Bruce Power unrealized fair value adjustments	(1)	2	(1)	—
Risk management activities	(21)	11	17	(63)
Income tax (expense) recovery	(351)	(134)	(844)	(733)

Income tax expense increased by $217 million and $111 million for the three and nine months ended September 30, 2024 compared to the same periods in 2023. 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 $15 million for the three months ended September 30, 2024 compared to the same period in 2023 primarily due to higher earnings, net of non-controlling interests and lower foreign income tax rate differentials, partially offset by the impact of our Mexico foreign exchange exposure.

Income tax expense included in comparable earnings increased by $9 million for the nine months ended September 30, 2024 compared to the same period in 2023 primarily due to lower foreign income tax rate differentials and higher earnings, net of non-controlling interests, largely offset by the impact of our Mexico foreign exchange exposure and lower flow-through income taxes.

28 | TC Energy Third Quarter 2024

NET (INCOME) LOSS ATTRIBUTABLE TO NON-CONTROLLING INTERESTS

	Non-Controlling Interests Ownership at  September 30, 2024		three months ended September 30		nine months ended September 30
(millions of $)			2024	2023	2024	2023
Columbia Gas and Columbia Gulf	40.0	%	(126)	—	(416)	—
Portland Natural Gas Transmission System1	—		(7)	(9)	(30)	(30)
Texas Wind Farms2	—		9	8	20	12
TGNH3	13.01	%	(21)	—	(31)	—
Net (income) loss attributable to non-controlling interests included in comparable earnings			(145)	(1)	(457)	(18)
Specific item:
Foreign exchange (gains) losses, net – intercompany loan	13.01	%	(23)	—	(41)	—
Net (income) loss attributable to non-controlling interests			(168)	(1)	(498)	(18)

1    The sale of PNGTS was completed on August 15, 2024. Refer to the Recent developments – U.S. Natural Gas Pipelines section for additional information.

2    Tax equity investors own 100 per cent of the Class A Membership Interests, to which a percentage of earnings, tax attributes and cash flows are allocated. We own 100 per cent of the Class B Membership Interests.

3    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.

Net income attributable to non-controlling interests increased by $167 million and $480 million for the three and nine months ended September 30, 2024 compared to the same periods in 2023 and includes the non-controlling interest portion of the unrealized foreign exchange gains and losses on the TGNH peso-denominated intercompany loan payable to TCPL, which has been removed from our calculation of Net (income) loss attributable to non-controlling interests included in comparable earnings.

Net income attributable to non-controlling interests included in comparable earnings increased by $144 million and     $439 million for the three and nine months ended September 30, 2024 compared to the same periods in 2023 primarily due to the sale of a 40 per cent non-controlling equity interest in Columbia Gas and Columbia Gulf to Global Infrastructure Partners in fourth quarter 2023 and the 13.01 per cent non-controlling equity interest in TGNH to the CFE, which was completed in second quarter 2024.

PREFERRED SHARE DIVIDENDS

	three months ended September 30		nine months ended September 30
(millions of $)	2024	2023	2024	2023
Preferred share dividends	(26)	(23)	(76)	(69)

Preferred share dividends increased by $3 million and $7 million for the three and nine months ended September 30, 2024 compared to the same periods in 2023 primarily due to the dividend rate reset on Series 7 preferred shares on April 30, 2024.

TC Energy Third Quarter 2024 | 29

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 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, 2024 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, which include our U.S. and Mexico Natural Gas Pipelines operations, along with the majority of our Liquids Pipelines business.

PRE-TAX U.S. DOLLAR-DENOMINATED INCOME AND EXPENSE ITEMS

	three months ended September 30		nine months ended September 30
(millions of US$)	2024	2023	2024	2023
Comparable EBITDA
U.S. Natural Gas Pipelines	734	722	2,435	2,348
Mexico Natural Gas Pipelines	195	173	563	443
Liquids Pipelines	190	226	589	592
	1,119	1,121	3,587	3,383
Depreciation and amortization	(235)	(233)	(721)	(713)
Interest expense on long-term debt and junior subordinated notes	(471)	(458)	(1,415)	(1,219)
Allowance for funds used during construction	149	102	387	269
Net (income) loss attributable to non-controlling interests included in comparable earnings and other	(118)	(20)	(356)	(64)
	444	512	1,482	1,656
Average exchange rate – U.S. to Canadian dollars	1.36	1.34	1.36	1.35

FOREIGN EXCHANGE RELATED TO MEXICO NATURAL GAS PIPELINES

Changes in the value of the Mexican peso against the U.S. dollar can affect our comparable earnings as a portion of our Mexico Natural Gas Pipelines monetary assets and liabilities are peso-denominated, while our financial results are denominated in U.S. dollars for our Mexico operations. These peso-denominated balances are revalued to U.S. dollars, creating foreign exchange gains and losses that are included in Income (loss) from equity investments, Foreign exchange (gains) losses, net and Net income (loss) attributable to non-controlling interests in the Condensed consolidated statement of income.

In addition, foreign exchange gains or losses calculated for Mexico income tax purposes on the revaluation of U.S. dollar‑denominated monetary assets and liabilities result in a peso-denominated income tax exposure for these entities, leading to fluctuations in Income from equity investments and Income tax expense. This exposure increases as our U.S. dollar‑denominated net monetary liabilities grow.

The above exposures are managed using foreign exchange derivatives, although some unhedged exposure remains. The impacts of the foreign exchange derivatives are recorded in Foreign exchange (gains) losses, net, in the Condensed consolidated statement of income. Refer to the Financial risks and financial instruments section for additional information.

30 | TC Energy Third Quarter 2024

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

September 30, 2024	19.70
September 30, 2023	17.42
December 31, 2023	16.91
December 31, 2022	19.50

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 $)	2024	2023	2024	2023
Comparable EBITDA - Mexico Natural Gas Pipelines1	40	7	85	(67)
Foreign exchange gains (losses), net included in comparable earnings	(31)	(12)	(32)	160
Income tax (expense) recovery included in comparable earnings	43	18	83	(95)
Net (income) loss attributable to non-controlling interests included in comparable earnings2	(4)	—	(8)	—
	48	13	128	(2)

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

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

TC Energy Third Quarter 2024 | 31

Recent developments

CANADIAN NATURAL GAS PIPELINES

NGTL System

In the nine months ended September 30, 2024, the NGTL System placed approximately $0.5 billion of capacity projects in service.

2023 NGTL System Intra-Basin Expansion

The NGTL System Intra-Basin Expansion consists of new pipeline and compressor stations and is underpinned by new firm-service contracts with 15-year terms. All assets have been placed in service, with a capital cost for the expansion of $0.5 billion.

NGTL System Revenue Requirement Settlement and Multi-Year Growth Plan

On September 26, 2024, the CER approved the five-year negotiated revenue requirement settlement commencing on January 1, 2025.

The settlement enables an investment framework that supports our Board of Directors' approval to allocate approximately $3.3 billion of capital towards progression of a new multi-year growth plan for expansion facilities on the NGTL System. It is comprised of multiple distinct projects with targeted in-service dates between 2027 and 2030 that are subject to final company and regulatory approvals. The completion of the multi-year growth plan is expected to enable approximately 1.0 Bcf/d of incremental system throughput.

The settlement maintains an ROE of 10.1 per cent on 40 per cent deemed common equity while increasing NGTL System depreciation rates, with an incentive that allows the NGTL System the opportunity to further increase depreciation rates if tolls fall below specified levels, or if growth projects are undertaken. The settlement introduces a new incentive mechanism to reduce both physical emissions and emissions compliance costs, which builds on the incentive mechanism for certain operating costs where variances from projected amounts and emissions savings are shared with our customers. A provision for review exists in the settlement if tolls exceed a pre-determined level or if final company approvals of the multi-year growth plan are not obtained.

Sale of Equity Interest in the NGTL System and Foothills Pipeline Assets

On July 30, 2024, we announced that we entered into an agreement to sell a 5.34 per cent minority equity interest in the NGTL System and the Foothills Pipeline assets to an Indigenous-owned investment partnership for a gross purchase price of $1.0 billion.

On September 10, 2024, we announced that the equity interest purchase transaction has been delayed due to an identified transaction structuring issue within the NGTL partnership. We will provide more information in the event a revised transaction is entered into between the parties.

32 | TC Energy Third Quarter 2024

Coastal GasLink

Coastal GasLink Pipeline

Post-construction reclamation activities remain underway and are expected to continue into 2025. The project remains on track with its cost estimate of approximately $14.5 billion. Commercial in-service of the Coastal GasLink pipeline will occur after completion of plant commissioning activities at the LNG Canada facility and upon receiving notice from LNG Canada.

Coastal GasLink LP continues to pursue cost recovery, including certain arbitration proceedings which involve claims by, and the defense of certain claims against, Coastal GasLink LP. With the exception of settlements made with respect to certain contractor disputes, including with SA Energy Group, these claims have not yet been conclusively determined, but our expectation is that these proceedings are likely to result in net cost recoveries. Refer to Note 15, Commitments, contingencies and guarantees, of our Condensed consolidated financial statements for additional information.

In June 2024, Coastal GasLink LP successfully completed a $7.15 billion refinancing of its existing construction credit facility through a private bond offering of senior secured notes to Canadian and U.S. investors. Proceeds from the offering were used to repay the majority of the outstanding $8.0 billion balance on Coastal GasLink LP’s construction credit facility. The remaining balance on the credit facility was settled through the use of proceeds from the unwinding of interest rate swap agreements associated with hedging the underlying interest rate exposure.

Cedar Link

In June 2024, Coastal GasLink LP sanctioned the Cedar Link project following an announcement by Cedar LNG joint venture partners, Haisla Nation and Pembina Pipeline Corporation, of a positive FID for the construction of the Cedar LNG project, a proposed floating liquefied natural gas facility to be constructed in Kitimat, B.C.

The Cedar Link project is an expansion of the Coastal GasLink pipeline that is expected to enable delivery of up to 0.4 Bcf/d of natural gas to the Cedar LNG facility. With an estimated cost of $1.2 billion, the expansion project includes the addition of a new compressor station, connector pipeline and meter station to Coastal GasLink’s existing pipeline infrastructure.

Funding for the expansion will be provided through project-level credit facilities of up to $1.4 billion secured by Coastal GasLink LP in June 2024, equity funding to be provided by Coastal GasLink LP partners, including us, and the recovery of construction carrying costs from LNG Canada participants who have elected to make payments on a quarterly basis throughout construction. The incremental funds available through the project-level credit facilities and cash AFUDC payments provide additional contingency to mitigate future funding requirements for Coastal GasLink LP should costs exceed initial estimates of $1.2 billion. We estimate our share of equity contributions required to fund the Cedar Link project will be approximately $50 million. All major regulatory permits have been received and construction began in July 2024. The planned in-service date for the Cedar Link project is 2028, subject to the completion of plant commissioning activities at the Cedar LNG facility.

TC Energy Third Quarter 2024 | 33

U.S. NATURAL GAS PIPELINES

Portland Natural Gas Transmission System

On March 4, 2024, we announced that TC Energy and its partner Northern New England Investment Company, Inc., a subsidiary of Énergir L.P. (Énergir), entered into a purchase and sale agreement to sell PNGTS to BlackRock, through a fund managed by its Diversified Infrastructure business, and investment funds managed by Morgan Stanley Infrastructure Partners (the Purchaser). On August 15, 2024, we completed the sale of PNGTS for a gross purchase price of approximately $1.6 billion (US$1.1 billion), which included US$250 million of senior notes outstanding held at PNGTS and assumed by the Purchaser. A pre-tax gain of $572 million (US$408 million) and an after-tax gain of $456 million (US$323 million) were recognized for the three and nine months ended September 30, 2024. We are providing customary transition services and will continue to work jointly with the Purchaser to facilitate the safe and orderly transition of this critical natural gas system. Refer to Note 14, Strategic alliance and disposition, of our Condensed consolidated financial statements for additional information.

Gillis Access Project

In March 2024, the Gillis Access project, a 68 km (42 mile) greenfield pipeline system that connects gas production sourced from the Gillis hub to downstream markets in southeast Louisiana, was placed in service. The capital cost of this project was approximately US$0.3 billion.

In February 2023, we approved the 63 km (39 mile), 1.4 Bcf/d extension of the Gillis Access project to further connect supplies from Haynesville basin at Gillis. Effective September 1, 2024, all remaining shipper conditions have expired and the project expanded to 1.9 Bcf/d. The project has anticipated in-service dates starting in late 2026 and total estimated costs of US$0.4 billion.

Columbia Gas Section 4 Rate Case

In September 2024, Columbia Gas filed a Section 4 Rate Case with FERC requesting an increase to the maximum transportation rates expected to become effective April 1, 2025, subject to refund. We will pursue a collaborative process to find a mutually beneficial outcome with our customers through settlement.

MEXICO NATURAL GAS PIPELINES

TGNH Strategic Alliance with the CFE

In 2022, we announced a strategic alliance with Mexico’s state-owned electric utility, the CFE, and we reached an FID to develop and construct the Southeast Gateway pipeline, a 1.3 Bcf/d, 715 km (444 mile) offshore natural gas pipeline to serve the southeast region of Mexico. Construction of the project continues, with the completion of the remaining shallow water pipe installation and landfall construction targeted for fourth quarter 2024. The project remains on track to achieve commercial in-service no later than mid-2025, with current estimated project costs trending to approximately US$4.0 billion, which is lower than the initial cost estimate of US$4.5 billion.

We continue to work with our partner, the CFE, to complete the south section of the Villa de Reyes pipeline. The in-service date will be determined upon resolution of outstanding stakeholder issues. Additionally, we continue to evaluate the development and completion of the Tula pipeline with the CFE, which is subject to a future FID. Due to the delay of an FID, recording AFUDC on the assets under construction for the Tula pipeline project was suspended in late 2023.

In accordance with the terms of our strategic alliance, 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 in TGNH. Provided that the CFE's contractual commitments are met related to land acquisition, community relations and permitting support, the CFE's equity in TGNH would build up to a maximum of 15 per cent upon the in-service of the Southeast Gateway pipeline. Refer to Note 14, Strategic alliance and disposition, of our Condensed consolidated financial statements for additional information.

34 | TC Energy Third Quarter 2024

LIQUIDS PIPELINES

Spinoff of Liquids Pipelines Business

On October 1, 2024, we completed the spinoff of our Liquids Pipelines business into a separate, publicly traded entity, South Bow Corporation. Common shareholders of TC Energy retained their interest in TC Energy and received 0.2 of a South Bow common share for each TC Energy common share held. South Bow's common shares commenced regular way trading on the TSX on October 2, 2024, and on the NYSE on October 8, 2024, under the ticker symbol SOBO. Refer to Note 3, Spinoff of Liquids Pipelines business, of our Condensed consolidated financial statements for additional information.

We have incurred pre-tax Liquids Pipelines business separation costs related to the spinoff Transaction of $67 million     ($56 million after tax) and $112 million ($95 million after tax) for the three and nine months ended September 30, 2024, respectively, of which, separation costs of $28 million and $42 million, respectively, were included in the results of our Liquids Pipelines business segment and $25 million and $56 million, respectively, were included in the Corporate segment. For the three and nine months ended September 30, 2024, $42 million of interest expense and $28 million of interest income were included in the Corporate segment related to senior unsecured notes and junior subordinated notes issued on August 28, 2024 to establish South Bow's debt capital structure, the net proceeds of which were placed in escrow pending the completion of the spinoff Transaction. These costs have been excluded from comparable measures.

TC Energy and South Bow entered into a Separation Agreement setting forth the terms of the separation of the Liquids Pipelines business from the business of TC Energy, including the transfer of certain assets related to the Liquids Pipelines business from TC Energy to South Bow and the allocation of certain liabilities and obligations related to the Liquids Pipelines business between TC Energy and South Bow. The Separation Agreement provides, among other things, that TC Energy will indemnify South Bow for 86 per cent of total net liabilities and costs associated with the Milepost 14 incident and the existing variable toll disputes on the Keystone Pipeline System (excluding any future impacts to the variable toll after October 1, 2024) subject to a maximum liability to South Bow of $30 million, in aggregate, for those two matters. Any amounts that may ultimately be payable in respect of these net liabilities and costs above the current accrued amount are indeterminable at this time. As part of the Separation Agreement, any insurance recoveries related to the Milepost 14 incident will remain with TC Energy.

Upon completion of the spinoff Transaction, for reporting periods subsequent to October 1, 2024, the Liquids Pipelines business will be reported as discontinued operations.

Blackrod Connection Project

Supported by long-term committed contracts, the Liquids Pipelines business is developing the Blackrod Connection project, which will consist of a 25 km (16 mile) crude oil pipeline and a 25 km (16 mile) natural gas lateral; and associated facilities to provide crude oil transportation from International Petroleum Corporation’s Blackrod project to the Grand Rapids Pipeline System. The expected total capital cost of the project is approximately $0.3 billion with a targeted in-service date of early 2026. As of October 1, 2024, after the completion of the spinoff Transaction, the committed capital related to the Blackrod Connection project is the responsibility of South Bow.

FERC Order on Initial Decision

In 2019 and 2020, three Keystone customers initiated complaints before FERC and the CER regarding certain costs within the variable toll calculation. In February 2023, FERC released its initial decision in respect of the complaint, which addressed previously charged tolls recognized in prior periods. On July 25, 2024, FERC released its Order on Initial Decision (Order) in respect of the complaint. For the three and nine months ended September 30, 2024, we recognized an additional $15 million pre-tax charge (2023 – nil and $57 million, respectively) with respect to the decision, which has been excluded from comparable EBITDA and comparable EBIT. On October 8, 2024, South Bow submitted a compliance filing, which is subject to final FERC approval. Subsequent rulings, if any, will be subject to the indemnity provisions as outlined in the Separation Agreement.

TC Energy Third Quarter 2024 | 35

NAFTA Claim Request for Arbitration

In 2021, TC Energy filed a Request for Arbitration to formally initiate a legacy North American Free Trade Agreement (NAFTA) claim to recover economic damages resulting from the revocation of the Presidential Permit for the Keystone XL pipeline project. The U.S. objected on the basis that the transition provisions under the United States-Mexico-Canada Agreement (USMCA) that protect investments made while NAFTA was in force apply only in connection with actions taken before July 1, 2020, when USMCA replaced NAFTA. The arbitral Tribunal adjudicating the claim issued a split decision on July 12, 2024, in which the majority of the panel agreed with the U.S. position and concluded that it did not have jurisdiction to hear TC Energy’s claim. After assessing the decision and available options to challenge it, TC Energy concluded that, while we continue to believe in the validity of the claim and believe the arbitral Tribunal’s decision to be incorrect, there is no viable path forward for the claim within the rules of the investor/state dispute resolution process under USMCA. Accordingly, no further action will be taken. This decision effectively ends TC Energy’s claim.

CORPORATE

NGTL System Ownership Transfer

On April 1, 2024, ownership of the NGTL System was transferred from Nova Gas Transmission Ltd. to NGTL GP Ltd. on behalf of NGTL Limited Partnership as part of an ordinary course corporate reorganization to support business optimization and facilitate future minority ownership of the NGTL System, including participation from Indigenous groups. Refer to the Recent developments – Canadian Natural Gas Pipelines section for additional information. The reorganization will not impact the operations of the NGTL System. As a limited partnership, NGTL LP is not subject to Canadian corporate income taxes. The related income tax obligations are those of the partners.

For the nine months ended September 30, 2024, we incurred costs of $42 million after tax related to the NGTL System Ownership Transfer, which has been excluded from our calculation of comparable measures.

2016 Columbia Pipeline Acquisition Lawsuit

In 2023, the Delaware Chancery Court (the Court) issued its decision in the class action lawsuit commenced by former shareholders of Columbia Pipeline Group Inc. (CPG) related to the acquisition of CPG by TC Energy in 2016. 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.

On May 15, 2024, the Court allocated responsibility for the total sale process damages of US$398 million in the amount of 50 per cent to the former Columbia CEO and CFO, collectively, and 50 per cent to TC Energy. Pursuant to the Final Order and Judgment (Final Judgment), TC Energy’s allocated share of the sale process claim damages is US$199 million, plus US$153 million in interest as of June 14, 2024. The Court also entered judgment related to a disclosure claim for which TC Energy’s allocated share of damages is US$84 million, plus US$64 million in interest as of June 14, 2024. The damages for the two claims are not cumulative and TC Energy would only be required to pay the greater of the sale process damages and disclosure claim damages after final determination of those amounts on appeal.

TC Energy disagrees with many of the Court’s findings and believes the Court’s ruling departs from established Delaware law. TC Energy has filed a notice of appeal of the Court’s decision and anticipates that the appeal will conclude by mid-2025. During the appeal process, in lieu of paying the judgment, TC Energy posted an appeal bond in the amount of US$380 million, which approximates the amount of the Final Judgment plus nine months of post-judgment interest. Our legal assessment is that it is not probable that TC Energy will incur a loss upon completion of the appeal process, and therefore, we have not accrued a provision for this claim at September 30, 2024.

36 | TC Energy Third Quarter 2024

2024 Canadian Legislation

On June 20, 2024, two pieces of Canadian legislation, Bill C-59 and Bill C-69 were enacted into law, which, among other things, included the excessive interest and financing expenses limitation (EIFEL) rules and the Global Minimum Tax Act. We do not expect a material impact on our financial performance and cash flows as a result of the new legislation.

Appointment of Executive Vice-President and CFO

On April 3, 2024, we announced that the Board of Directors appointed Sean O’Donnell, previously Senior Vice-President, Capital Markets and Corporate Planning, who succeeded Joel Hunter as Executive Vice-President and Chief Financial Officer effective May 15, 2024.

Focus Project

In late 2022, we launched the Focus Project to identify opportunities to improve safety, productivity and cost-effectiveness. To date, we have identified a broad set of opportunities expected to further enhance safety, as well as improve operational and financial performance over the long term.

Certain initiatives have been implemented and we expect to continue designing and implementing additional initiatives beyond 2024, with benefits in the form of enhanced productivity and cost-effectiveness expected to be realized in the future.

For the three and nine months ended September 30, 2024 we have incurred pre-tax costs of $8 million and $30 million, respectively, (2023 – $29 million and $98 million, respectively) for the Focus Project primarily related to severance costs, of which $5 million and $15 million (2023 – $18 million and $50 million, respectively, primarily external consulting) was recorded in Plant operating costs and other in the Condensed consolidated statement of income and was removed from comparable amounts. An additional $1 million and $11 million for the three and nine months ended September 30, 2024 (2023 ‑ $4 million and $19 million, respectively) was recorded in Plant operating costs and other with offsetting revenues related to costs recoverable through regulatory and commercial tolling structures, the net effect of which had no impact on net income. As at September 30, 2024, $4 million (2023 – $29 million) was allocated to capital projects.

Asset Divestiture Program

Our asset divestiture program, which includes completing the sale of PNGTS and the CFE’s equity injection resulting in a 13.01 per cent equity interest in TGNH in 2024, as well as the sale of a 40 per cent non-controlling equity interest in Columbia Gas and Columbia Gulf in 2023, have collectively contributed to our deleveraging goal. Any further capital rotation opportunities will be assessed in the normal course of our business.

TC Energy Third Quarter 2024 | 37

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, 2024, our current assets totaled $17.1 billion and current liabilities amounted to $13.1 billion, leaving us with a working capital surplus of $4.0 billion compared to a deficit of $0.4 billion at December 31, 2023. On August 28, 2024, South Bow Canadian Infrastructure Holdings Ltd. and 6297782 LLC completed an offering of approximately $7.9 billion Canadian-dollar equivalent of senior unsecured notes and junior subordinated notes, of which approximately $6.2 billion was placed in escrow pending the completion of the spinoff Transaction. Refer to Note 3, Spinoff of Liquids Pipelines business, of our Condensed consolidated financial statements for additional information. Excluding the proceeds in escrow, 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 $9.8 billion of TCPL committed revolving credit facilities, of which $9.4 billion of short-term borrowing capacity remains available, net of $0.4 billion backstopping outstanding commercial paper balances, and arrangements for a further $2.0 billion of demand credit facilities, of which $1.1 billion remains available as of September 30, 2024

•additional $1.4 billion of committed revolving credit facilities at certain of our subsidiaries and affiliates, which were undrawn as of September 30, 2024

•access to capital markets, including through securities issuances, incremental credit facilities, portfolio management activities and DRP, if deemed appropriate.

38 | TC Energy Third Quarter 2024

CASH PROVIDED BY OPERATING ACTIVITIES

	three months ended September 30		nine months ended September 30
(millions of $)	2024	2023	2024	2023
Net cash provided by operations	1,915	1,824	5,612	5,408
Increase (decrease) in operating working capital	(203)	(102)	313	15
Funds generated from operations	1,712	1,722	5,925	5,423
Specific items:
Current income tax (recovery) expense on PNGTS and non-core assets	139	—	148	—
Liquids Pipelines business separation costs, net of current   income tax	58	15	100	15
NGTL System ownership transfer costs	—	—	10	—
Third-party settlement, net of current income tax	—	—	26	—
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)	48
Focus Project costs, net of current income tax	4	15	13	42
Milepost 14 insurance expense	—	—	—	36
Keystone XL preservation and other, net of current income tax	—	3	—	11
Current income tax (recovery) expense on risk management activities	8	—	9	—
Comparable funds generated from operations	1,915	1,755	6,225	5,575

Net cash provided by operations

Net cash provided by operations increased by $91 million for the three months ended September 30, 2024 compared to the same period in 2023 primarily due to timing of working capital changes. Net cash provided by operations increased by $204 million for the nine months ended September 30, 2024 compared to the same period in 2023 primarily due to higher funds generated from operations and timing of working capital changes.

Comparable funds generated from operations

Comparable funds generated from operations, a non-GAAP measure, helps us assess the cash generating ability of our businesses by excluding the timing effects of working capital changes, as well as the cash impact of our specific items.

Comparable funds generated from operations increased by $160 million and $650 million for the three and nine months ended September 30, 2024, respectively, compared to the same periods in 2023 primarily due to increased comparable EBITDA, higher distributions received from operating activities of our equity investments, which includes receipt of a $200 million distribution from Coastal GasLink LP related to an incentive payment that TC Energy accrued in December 2023, partially offset by higher interest expense and realized losses in 2024 compared to realized gains in 2023 on derivatives used to manage our exposure to net liabilities in Mexico that give rise to foreign exchange gains and losses.

TC Energy Third Quarter 2024 | 39

CASH (USED IN) PROVIDED BY INVESTING ACTIVITIES

	three months ended September 30		nine months ended September 30
(millions of $)	2024	2023	2024	2023
Capital spending
Capital expenditures	(1,756)	(2,042)	(4,668)	(5,945)
Capital projects in development	(8)	(18)	(41)	(122)
Contributions to equity investments	(345)	(1,229)	(888)	(3,246)
	(2,109)	(3,289)	(5,597)	(9,313)
Loans to affiliate (issued) repaid, net	—	—	—	250
Acquisitions, net of cash acquired	—	—	—	(302)
Proceeds from sale of assets, net of transaction costs	743	—	791	—
Other distributions from equity investments	509	—	539	16
Keystone XL contractual recoveries	2	2	7	7
Deferred amounts and other	—	(42)	(133)	(33)
Net cash (used in) provided by investing activities	(855)	(3,329)	(4,393)	(9,375)

Capital expenditures in 2024 were incurred primarily for the development of the Southeast Gateway pipeline, Columbia Gas and ANR projects, as well as maintenance capital expenditures. Lower capital expenditures in 2024 compared to 2023 reflect reduced spending on expansion of the NGTL System and Foothills.

Contributions to equity investments decreased in 2024 compared to 2023 mainly due to lower contributions to Coastal GasLink LP, as well as reduced draws on the subordinated loan by Coastal GasLink LP which are accounted for as     in-substance equity contributions.

Other distributions from equity investments increased in 2024 compared to 2023 mainly due to distributions from Millennium as a result of its debt financing program.

CASH (USED IN) PROVIDED BY FINANCING ACTIVITIES

	three months ended September 30		nine months ended September 30
(millions of $)	2024	2023	2024	2023
Notes payable issued (repaid), net	(1,137)	(2,401)	421	(6,055)
Long-term debt issued, net of issue costs	7,428	7,434	8,089	15,887
Long-term debt repaid	—	(2,150)	(1,662)	(2,610)
Junior subordinated notes issued, net of issue costs	1,465	—	1,465	—
Disposition of equity interest, net of transaction costs	(7)	—	419	—
Dividends and distributions paid	(1,325)	(616)	(3,699)	(1,979)
Contributions from non-controlling interest	11	—	16	—
Common shares issued, net of issue costs	21	—	21	4
Net cash (used in) provided by financing activities	6,456	2,267	5,070	5,247

Dividends and distributions paid increased in 2024 compared to 2023 mainly due to the impact of common shares issued from treasury under the DRP in 2023, as well as higher distributions paid in 2024 as a result of the sale of a 40 per cent non-controlling equity interest in Columbia Gas and Columbia Gulf to Global Infrastructure Partners in fourth quarter 2023.

40 | TC Energy Third Quarter 2024

Long-term debt issued

The following table outlines significant long-term debt issuances in the nine months ended September 30, 2024:

(millions of Canadian $, unless otherwise noted)
Company	Issue date	Type	Maturity date	Amount	Interest rate
TransCanada PipeLines Limited
	August 2024	Term Loan1	August 2024	US 1,242	Floating
Columbia Pipelines Operating Company LLC
	September 2024	Senior Unsecured Notes	October 2054	US 400	5.70	%
Columbia Pipelines Holding Company LLC
	September 2024	Senior Unsecured Notes	October 2031	US 400	5.10	%
	January 2024	Senior Unsecured Notes	January 2034	US 500	5.68	%

1    In August 2024, TCPL entered into a term loan to facilitate the spinoff of its Liquids Pipelines business, and in August 2024, the term loan was fully repaid and retired upon delivery of senior unsecured notes issued by 6297782 LLC.

South Bow debt issued

(millions of Canadian $, unless otherwise noted)
Company	Issue date	Type	Maturity date	Amount	Interest rate
South Bow Canadian Infrastructure Holdings Ltd.
	August 2024	Senior Unsecured Notes	February 2030	450	4.32	%
	August 2024	Senior Unsecured Notes	February 2032	500	4.62	%
	August 2024	Senior Unsecured Notes	February 2035	500	4.93	%
	August 2024	Junior Subordinated Notes	March 2055	US 450	7.63	%
	August 2024	Junior Subordinated Notes	March 2055	US 650	7.50	%
6297782 LLC
	August 2024	Senior Unsecured Notes	September 2027	US 700	4.91	%
	August 2024	Senior Unsecured Notes	October 2029	US 1,000	5.03	%
	August 2024	Senior Unsecured Notes	October 2034	US 1,250	5.58	%
	August 2024	Senior Unsecured Notes	October 2054	US 700	6.18	%

On August 28, 2024, South Bow Canadian Infrastructure Holdings Ltd. and 6297782 LLC completed an offering of approximately $7.9 billion Canadian-dollar equivalent of senior unsecured notes and junior subordinated notes. Approximately $6.2 billion Canadian-dollar equivalent of the net proceeds was placed in escrow pending the completion of the spinoff Transaction on October 1, 2024 and US$1.25 billion of senior unsecured notes were used to repay a TCPL term loan. Upon completion of the spinoff Transaction, the escrowed funds were released to South Bow and used to repay indebtedness owed by South Bow and its subsidiaries to TC Energy and its subsidiaries. Refer to Note 3, Spinoff of Liquids Pipelines business, of our Condensed consolidated financial statements for additional information.

At September 30, 2024, restricted cash was $6.2 billion which was comprised primarily of the proceeds of the South Bow debt offering held in escrow.

TC Energy Third Quarter 2024 | 41

Long-term debt repaid/retired

The following table outlines significant long-term debt repaid in the nine months ended September 30, 2024:

(millions of Canadian $, unless otherwise noted)
Company	Repayment date	Type	Amount	Interest rate
TransCanada PipeLines Limited
	August 2024	Term Loan1	US 1,242	Floating
	June 2024	Medium Term Notes	750	Floating
Nova Gas Transmission Ltd.
	March 2024	Debentures	100	9.90	%
ANR Pipeline Company
	February 2024	Senior Unsecured Notes	US 125	7.38	%
TC Energía Mexicana, S. de R.L. de C.V.
	Various	Senior Unsecured Term Loan	US 265	Floating
	Various	Senior Unsecured Revolving Credit Facility	US 185	Floating

1    In August 2024, TCPL entered into a term loan to facilitate the spinoff of its Liquids Pipelines business, and in August 2024, the term loan was fully repaid and retired upon delivery of senior unsecured notes issued by 6297782 LLC.

On August 15, 2024, the Purchaser assumed US$250 million of senior notes outstanding held at PNGTS as part of the sale of PNGTS. Refer to the Recent developments – U.S. Natural Gas Pipelines section for additional information.

Subsequent debt repayments

On October 12, 2024, TCPL fully repaid and retired US$1.25 billion of senior unsecured notes upon maturity, bearing interest at a fixed rate of one per cent.

On October 15, 2024, TCPL purchased and cancelled the following notes at a 7.73 per cent weighted average discount, as a settlement of the cash tender offers previously announced on October 1, 2024:

(millions of Canadian $, unless otherwise noted)
Company	Repayment date	Type	Amount	Interest rate
TransCanada PipeLines Limited
	October 2024	Senior Unsecured Notes	US 739	2.50	%
	October 2024	Senior Unsecured Notes	US 201	5.00	%
	October 2024	Senior Unsecured Notes	US 441	4.88	%
	October 2024	Senior Unsecured Notes	US 180	5.10	%
	October 2024	Senior Unsecured Notes	US 313	4.75	%
	October 2024	Medium Term Notes	575	4.18	%

In addition, the following callable bonds were fully repaid and retired on October 31, 2024:

(millions of Canadian $, unless otherwise noted)
Company	Repayment date	Type	Amount	Interest rate
TransCanada PipeLines Limited
	October 2024	Senior Unsecured Notes	US 850	6.20	%
	October 2024	Senior Unsecured Notes	US 400	Floating
	October 2024	Medium Term Notes	600	5.42	%
	October 2024	Medium Term Notes	400	Floating

42 | TC Energy Third Quarter 2024

DIVIDENDS

On November 4, 2024, we declared quarterly dividends on our common shares of $0.8225 per share payable on January 31, 2025 to shareholders of record at the close of business on December 31, 2024. The dividend declared reflects TC Energy’s proportionate allocation following the spinoff Transaction. Refer to the Recent developments – Liquids Pipelines section for additional information.

SHARE INFORMATION

At October 30, 2024, we had approximately 1.0 billion issued and outstanding common shares and approximately 6 million outstanding options to buy common shares, of which 4 million were exercisable.

Holders of the Series 9 preferred shares had the option to convert to Series 10 preferred shares by providing notice on or before October 15, 2024. On October 30, 2024, shareholders exercised their option to convert, on a one-for-one basis, 1,297,203 Series 9 preferred shares into Series 10 preferred shares and will receive a floating rate cumulative dividend at an annual rate equal to the 90-day Government of Canada Treasury bill rate plus 2.35 per cent, which will reset every quarter going forward. The fixed dividend rate on the remaining Series 9 preferred shares was reset for five years at 5.08 per cent, per annum. This rate will reset every five years.

Holders of the Series 7 preferred shares had the option to convert to Series 8 preferred shares by providing notice on or before April 15, 2024. As the total number of Series 7 preferred shares tendered for conversion did not meet the established threshold, no Series 7 preferred shares were subsequently converted into Series 8 preferred shares.

STOCK OPTIONS

On October 1, 2024, as part of the spinoff Transaction, all outstanding TC Energy stock options were cancelled, and an equivalent number of new TC Energy stock options were issued to applicable remaining TC Energy employees and former     TC Energy employees (other than those transferred to South Bow pursuant to the spinoff Transaction) who still held TC Energy stock options. The exercise prices of the new TC Energy stock options were adjusted for the change in value of the TC Energy common shares following the spinoff Transaction.

CREDIT FACILITIES

At October 30, 2024, we had a total of $10.0 billion of TCPL committed revolving credit facilities, of which $8.4 billion of short-term borrowing capacity remains available, net of $1.6 billion backstopping outstanding commercial paper balances. We also have arrangements in place for a further $2.0 billion of demand credit facilities, of which $1.1 billion remains available.

TC Energy Third Quarter 2024 | 43

CONTRACTUAL OBLIGATIONS

Long-term purchase obligations at September 30, 2024 have increased by approximately $1.1 billion from those reported at December 31, 2023, primarily due to the extension of the contract for the Canadian Mainline to transport volumes on the TQM pipeline, which we have 50 per cent ownership interest in, to 2042.

Capital expenditure commitments at September 30, 2024 have decreased by approximately $0.5 billion from those reported at December 31, 2023, reflecting normal course fulfillment of construction. As at September 30, 2024, capital expenditure commitments include the Liquids Pipelines business commitments, primarily related to the Blackrod Connection project. As of October 1, 2024, after the completion of the spinoff Transaction, the committed capital related to the Blackrod Connection project is the responsibility of South Bow. Refer to the Recent developments – Liquids Pipelines section for additional information.

44 | TC Energy Third Quarter 2024

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 2023 Annual Report for additional information about the risks we face in our business which have not changed materially since December 31, 2023, 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, cross‑currency interest rate swaps and foreign exchange options, as appropriate.

COUNTERPARTY CREDIT RISK

We have exposure to counterparty credit risk in a number of areas including:

•cash and cash equivalents

•accounts receivable and certain contractual recoveries

•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 2023 Annual Report for more information about the factors that mitigate our counterparty credit risk exposure.

TC Energy Third Quarter 2024 | 45

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, 2024, we had no significant credit risk concentrations and no significant amounts past due or impaired. We recorded a pre-tax loss of     $5 million and pre-tax recovery of $19 million on the expected credit loss provision on the TGNH net investment in leases and certain contract assets in Mexico for the three and nine months ended September 30, 2024, respectively (2023 – pre-tax recovery of $1 million and $116 million, respectively). Refer to Note 13, Risk management and financial instruments, of our Condensed consolidated financial statements for additional information.

We have significant credit and performance exposure to financial institutions that hold cash deposits and provide committed credit lines and letters of credit that help manage our exposure to counterparties and provide liquidity in commodity, foreign exchange and interest rate derivative markets. Our portfolio of financial sector exposure consists primarily of highly-rated investment grade, systemically important financial institutions.

LIQUIDITY RISK

Liquidity risk is the risk that we will not be able to meet our financial obligations as they come due. We manage our liquidity risk by continuously forecasting our cash flows and ensuring we have adequate cash balances, cash flows from operations, committed and demand credit facilities and access to capital markets to meet our operating, financing and capital expenditure obligations under both normal and stressed economic conditions.

RELATED PARTY TRANSACTIONS

Related party transactions are conducted in the normal course of business and are measured at the exchange amount, which is the amount of consideration established and agreed to by the related parties.

Coastal GasLink LP

We hold a 35 per cent equity interest in Coastal GasLink LP and have been contracted to develop, construct and operate the Coastal GasLink pipeline.

TC Energy Subordinated Loan Agreement

TC Energy has a subordinated loan agreement with Coastal GasLink LP under which draws by Coastal GasLink LP will fund the anticipated remaining $0.7 billion (December 31, 2023 – $0.9 billion) equity requirement related to the estimated capital cost to complete the Coastal GasLink pipeline. At September 30, 2024, the total capacity committed by TC Energy and Coastal GasLink LP under this subordinated loan agreement was $3.4 billion.

Any amounts outstanding on this loan will be repaid by Coastal GasLink LP to TC Energy, once final project costs are known. Coastal GasLink LP partners, including TC Energy, will contribute equity to Coastal GasLink LP to ultimately fund Coastal GasLink LP’s repayment of this subordinated loan to TC Energy. We expect that, in accordance with contractual terms, these additional equity contributions will be predominantly funded by TC Energy but will not result in a change to our 35 per cent ownership. The total amount drawn on this loan at September 30, 2024 was $2,680 million (December 31, 2023 – $2,520 million). The carrying value of this loan was $660 million at September 30, 2024 (December 31, 2023 – $500 million) due to the impairment charges recognized to date.

Subordinated Demand Revolving Credit Facilities

We have subordinated demand revolving credit facilities with Coastal GasLink LP to provide additional short-term liquidity and funding flexibility to the project. The facilities bear interest at floating market-based rates and have capacity of $120 million (December 31, 2023 – $100 million) with outstanding balances of nil at September 30, 2024 (December 31, 2023 – nil).

46 | TC Energy Third Quarter 2024

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.

Balance sheet presentation of derivative instruments

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

(millions of $)	September 30, 2024	December 31, 2023
Other current assets	1,242	1,285
Other long-term assets	380	155
Accounts payable and other	(1,168)	(1,143)
Other long-term liabilities	(199)	(106)
	255	191

TC Energy Third Quarter 2024 | 47

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 $)	2024	2023	2024	2023
Derivative Instruments Held for Trading1
Unrealized gains (losses) in the period
Commodities2	54	(17)	33	113
Foreign exchange	24	(40)	(78)	142
Realized gains (losses) in the period
Commodities	192	249	550	579
Foreign exchange	(58)	(29)	(105)	110
Derivative Instruments in Hedging Relationships
Realized gains (losses) in the period
Commodities	6	(8)	24	(20)
Interest rate	(14)	(13)	(41)	(29)

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 held-for-trading derivative instruments are included on a net basis in Foreign exchange (gains) losses, net in the Condensed consolidated statement of income.

2In the three and nine months ended September 30, 2024, unrealized gains of $4 million were reclassified to Net income (loss) from AOCI related to discontinued cash flow hedges (2023 – nil).

For further details on our non-derivative and derivative financial instruments, including classification assumptions made in the calculation of fair value and additional discussion of exposure to risks and mitigation activities, refer to Note 13, Risk management and financial instruments, of our Condensed consolidated financial statements.

48 | TC Energy Third Quarter 2024

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, 2024, 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 2024 that had or are likely to have a material impact on our internal controls over financial reporting.

On October 1, 2024, we completed the spinoff Transaction. In connection with the spinoff Transaction, the internal controls associated with the Liquids Pipelines business were transferred to South Bow. We are contractually obligated to design and maintain adequate controls post-spinoff and throughout the provision of services under the Transition Services Agreement.

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 2023 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.

In the determination of the fair value utilized in the quantitative goodwill impairment test performed in 2023 for the Columbia reporting unit, we performed a discounted cash flow analysis using projections of future cash flows and applied a risk-adjusted discount rate and terminal value multiple which involved significant estimates and judgments. It was determined that the fair value of the Columbia reporting unit exceeded its carrying value, including goodwill. Although goodwill was not impaired, the estimated fair value in excess of the carrying value was less than 10 per cent. There is a risk that reductions in future cash flow forecasts and adverse changes in other key assumptions could result in a future impairment of a portion of the goodwill balance relating to Columbia.

Accounting changes

Our significant accounting policies have remained unchanged since December 31, 2023 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 2023 Annual Report.

TC Energy Third Quarter 2024 | 49

Quarterly results

SELECTED QUARTERLY CONSOLIDATED FINANCIAL DATA

	2024			2023				2022
(millions of $, except per share amounts)	Third	Second	First	Fourth	Third	Second	First	Fourth
Revenues	4,083	4,085	4,243	4,236	3,940	3,830	3,928	4,041
Net income (loss) attributable to common shares	1,457	963	1,203	1,463	(197)	250	1,313	(1,447)
Comparable earnings	1,074	978	1,284	1,403	1,035	981	1,233	1,129
Per share statistics:
Net income (loss) per common share – basic	$1.40	$0.93	$1.16	$1.41	($0.19)	$0.24	$1.29	($1.42)
Comparable earnings per common share	$1.03	$0.94	$1.24	$1.35	$1.00	$0.96	$1.21	$1.11
Dividends declared per common share	$0.96	$0.96	$0.96	$0.93	$0.93	$0.93	$0.93	$0.90

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 Canadian Natural Gas Pipelines, U.S. Natural Gas Pipelines and Mexico Natural Gas Pipelines segments, except for seasonal fluctuations in short-term throughput volumes on U.S. pipelines, quarter-over-quarter revenues and segmented earnings (losses) generally remain relatively stable during any fiscal year. Over the long term, however, they fluctuate because of:

•regulatory decisions

•negotiated settlements with customers

•newly constructed assets being placed in service

•acquisitions and divestitures

•natural gas marketing activities and commodity prices

•developments outside of the normal course of operations

•certain fair value adjustments

•provisions for expected credit losses on net investment in leases and certain contract assets in Mexico.

In Liquids Pipelines, quarter-over-quarter revenues and segmented earnings (losses) are affected by:

•regulatory decisions

•newly constructed assets being placed in service

•acquisitions and divestitures

•demand for uncontracted transportation services

•liquids marketing activities and commodity prices

•developments outside of the normal course of operations

•certain fair value adjustments.

On October 1, 2024, we completed the spinoff of our Liquids Pipelines business into a separate, publicly traded entity, South Bow. Refer to Note 3, Spinoff of Liquids Pipelines business, of our Condensed consolidated financial statements for additional information.

50 | TC Energy Third Quarter 2024

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.

We exclude from comparable measures the unrealized gains and losses from changes in the fair value of derivatives related to financial and commodity price risk management activities. These derivatives generally provide effective economic hedges but do not meet the criteria for hedge accounting. We also exclude from comparable measures our proportionate share of the unrealized gains and losses from changes in the fair value of Bruce Power's funds invested for post-retirement benefits and derivatives related to its risk management activities. These changes in fair value are recorded in net income. As these amounts do not accurately reflect the gains and losses that will be realized at settlement, we do not consider them reflective of our underlying operations.

In third quarter 2024, comparable earnings also excluded:

•an after-tax gain of $456 million related to the sale of PNGTS which was completed on August 15, 2024

•an after-tax charge of $56 million due to Liquids Pipelines business separation costs related to the spinoff Transaction

•after-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 $16 million after-tax expense related to Keystone XL asset disposition and termination activities

•a $12 million after-tax charge related to the FERC Administrative Law Judge decision on Keystone in respect of a tolling-related complaint pertaining to amounts recognized in prior periods

•a $4 million after-tax expense on the expected credit loss provision related to the TGNH net investment in leases and certain contract assets in Mexico, net of non-controlling interest

•a $3 million after-tax expense related to Focus Project costs.

In second quarter 2024, comparable earnings also excluded:

•an after-tax gain of $63 million related to the sale of non-core assets in U.S. Natural Gas Pipelines and Canadian Natural Gas Pipelines

•after-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 $2 million after-tax recovery on the expected credit loss provision related to the TGNH net investment in leases and certain contract assets in Mexico, net of non-controlling interest

•after-tax costs of $42 million related to the NGTL System Ownership Transfer

•an after-tax charge of $26 million due to Liquids Pipelines business separation costs related to the spinoff Transaction.

TC Energy Third Quarter 2024 | 51

In first quarter 2024, comparable earnings also excluded:

•after-tax unrealized foreign exchange gains, net, of $55 million on the peso-denominated intercompany loan between TCPL and TGNH

•a $15 million after-tax recovery on the expected credit loss provision related to the TGNH net investment in leases and certain contract assets in Mexico

•an after-tax expense of $26 million related to a non-recurring third-party settlement

•an after-tax charge of $13 million due to Liquids Pipelines business separation costs related to the spinoff Transaction

•an $8 million after-tax expense related to Focus Project costs.

In fourth quarter 2023, comparable earnings 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

•an $18 million after-tax recovery related to the net impact of a U.S. minimum tax recovery on the 2021 Keystone XL asset impairment charge and other and a gain on the sale of Keystone XL project assets, partially offset by adjustments to the estimate for contractual and legal obligations related to termination activities

•after-tax unrealized foreign exchange losses, net, of $55 million on the peso-denominated intercompany loan between TCPL and TGNH

•a $25 million after-tax loss on the expected credit loss provision related to the TGNH net investment in leases and certain contract assets in Mexico

•an after-tax charge of $23 million due to Liquids Pipelines business separation costs related to the spinoff Transaction

•a $9 million after-tax expense related to Focus Project costs

•carrying charges of $4 million after tax as a result of a charge related to the FERC Administrative Law Judge initial decision on Keystone issued in February 2023 in respect of a tolling-related complaint pertaining to amounts recognized in prior periods

•preservation and other costs for Keystone XL pipeline project assets of $4 million after tax.

In third quarter 2023, comparable earnings also excluded:

•an after-tax impairment charge of $1,179 million related to our equity investment in Coastal GasLink LP

•a $14 million after-tax expense related to Focus Project costs

•an after-tax charge of $11 million due to Liquids Pipelines business separation costs related to the spinoff Transaction

•preservation and other costs for Keystone XL pipeline project assets of $2 million after tax

•after-tax unrealized foreign exchange gains, net, of $20 million on the peso-denominated intercompany loan between TCPL and TGNH.

In second quarter 2023, comparable earnings also excluded:

•an after-tax impairment charge of $809 million related to our equity investment in Coastal GasLink LP

•a $36 million after-tax accrued insurance expense related to the Milepost 14 incident

•a $25 million after-tax expense related to Focus Project costs

•after-tax unrealized foreign exchange losses, net, of $9 million on the peso-denominated intercompany loan between TCPL and TGNH

•preservation and other costs for Keystone XL pipeline project assets of $4 million after tax

•an $8 million after-tax recovery on the expected credit loss provision related to the TGNH net investment in leases and certain contract assets in Mexico.

52 | TC Energy Third Quarter 2024

In first quarter 2023, comparable earnings also excluded:

•a $72 million after-tax recovery on the expected credit loss provision related to the TGNH net investment in leases and certain contract assets in Mexico

•$48 million after-tax charge as a result of the FERC Administrative Law Judge initial decision on Keystone issued in February 2023 in respect of a tolling-related complaint pertaining to amounts recognized in prior periods, which consists of a one-time pre-tax charge of $57 million and accrued pre-tax carrying charges of $5 million

•an after-tax impairment charge of $29 million related to our equity investment in Coastal GasLink LP

•preservation and other costs for Keystone XL pipeline project assets of $4 million after tax.

In fourth quarter 2022, comparable earnings also excluded:

•an after-tax impairment charge of $2.6 billion related to our equity investment in Coastal GasLink LP

•a $64 million after-tax expected credit loss provision related to the TGNH net investment in leases and certain contract assets in Mexico

•a $20 million after-tax charge due to the CER decision on Keystone issued in December 2022 in respect of a tolling-related complaint pertaining to amounts reflected in 2021 and 2020

•preservation and other costs for Keystone XL pipeline project assets of $8 million after tax

•a $5 million after-tax net expense related to the 2021 Keystone XL asset impairment charge and other due to a U.S. minimum tax, partially offset by the gain on the sale of Keystone XL project assets and reduction to the estimate for contractual and legal obligations related to termination activities

•a $1 million income tax expense for the settlement related to prior years' income tax assessments in Mexico.

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