TRP 6-K, filed Nov 5, 2021, 0001232384-21-000125

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 6-K

Report of Foreign Private Issuer

Pursuant to Rule 13a-16 or 15d-16 of

the Securities Exchange Act of 1934

For the month of November 2021

TC Energy Corporation

(Commission File No. 1-31690)

TransCanada PipeLines Limited

(Commission File No. 1-8887)

(Translation of Registrants’ Names into English)

450 - 1 Street S.W., Calgary, Alberta, T2P 5H1, Canada

(Address of Principal Executive Offices)

Indicate by check mark whether the registrant files or will file annual reports under cover of Form 20-F or Form 40-F:

Form 20-F o Form 40-F þ

Indicate by check mark if the registrant is submitting the Form 6-K in paper as permitted by Regulation S-T Rule 101(b)(1): o

Indicate by check mark if the registrant is submitting the Form 6-K in paper as permitted by Regulation S-T Rule 101(b)(7): o

Exhibits 13.1 and 13.2 to this report, furnished on Form 6-K, shall be incorporated by reference into each of the following Registration Statements under the Securities Act of 1933, as amended: Form S-8 (File Nos. 333-5916, 333-8470, 333-9130, 333-151736, 333-184074, 333-227114 and 333-237979), Form F-3 (File Nos. 33-13564 and 333-6132), Form F-4 (File No. 333-252004) and Form F-10 (File Nos. 333-151781, 333-161929, 333-208585, 333-235546, 333-250988, 333-252123 and 333-253333).

Exhibits 31.1, 31.2, 32.1, 32.2 and 99.1 to this report, furnished on Form 6-K, are furnished, not filed, and will not be incorporated by reference into any registration statement filed by the registrants under the Securities Act of 1933, as amended.

Explanatory Note

TransCanada PipeLines Limited (“TransCanada PipeLines”) is a wholly owned subsidiary of TC Energy Corporation (“TC Energy”). TransCanada PipeLines is relying on the continuous disclosure documents filed by TC Energy pursuant to an exemption from the requirements of National Instrument 51-102 - Continuous Disclosure Obligations and as provided in the decision of the Alberta Securities Commission and Ontario Securities Commission in Re TransCanada Corporation, 2019 ABASC 1, issued on January 3, 2019. Consistent with the exemptive relief, information contained in this Form 6-K is that provided by TC Energy.

EXHIBIT INDEX

13.1	Management’s Discussion and Analysis of Financial Condition and Results of Operations of TC Energy Corporation as at and for the period ended September 30, 2021.
13.2	Consolidated comparative interim unaudited financial statements of TC Energy Corporation for the period ended September 30, 2021 (included in TC Energy Corporation's Third Quarter 2021 Quarterly Report to Shareholders).
31.1	Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2	Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1	Certification of Chief Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2	Certification of Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
99.1	A copy of the registrant's news release of November 5 , 2021.

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, each Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

Date: November 5, 2021	TC ENERGY CORPORATION<br>TRANSCANADA PIPELINES LIMITED
	By:	/s/ Joel E. Hunter
		Joel E. Hunter
		Executive Vice-President and Chief Financial Officer
	By:	/s/ G. Glenn Menuz
		G. Glenn Menuz
		Vice-President and Controller

Document

EXHIBIT 13.1

Quarterly report to shareholders

Third quarter 2021

Financial highlights

	three months ended<br>September 30		nine months ended <br>September 30
(millions of $, except per share amounts)	2021	2020	2021	2020
Income
Revenues	3,240	3,195	9,803	9,702
Net income attributable to common shares	779	904	697	3,333
per common share – basic	$0.80	$0.96	$0.72	$3.55
Comparable EBITDA	2,240	2,294	6,978	7,028
Comparable earnings	972	893	3,118	2,865
per common share	$0.99	$0.95	$3.21	$3.05
Cash flows
Net cash provided by operations	1,712	1,783	5,089	5,119
Comparable funds generated from operations	1,556	1,663	5,333	5,306
Capital spending1	1,687	2,250	5,011	6,669
Dividends declared
Per common share	$0.87	$0.81	$2.61	$2.43
Basic common shares outstanding (millions)
– weighted average for the period	979	940	970	940
– issued and outstanding at end of period	979	940	979	940

1Includes capacity capital expenditures, maintenance capital expenditures, capital projects in development and contributions to equity investments.

Management’s discussion and analysis

November 4, 2021

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, 2021, and should be read with the accompanying unaudited Condensed consolidated financial statements for the three and nine months ended September 30, 2021, which have been prepared in accordance with U.S. GAAP.

This MD&A should also be read in conjunction with our December 31, 2020 audited Consolidated financial statements and notes and the MD&A in our 2020 Annual Report. Capitalized abbreviated terms that are used but not otherwise defined herein are defined in our 2020 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

•expected cash flows and future financing options available, including portfolio management

•expected dividend growth

•expected access to and cost of capital

•expected costs and schedules for planned projects, including projects under construction and in development

•expected capital expenditures, contractual obligations, commitments and contingent liabilities

•expected regulatory processes and outcomes

•expected outcomes with respect to legal proceedings, including arbitration and insurance claims

•the expected impact of future tax and accounting changes

•expected industry, market and economic conditions

•the expected impacts of COVID-19.

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 2021

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

Assumptions

•regulatory decisions and outcomes

•planned and unplanned outages and the use of our pipeline, 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

•inflation rates and commodity prices

•interest, tax and foreign exchange rates

•nature and scope of hedging

•expected impact of COVID-19.

Risks and uncertainties

•our ability to successfully implement our strategic priorities and whether they will yield the expected benefits

•our ability to implement a capital allocation strategy aligned with maximizing shareholder value

•the operating performance of our pipeline, power and storage assets

•amount of capacity sold and rates achieved in our pipeline businesses

•the amount of capacity payments and revenues from our power generation assets due to plant availability

•production levels within supply basins

•construction and completion of capital projects

•cost and availability of labour, equipment and materials

•the 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 and COVID-19

•our ability to realize the value of tangible assets and contractual recoveries, including those specific to the Keystone XL pipeline project

•competition in the businesses in which we operate

•unexpected or unusual weather

•acts of civil disobedience

•cyber security and technological developments

•economic conditions in North America as well as globally

•global health crises, such as pandemics and epidemics, including COVID-19 and the unexpected 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 2020 Annual Report.

TC Energy Third Quarter 2021 | 3

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 (AIF) and other disclosure documents, which are available on SEDAR (www.sedar.com).

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.

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.

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 not to adjust for a specific item is subjective and made after careful consideration. Specific items may include:

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

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

•certain fair value adjustments relating to risk management activities

•legal, contractual and bankruptcy settlements

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

•acquisition and integration costs

•restructuring costs.

We exclude the unrealized gains and losses from changes in the fair value of derivatives used to reduce our exposure to certain financial and commodity price risks. These derivatives generally provide effective economic hedges but do not meet the criteria for hedge accounting. As a result, the 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. We also exclude the unrealized foreign exchange gains and losses on the Loan receivable from affiliate as well as the corresponding proportionate share of Sur de Texas foreign exchange gains and losses, as these amounts do not accurately reflect the gains and losses that will be realized at settlement. These amounts offset within each reporting period, resulting in no impact on net income.

4 | TC Energy Third Quarter 2021

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

Comparable measure	GAAP measure
comparable EBITDA	segmented earnings
comparable EBIT	segmented earnings
comparable earnings	net income attributable to common shares
comparable earnings per common share	net income per common share
funds generated from operations	net cash provided by operations
comparable funds generated from operations	net cash provided by operations

Comparable EBITDA and comparable EBIT

Comparable EBITDA (comparable earnings before interest, taxes, depreciation and amortization) represents segmented earnings adjusted for certain specific items, excluding non-cash 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 (comparable earnings before interest and taxes) represents segmented earnings adjusted for specific items and is an effective tool for evaluating trends in each segment. Refer to each business segment section for a reconciliation to segmented earnings.

Comparable earnings and comparable earnings per common share

Comparable earnings represents earnings or losses attributable to common shareholders on a consolidated basis, adjusted for specific items. Comparable earnings is comprised of segmented earnings, Interest expense, Allowance for funds used during construction (AFUDC), Interest income and other, Income tax expense, Non-controlling interests and Preferred share dividends, adjusted for specific items. Refer to the Consolidated results section for reconciliations to Net income attributable to common shares and Net income 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. We believe it 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 performance of our assets. Comparable funds generated from operations is adjusted for the cash impact of specific items noted above. Refer to the Financial condition section for a reconciliation to Net cash provided by operations.

TC Energy Third Quarter 2021 | 5

Capital program

We are developing quality projects under our capital program. These long-life infrastructure assets are supported by long-term commercial arrangements with creditworthy counterparties and/or regulated business models and are expected to generate significant growth in earnings and cash flows.

Our capital program consists of approximately $22 billion of secured projects which include commercially supported, committed projects that are either under construction or are in or preparing to commence the permitting stage. An additional $7 billion of projects under development are commercially supported (except where noted) but have greater uncertainty with respect to timing and estimated project costs and are subject to certain key approvals.

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. Tolling arrangements in our liquids pipelines business provide for the recovery of maintenance capital expenditures.

In the nine months ended September 30, 2021, we placed approximately $0.9 billion of Canadian and U.S. Natural Gas Pipelines capacity capital projects into service. In addition, approximately $1.3 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, permitting conditions, scheduling and timing of regulatory permits, as well as the additional restrictions and uncertainty presented by the ongoing impact of COVID-19. Amounts exclude capitalized interest and AFUDC.

6 | TC Energy Third Quarter 2021

Secured projects

	Estimated<br><br>project cost1	Carrying value at September 30, 2021
(billions of )
Canadian Natural Gas Pipelines
Canadian Mainline	0.3	0.2
NGTL System2	1.2	1.1
	3.3	1.2
	1.8	0.1
	0.5	—
Coastal GasLink3	0.2	0.2
Regulated maintenance capital expenditures	2.1	0.4
U.S. Natural Gas Pipelines
Other capacity capital	US 3.5	US 1.2
Regulated maintenance capital expenditures	US 2.1	US 0.5
Mexico Natural Gas Pipelines
Villa de Reyes	US 1.0	US 0.9
Tula4	US 0.8	US 0.6
Liquids Pipelines
Other capacity capital	US 0.1	—
Recoverable maintenance capital expenditures	0.1	—
Power and Storage
Bruce Power – life extension5	2.7	1.6
Other
Non-recoverable maintenance capital expenditures6	0.7	0.2
	20.4	8.2
Foreign exchange impact on secured projects7	2.0	0.9
Total secured projects (Cdn)	22.4	9.1

All values are in US Dollars.

1Amounts reflect 100 per cent of costs related to wholly-owned assets as well as cash contributions to our joint venture investments.

2Estimated project costs for 2022 and 2023 include $0.5 billion for Foothills related to the West Path Expansion Program.

3The estimated project cost represents our share of anticipated partner equity contributions to the project, with the expected in-service date and estimated project cost reflecting the last project update. Refer to the Recent developments – Canadian Natural Gas Pipelines section for additional information on the status of Coastal GasLink's dispute with LNG Canada regarding the recognition of certain costs and schedule changes, as well as our commitment to provide additional temporary financing, if necessary, to Coastal GasLink under certain circumstances.

4Construction of the central segment of the Tula project has been delayed due to a lack of progress to successfully complete Indigenous consultation by the Secretary of Energy. Project completion is expected approximately two years after the consultation process is successfully concluded. The East Section of the Tula pipeline is available for interruptible transportation services.

5Reflects our expected share of cash contributions for the Bruce Power Unit 6 MCR program, expected to be in service in 2023, amounts to be invested under the Asset Management program through 2024 as well as the incremental uprate initiative. Refer to the Recent developments – Power and Storage section for additional information.

6Includes non-recoverable maintenance capital expenditures from all segments and is primarily comprised of our proportionate share of maintenance capital expenditures for Bruce Power and other Power and Storage assets.

7Reflects U.S./Canada foreign exchange rate of 1.27 at September 30, 2021.

TC Energy Third Quarter 2021 | 7

Projects under development

The costs provided in the table below reflect the most recent estimates for each project as filed with the various regulatory authorities or otherwise determined by management.

	Estimated<br><br>project cost1	Carrying value at September 30, 2021
(billions of $)
U.S. Natural Gas Pipelines
Other capacity capital2	US 0.3	—
Liquids Pipelines
Grand Rapids Phase II3	0.7	—
Power and Storage
Bruce Power – life extension4	6.3	0.3
	7.3	0.3
Foreign exchange impact on projects under development5	0.1	—
Total projects under development (Cdn$)	7.4	0.3

1Amounts reflect our proportionate share of joint venture costs where applicable and 100 per cent of costs related to wholly-owned assets.

2Includes projects subject to a positive customer FID.

3Regulatory approvals have been obtained and additional commercial support is being pursued.

4Reflects our proportionate share of the Bruce Power MCR program costs for Units 3, 4, 5, 7 and 8, the remaining Asset Management program costs beyond 2024, as well as the incremental uprate initiative. Refer to the Recent developments – Power and Storage section for additional information.

5Reflects U.S./Canada foreign exchange rate of 1.27 at September 30, 2021.

8 | TC Energy Third Quarter 2021

Consolidated results – third quarter 2021

	three months ended<br>September 30		nine months ended <br>September 30
(millions of $, except per share amounts)	2021	2020	2021	2020
Canadian Natural Gas Pipelines	343	334	1,060	1,307
U.S. Natural Gas Pipelines	692	644	2,253	2,107
Mexico Natural Gas Pipelines	144	142	434	532
Liquids Pipelines	285	342	(1,973)	1,059
Power and Storage	116	105	437	138
Corporate	(36)	(61)	(40)	220
Total segmented earnings	1,544	1,506	2,171	5,363
Interest expense	(596)	(559)	(1,749)	(1,698)
Allowance for funds used during construction	81	91	195	254
Interest income and other	(76)	164	113	(160)
Income before income taxes	953	1,202	730	3,759
Income tax (expense)/recovery	(135)	(190)	158	(78)
Net income	818	1,012	888	3,681
Net income attributable to non-controlling interests	(8)	(69)	(83)	(228)
Net income attributable to controlling interests	810	943	805	3,453
Preferred share dividends	(31)	(39)	(108)	(120)
Net income attributable to common shares	779	904	697	3,333
Net income per common share – basic	$0.80	$0.96	$0.72	$3.55

Net income attributable to common shares decreased by $125 million and $2.6 billion or $0.16 and $2.83 per common share for the three and nine months ended September 30, 2021 compared to the same periods in 2020. These decreases were primarily due to the $2.2 billion after-tax asset impairment of the Keystone XL pipeline project, net of expected contractual recoveries and other contractual and legal obligations, as well as unrealized net losses on risk management activities in third quarter 2021 compared to unrealized gains in third quarter 2020. The decreases in Net income per common share also reflected the impact of common shares issued for the acquisition of the remaining ownership interests in TC PipeLines, LP in first quarter 2021.

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

2021 results included:

•a $2.2 billion after-tax asset impairment charge predominantly in first quarter 2021, net of expected contractual recoveries and other contractual and legal obligations, related to the termination of the Keystone XL pipeline project following the January 20, 2021 revocation of the Presidential Permit. Refer to the Recent developments – Liquids Pipelines section for additional information

•preservation and other costs of $11 million and $27 million after tax for the three and nine months ended September 30, 2021 primarily related to the preservation and storage of Keystone XL pipeline project assets which could not be accrued as part of the Keystone XL impairment charge, as well as interest expense in second quarter 2021 on the Keystone XL project-level credit facility prior to its termination

•a $55 million after-tax expense with respect to transition payments incurred as part of the Voluntary Retirement Program (VRP)

•a $13 million after-tax recovery of certain costs from the IESO in second quarter 2021 associated with the Ontario natural gas-fired power plants sold in April 2020.

TC Energy Third Quarter 2021 | 9

The Keystone XL pipeline project asset impairment charge does not reflect offsetting amounts with respect to the Government of Alberta's related investment in Keystone XL nor their repayment of the project's guaranteed credit facility without recourse to TC Energy, both of which were accounted for within the Condensed consolidated statement of equity in second quarter 2021 and served to reduce our net financial impact from the Keystone XL pipeline project termination. Refer to the Recent developments – Liquids Pipelines section for additional information.

2020 results included:

•a $6 million reduction to the after-tax gain in third quarter 2020 related to the sale of a 65 per cent equity interest in Coastal GasLink Pipeline Limited Partnership (Coastal GasLink LP) in May 2020, resulting in an after-tax gain of $402 million for the nine months ended September 30, 2020

•an income tax valuation allowance release of $281 million following our reassessment of deferred income tax assets that were deemed more likely than not to be realized in first quarter 2020

•an incremental after-tax loss of $45 million in third quarter 2020 related to the Ontario natural-gas fired power plants sold in April 2020, which resulted in a year-to-date after-tax loss of $202 million at September 30, 2020.

Net income in both periods included unrealized gains and losses from changes in risk management activities which we exclude, along with the above noted items, to arrive at comparable earnings. A reconciliation of Net income attributable to common shares to comparable earnings is shown in the following table.

RECONCILIATION OF NET INCOME TO COMPARABLE EARNINGS

	three months ended<br>September 30		nine months ended <br>September 30
(millions of $, except per share amounts)	2021	2020	2021	2020
Net income attributable to common shares	779	904	697	3,333
Specific items (net of tax):
Keystone XL asset impairment charge and other	—	—	2,194	—
Keystone XL preservation and other	11	—	27	—
Voluntary Retirement Program	55	—	55	—
Gain on partial sale of Coastal GasLink LP	—	6	—	(402)
Income tax valuation allowance release	—	—	—	(281)
Loss/(gain) on sale of Ontario natural gas-fired power plants	—	45	(13)	202
Risk management activities1	127	(62)	158	13
Comparable earnings	972	893	3,118	2,865
Net income per common share	$0.80	$0.96	$0.72	$3.55
Specific items (net of tax):
Keystone XL asset impairment charge and other	—	—	2.27	—
Keystone XL preservation and other	0.01	—	0.03	—
Voluntary Retirement Program	0.05	—	0.05	—
Gain on partial sale of Coastal GasLink LP	—	0.01	—	(0.43)
Income tax valuation allowance release	—	—	—	(0.30)
Loss/(gain) on sale of Ontario natural gas-fired power plants	—	0.05	(0.01)	0.21
Risk management activities	0.13	(0.07)	0.15	0.02
Comparable earnings per common share	$0.99	$0.95	$3.21	$3.05

10 | TC Energy Third Quarter 2021

Risk management activities	three months ended<br>September 30		nine months ended <br>September 30
(millions of $)	2021	2020	2021	2020
U.S. Natural Gas marketing	(3)	—	(1)	—
Liquids marketing	(8)	9	2	16
Canadian Power	7	—	8	(1)
Natural Gas Storage	(39)	(4)	(36)	(8)
Foreign exchange	(125)	78	(183)	(24)
Income tax attributable to risk management activities	41	(21)	52	4
Total unrealized (losses)/gains from risk management activities	(127)	62	(158)	(13)

COMPARABLE EBITDA TO COMPARABLE EARNINGS

Comparable EBITDA represents segmented earnings adjusted for the specific items described above and excludes non-cash charges for depreciation and amortization. For further information on our reconciliation to comparable EBITDA refer to the business segment financial results sections.

	three months ended<br>September 30		nine months ended <br>September 30
(millions of $, except per share amounts)	2021	2020	2021	2020
Comparable EBITDA
Canadian Natural Gas Pipelines	631	666	2,001	1,884
U.S. Natural Gas Pipelines	890	863	2,824	2,719
Mexico Natural Gas Pipelines	171	170	515	620
Liquids Pipelines	387	415	1,146	1,292
Power and Storage	168	187	506	516
Corporate	(7)	(7)	(14)	(3)
Comparable EBITDA	2,240	2,294	6,978	7,028
Depreciation and amortization	(610)	(673)	(1,888)	(1,938)
Interest expense included in comparable earnings	(596)	(559)	(1,743)	(1,698)
Allowance for funds used during construction	81	91	195	254
Interest income and other included in comparable earnings	91	32	341	87
Income tax expense included in comparable earnings	(195)	(184)	(574)	(520)
Net income attributable to non-controlling interests	(8)	(69)	(83)	(228)
Preferred share dividends	(31)	(39)	(108)	(120)
Comparable earnings	972	893	3,118	2,865
Comparable earnings per common share	$0.99	$0.95	$3.21	$3.05

TC Energy Third Quarter 2021 | 11

Comparable EBITDA – 2021 versus 2020

Comparable EBITDA decreased by $54 million for the three months ended September 30, 2021 compared to the same period in 2020 primarily due to the net effect of the following:

•lower EBITDA from Canadian Natural Gas Pipelines largely attributable to the impact of lower flow-through depreciation and financial charges on the Canadian Mainline, partially offset by increased flow-through depreciation and income taxes along with higher rate-base earnings on the NGTL System

•decreased earnings from Liquids Pipelines as a result of lower contributions from liquids marketing activities, mainly attributable to lower margins

•foreign exchange impact of a weaker U.S. dollar on the Canadian dollar equivalent segmented earnings in our U.S. dollar-denominated operations. As detailed below, U.S. dollar-denominated comparable EBITDA increased by US$53 million to US$1.1 billion compared to 2020, however, this was translated at a rate of 1.26 in 2021 versus 1.33 in 2020. Refer to the Foreign exchange discussion below for additional information.

Comparable EBITDA decreased by $50 million for the nine months ended September 30, 2021 compared to the same period in 2020 primarily due to the net effect of the following:

•decreased earnings from Liquids Pipelines attributable to lower volumes on the U.S. Gulf Coast section of the Keystone Pipeline System, partially offset by increased contributions from liquids marketing activities reflecting higher margins and volumes

•lower contribution from Mexico Natural Gas Pipelines mainly due to US$55 million of fees recognized in 2020 associated with the successful completion of the Sur de Texas pipeline

•lower Power and Storage results attributable to decreased earnings at Bruce Power in 2021 due to lower volumes resulting from greater planned outage days and higher operating expenses, partially offset by higher realized power prices, increased Natural Gas Storage and Other earnings reflecting higher realized Alberta natural gas spreads and the impact of the November 2020 acquisition of the remaining 50 per cent ownership interest in TC Turbines

•higher EBITDA from Canadian Natural Gas Pipelines largely as a result of the impact of increased flow-through depreciation and income taxes along with higher rate-base earnings on the NGTL System, as well as higher Coastal GasLink development fees and Canadian Mainline incentive earnings and flow-through income taxes, partially offset by lower flow-through depreciation and financial charges on the Canadian Mainline

•increased earnings in U.S. Natural Gas Pipelines from Columbia Gas following the application for higher transportation rates effective February 1, 2021 and the settlement-in-principle that was reached on July 28, 2021, subject to refund upon completion of the current rate proceeding, and improved earnings across our U.S. Natural Gas Pipelines assets following the cold weather events of 2021 impacting many of the U.S. markets in which we operate, partially offset by higher property taxes

•foreign exchange impact of a weaker U.S. dollar on the Canadian dollar equivalent segmented earnings in our U.S. dollar-denominated operations. As detailed below, U.S. dollar-denominated comparable EBITDA increased by US$134 million to US$3.4 billion compared to 2020, however, this was translated at a rate of 1.25 in 2021 versus 1.35 in 2020.

While the weakening of the U.S. dollar in 2021 compared to the same periods in 2020 had a considerable negative impact on 2021 comparable EBITDA, the corresponding impact on comparable earnings was not significant due to offsetting natural and economic hedges. Refer to the Foreign exchange discussion below for additional information.

12 | TC Energy Third Quarter 2021

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

Comparable earnings – 2021 versus 2020

Comparable earnings increased by $79 million or $0.04 per common share for the three months ended September 30, 2021 compared to the same period in 2020 and was primarily the net effect of:

•changes in comparable EBITDA described above

•lower Depreciation and amortization primarily in Canadian Natural Gas Pipelines on the Canadian Mainline, partially offset by higher depreciation on the NGTL System from expansion facilities that were placed in service

•decreased Non-controlling interests following the March 3, 2021 acquisition of all outstanding common units of TC PipeLines, LP not beneficially owned by TC Energy

•higher Interest income and other mainly attributable to realized gains in 2021 compared to realized losses in 2020 on derivatives used to manage our net exposure to foreign exchange rate fluctuations on U.S. dollar-denominated income

•higher Interest expense primarily due to lower capitalized interest as a result of its cessation for the Keystone XL pipeline project following the revocation of the Presidential Permit in January 2021, partially offset by the foreign exchange impact from a weaker U.S. dollar on translation of U.S. dollar-denominated interest.

Comparable earnings increased by $253 million or $0.16 per common share for the nine months ended September 30, 2021 compared to the same period in 2020 and was primarily the net effect of:

•changes in comparable EBITDA described above

•decreased Non-controlling interests following the March 3, 2021 acquisition of all outstanding common units of TC PipeLines, LP not beneficially owned by TC Energy

•lower Depreciation and amortization on our U.S. dollar-denominated assets primarily as a result of the weaker U.S. dollar

•lower AFUDC, predominantly due to the suspension of recording AFUDC on the Villa de Reyes project effective January 1, 2021 as a result of ongoing project delays, partially offset by higher AFUDC related to the NGTL System and U.S. natural gas pipeline expansion projects

•higher Income tax expense primarily as a result of higher pre-tax earnings and increased flow-through income taxes on our Canadian rate-regulated pipelines, partially offset by higher foreign tax rate differentials

•higher Interest expense primarily due to lower capitalized interest as a result of its cessation for the Keystone XL pipeline project following the revocation of the Presidential Permit in January 2021, the change to equity accounting for our Coastal GasLink investment upon the sale of a 65 per cent interest in Coastal GasLink LP in second quarter 2020 and the completion of the Napanee power plant in first quarter 2020, partially offset by long-term debt issuances, net of maturities and the foreign exchange impact from a weaker U.S. dollar on translation of U.S. dollar-denominated interest.

Comparable earnings per share also reflected the impact of common shares issued for the acquisition of the remaining ownership interests in TC PipeLines, LP in first quarter 2021. Refer to the Financial condition section of this MD&A for further information on common share issuances.

TC Energy Third Quarter 2021 | 13

Foreign exchange

Certain of our businesses generate all or most of their earnings in U.S. dollars and, since we report our financial results in Canadian dollars, changes in the value of the U.S. dollar against the Canadian dollar directly affect our comparable EBITDA and may also impact comparable earnings. As our U.S. dollar-denominated operations continue to grow, this exposure increases. A portion of the U.S. dollar-denominated comparable EBITDA exposure is naturally offset by U.S. dollar-denominated amounts below comparable EBITDA within Depreciation and amortization, Interest expense and other income statement line items. The balance of the exposure is actively managed on a rolling two-year forward basis using foreign exchange derivatives, however, the natural exposure beyond that period remains. As noted previously, the net impact of the U.S. dollar movements on comparable earnings for the three and nine months ended September 30, 2021 compared to 2020, after considering natural offsets and economic hedges, was not significant.

Average exchange rate — U.S. to Canadian dollars

The average exchange rate for one U.S. dollar converted into Canadian dollars was as follows:

three months ended September 30, 2021	1.26
three months ended September 30, 2020	1.33	nine months ended September 30, 2021	1.25
---	---
nine months ended September 30, 2020	1.35

The components of our financial results denominated in U.S. dollars are set out in the table below, including our U.S. and Mexico Natural Gas Pipelines operations along with the majority of our Liquids Pipelines business. Comparable EBITDA is a non-GAAP measure.

Pre-tax U.S. dollar-denominated income and expense items	three months ended<br>September 30		nine months ended <br>September 30
(millions of US$)	2021	2020	2021	2020
Comparable EBITDA
U.S. Natural Gas Pipelines	706	647	2,256	2,008
Mexico Natural Gas Pipelines1	152	146	462	520
U.S. Liquids Pipelines	223	235	668	724
	1,081	1,028	3,386	3,252
Depreciation and amortization	(224)	(233)	(666)	(661)
Interest on long-term debt and junior subordinated notes	(315)	(324)	(945)	(987)
Capitalized interest	—	38	10	89
Allowance for funds used during construction	33	51	73	126
Non-controlling interests and other	(7)	(56)	(67)	(178)
	568	504	1,791	1,641

1Excludes interest expense on our inter-affiliate loan with Sur de Texas which is fully offset in Interest income and other.

14 | TC Energy Third Quarter 2021

Outlook

Consolidated comparable earnings

Our overall comparable earnings per common share outlook for 2021 is expected to be modestly higher than reported in the 2020 Annual Report. This is primarily due to incremental U.S. Natural Gas Pipelines' earnings in 2021 and higher realized margins in Canadian Power.

We continue to monitor developments in energy markets, our construction projects and regulatory proceedings for any impact on our 2021 comparable earnings per common share. We do not expect COVID-19 to have a material impact on our 2021 comparable earnings.

Consolidated capital spending

Our expected total capital expenditures for 2021 as outlined in the 2020 Annual Report remain materially unchanged. Although we have observed some slowdown on certain of our construction activities and capital expenditures, we do not believe disruptions related to COVID-19 will be material to our overall 2021 capital program.

TC Energy Third Quarter 2021 | 15

Canadian Natural Gas Pipelines

The following is a reconciliation of comparable EBITDA and comparable EBIT (our non-GAAP measures) to segmented earnings (the most directly comparable GAAP measure).

	three months ended<br>September 30		nine months ended <br>September 30
(millions of $)	2021	2020	2021	2020
NGTL System	409	390	1,214	1,103
Canadian Mainline	183	229	648	677
Other Canadian pipelines1	39	47	139	104
Comparable EBITDA	631	666	2,001	1,884
Depreciation and amortization	(288)	(326)	(941)	(941)
Comparable EBIT	343	340	1,060	943
Specific item:
Gain on partial sale of Coastal GasLink LP	—	(6)	—	364
Segmented earnings	343	334	1,060	1,307

1Includes results from Foothills, Ventures LP, Great Lakes Canada, our investment in TQM, Coastal GasLink development fee revenue as well as general and administrative and business development costs related to our Canadian Natural Gas Pipelines.

Canadian Natural Gas Pipelines segmented earnings increased by $9 million and decreased by $247 million for the three and nine months ended September 30, 2021 compared to the same periods in 2020. Third quarter 2020 results included a $6 million reduction to the pre-tax gain on the May 2020 sale of a 65 per cent equity interest in Coastal GasLink LP, resulting in a pre-tax gain of $364 million for the nine months ended September 30, 2020. These amounts have been excluded from our calculation of comparable EBIT.

Net income and comparable EBITDA for our rate-regulated Canadian natural gas pipelines are primarily affected by our approved ROE, our investment base, the level of deemed common equity and incentive earnings. Changes in depreciation, financial charges and income taxes affect 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<br>September 30		nine months ended <br>September 30
(millions of $)	2021	2020	2021	2020
Net income
NGTL System	160	145	467	419
Canadian Mainline	52	40	156	118
Average investment base
NGTL System			15,345	13,890
Canadian Mainline			3,700	3,649

Net income for the NGTL System increased by $15 million and $48 million for the three and nine months ended September 30, 2021 compared to the same periods in 2020 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 ROE of 10.1 per cent on 40 per cent deemed common equity, 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.

16 | TC Energy Third Quarter 2021

Net income for the Canadian Mainline increased by $12 million and $38 million for the three and nine months ended September 30, 2021 compared to the same periods in 2020 largely due to higher incentive earnings and the elimination of a $20 million after-tax annual TC Energy contribution included in the previous NEB 2014 Decision. Beginning January 1, 2021, 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 decreased by $35 million and increased by $117 million for the three and nine months ended September 30, 2021 compared to the same periods in 2020 due to the net effect of:

•higher flow-through depreciation and income taxes as well as increased rate-base earnings on the NGTL System

•lower flow-through depreciation and financial charges, partially offset by higher flow-through income taxes, increased incentive earnings and elimination of the TC Energy contribution on the Canadian Mainline

•Coastal GasLink development fee revenue commenced in second quarter 2020 and resulted in increased earnings for the nine months ended September 30, 2021, with lower earnings for the three months ended September 30, 2021 due to the timing of revenue recognition, compared to the same periods in 2020.

DEPRECIATION AND AMORTIZATION

Depreciation and amortization decreased by $38 million for the three months ended September 30, 2021 compared to the same period in 2020 mainly due to one section of the Canadian Mainline being fully depreciated, partially offset by higher depreciation on the NGTL System from expansion facilities that were placed in service. Depreciation and amortization was consistent for the nine months ended September 30, 2021 with the same period in 2020.

TC Energy Third Quarter 2021 | 17

U.S. Natural Gas Pipelines

On March 3, 2021, we acquired all the outstanding common units of TC PipeLines, LP not beneficially owned by TC Energy or our affiliates in exchange for TC Energy common shares (the TC PipeLines, LP acquisition). Refer to the Recent developments – U.S. Natural Gas Pipelines section for additional information. TC PipeLines, LP results reflect our ownership interests in eight natural gas pipelines prior to the acquisition.

The table below is a reconciliation of comparable EBITDA and comparable EBIT (our non-GAAP measures) to segmented earnings (the most directly comparable GAAP measure).

	three months ended<br>September 30		nine months ended <br>September 30
(millions of US$, unless otherwise noted)	2021	2020	2021	2020
Columbia Gas	359	308	1,122	968
ANR	135	120	436	381
Columbia Gulf	52	46	161	143
Great Lakes1,4	35	18	112	65
GTN2,4	40	—	95	—
Other U.S. pipelines3,4	78	36	215	86
TC PipeLines, LP4,5	—	28	24	88
Non-controlling interests5	7	91	91	277
Comparable EBITDA	706	647	2,256	2,008
Depreciation and amortization	(154)	(164)	(455)	(452)
Comparable EBIT	552	483	1,801	1,556
Foreign exchange impact	143	161	453	551
Comparable EBIT (Cdn$)	695	644	2,254	2,107
Specific item:
Risk management activities	(3)	—	(1)	—
Segmented earnings (Cdn$)	692	644	2,253	2,107

1Results reflect our 53.55 per cent direct interest in Great Lakes until March 3, 2021 and our 100 per cent ownership interest subsequent to the TC PipeLines, LP acquisition.

2Reflects 100 per cent of GTN's earnings subsequent to the TC PipeLines, LP acquisition on March 3, 2021.

3Reflects earnings from our ownership in our mineral rights business (CEVCO), Crossroads, and our share of equity income from Millennium and Hardy Storage, as well as general and administrative and business development costs related to our U.S. natural gas pipelines. For the period subsequent to the TC PipeLines, LP acquisition on March 3, 2021, results also include 100 per cent of Bison, North Baja, and Tuscarora, 61.7 per cent of Portland, plus our equity income from Northern Border and Iroquois.

4Our ownership interest in TC PipeLines, LP was 25.5 per cent prior to the acquisition on March 3, 2021, at which time it became 100 per cent. Prior to March 3, 2021, results reflected TC PipeLines, LP’s 46.45 per cent interest in Great Lakes, its ownership of GTN, Bison, North Baja, Portland and Tuscarora as well as its share of equity income from Northern Border and Iroquois.

5Reflects earnings attributable to portions of TC PipeLines, LP and Portland that we did not own prior to the TC PipeLines, LP acquisition on March 3, 2021, and subsequently reflects earnings attributable to the remaining 38.3 per cent interest in Portland we do not own.

U.S. Natural Gas Pipelines segmented earnings increased by $48 million and $146 million for the three and nine months ended September 30, 2021 compared to the same periods in 2020 and included unrealized losses from changes in the fair value of derivatives related to our U.S. Natural Gas marketing business in 2021 which have been excluded from our calculation of comparable EBIT. A weaker U.S. dollar in 2021 had a negative impact on the Canadian dollar equivalent segmented earnings from our U.S. operations compared to the same period in 2020. Refer to the Consolidated results – Foreign exchange section for additional information.

18 | TC Energy Third Quarter 2021

Comparable EBITDA for U.S. Natural Gas Pipelines increased by US$59 million and US$248 million for the three and nine months ended September 30, 2021 compared to the same periods in 2020 and was primarily due to the net effect of:

•a net increase in earnings from Columbia Gas following the application for higher transportation rates effective February 1, 2021 and the settlement-in-principle that was reached on July 28, 2021, subject to refund upon completion of the rate proceeding, partially offset by higher property taxes. For the nine months ended September 30, 2021, earnings also increased due to greater capitalized pipeline integrity costs in 2021 compared to 2020. Refer to the Recent developments – U.S. Natural Gas Pipelines section for additional information

•increased earnings across our U.S. Natural Gas Pipelines assets, which includes the impact of cold weather events in first quarter 2021 affecting many of the U.S. markets in which we operate.

The positive impact on comparable earnings following the TC PipeLines, LP acquisition noted above is reflected through a reduction in Non-controlling interests. Refer to the Corporate – Net income attributable to non-controlling interests section for additional information.

DEPRECIATION AND AMORTIZATION

Depreciation and amortization decreased by US$10 million for the three months ended September 30, 2021 compared to the same period in 2020 mainly due to certain third quarter 2020 adjustments and increased by US$3 million for the nine months ended September 30, 2021 compared to the same period in 2020 mainly due to new projects placed in service.

TC Energy Third Quarter 2021 | 19

Mexico Natural Gas Pipelines

The following is a reconciliation of comparable EBITDA and comparable EBIT (our non-GAAP measures) to segmented earnings (the most directly comparable GAAP measure).

	three months ended<br>September 30		nine months ended <br>September 30
(millions of US$, unless otherwise noted)	2021	2020	2021	2020
Topolobampo	40	40	121	120
Sur de Texas1	31	23	92	145
Tamazunchale	29	31	91	91
Guadalajara	17	16	54	47
Mazatlán	18	18	53	53
Comparable EBITDA	135	128	411	456
Depreciation and amortization	(21)	(21)	(65)	(65)
Comparable EBIT	114	107	346	391
Foreign exchange impact	30	35	88	141
Comparable EBIT and segmented earnings (Cdn$)	144	142	434	532

1Represents equity income from our 60 per cent interest and fees earned from the construction and operation of the pipeline.

Mexico Natural Gas Pipelines comparable EBIT and segmented earnings increased by $2 million and decreased by $98 million for the three and nine months ended September 30, 2021, compared to the same periods in 2020. A weaker U.S. dollar for the three and nine months ended September 30, 2021 had a negative impact on the Canadian dollar equivalent segmented earnings compared to the same periods in 2020. Refer to the Consolidated results – Foreign exchange section for additional information.

Comparable EBITDA for Mexico Natural Gas Pipelines increased by US$7 million for the three months ended September 30, 2021 compared to the same period in 2020 primarily as a result of increased Sur de Texas earnings reflecting lower interest and deferred income tax expenses. Comparable EBITDA decreased by US$45 million for the nine months ended September 30, 2021 compared to the same period in 2020 mainly attributable to US$55 million of fees recognized in first quarter 2020 associated with the successful completion of the Sur de Texas pipeline, partially offset by additional earnings from Guadalajara following the implementation of a flow reversal completed in 2020.

DEPRECIATION AND AMORTIZATION

Depreciation and amortization for the three and nine months ended September 30, 2021 was consistent with the same periods in 2020.

20 | TC Energy Third Quarter 2021

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<br>September 30		nine months ended <br>September 30
(millions of $)	2021	2020	2021	2020
Keystone Pipeline System	327	345	956	1,113
Intra-Alberta pipelines1	22	22	67	69
Liquids marketing and other	38	48	123	110
Comparable EBITDA	387	415	1,146	1,292
Depreciation and amortization	(80)	(82)	(238)	(249)
Comparable EBIT	307	333	908	1,043
Specific items:
Keystone XL asset impairment charge and other	—	—	(2,854)	—
Keystone XL preservation and other	(14)	—	(29)	—
Risk management activities	(8)	9	2	16
Segmented earnings/(losses)	285	342	(1,973)	1,059
Comparable EBITDA denominated as follows:
Canadian dollars	106	102	310	311
U.S. dollars	223	235	668	724
Foreign exchange impact	58	78	168	257
Comparable EBITDA	387	415	1,146	1,292

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

Liquids Pipelines segmented earnings decreased by $57 million and $3.0 billion for the three and nine months ended September 30, 2021 compared to the same periods in 2020 and included the following specific items which have been excluded from our calculation of comparable EBIT and comparable earnings:

•a $2.8 billion pre-tax asset impairment charge, net of expected contractual recoveries and other contractual and legal obligations, for the nine months ended September 30, 2021, associated with the termination of the Keystone XL pipeline and related projects following the January 20, 2021 revocation of the Presidential Permit. Refer to the Recent developments – Liquids Pipelines section for additional information

•pre-tax preservation and other costs of $14 million and $29 million for the three and nine months ended September 30, 2021 primarily related to the preservation and storage of the Keystone XL pipeline project assets which could not be accrued as part of the Keystone XL impairment charge

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

A weaker U.S. dollar in 2021 had a negative impact on the Canadian dollar equivalent segmented earnings from our U.S. operations compared to the same periods in 2020. Refer to the Consolidated results – Foreign exchange section for additional information.

TC Energy Third Quarter 2021 | 21

Comparable EBITDA for Liquids Pipelines decreased by $28 million and $146 million for the three and nine months ended September 30, 2021 compared to the same periods in 2020 and was primarily due to the net effect of:

•lower volumes on the U.S. Gulf Coast section of the Keystone Pipeline System for the nine months ended September 30, 2021

•lower contributions from liquids marketing activities for the three months ended September 30, 2021 mainly attributable to lower margins. Earnings for the nine months ended September 30, 2021 from liquids marketing increased due to higher margins and volumes.

DEPRECIATION AND AMORTIZATION

Depreciation and amortization decreased by $2 million and $11 million for the three and nine months ended September 30, 2021 compared to the same periods in 2020 primarily as a result of a weaker U.S. dollar.

22 | TC Energy Third Quarter 2021

Power and Storage

The following is a reconciliation of comparable EBITDA and comparable EBIT (our non-GAAP measures) to segmented earnings (the most directly comparable GAAP measure).

	three months ended<br>September 30		nine months ended <br>September 30
(millions of $)	2021	2020	2021	2020
Bruce Power1	112	140	296	339
Canadian Power2	50	39	176	164
Natural Gas Storage and other	6	8	34	13
Comparable EBITDA	168	187	506	516
Depreciation and amortization	(20)	(18)	(58)	(48)
Comparable EBIT	148	169	448	468
Specific items:
(Loss)/gain on sale of Ontario natural gas-fired power plants	—	(60)	17	(321)
Risk management activities	(32)	(4)	(28)	(9)
Segmented earnings	116	105	437	138

1Represents our share of equity income from Bruce Power.

2Includes Napanee from in-service in March 2020 and our other Ontario natural gas-fired power plants until sold in April 2020.

Power and Storage segmented earnings increased by $11 million and $299 million for the three and nine months ended September 30, 2021 compared to the same periods in 2020 and included the following specific items which have been excluded from comparable EBIT:

•a $17 million pre-tax recovery of certain costs from the IESO in second quarter 2021 associated with the Ontario natural gas-fired power plants sold in April 2020. Pre-tax losses on the sale of $60 million and $321 million were recorded in the three and nine months ended September 30, 2020

•unrealized losses from changes in the fair value of derivatives used to reduce commodity exposures in our Power and Storage business.

Comparable EBITDA for Power and Storage decreased by $19 million and $10 million for the three and nine months ended September 30, 2021 compared to the same periods in 2020 primarily due to the net effect of:

•decreased contributions from Bruce Power due to lower volumes resulting from greater planned outage days and increased operating expenses, partially offset by higher realized power prices. Earnings for the nine months ended September 30, 2021 also included increased gains on funds invested for post-retirement benefits. Additional financial and operating information on Bruce Power is provided below

•Natural Gas Storage and other results reflecting higher realized Alberta natural gas storage spreads in 2021 and the November 2020 acquisition of the remaining 50 per cent ownership interest in TC Turbines. Results for the three months ended September 30, 2021 also included higher business development activities across the segment

•increased Canadian Power results primarily due to higher realized margins in 2021 and earnings from our MacKay River cogeneration facility following its return to service in May 2020, partially offset by the sale of our Ontario natural gas-fired power plants in April 2020.

DEPRECIATION AND AMORTIZATION

Depreciation and amortization increased by $2 million and $10 million for the three and nine months ended September 30, 2021 compared to the same periods in 2020 and includes incremental TC Turbines depreciation following the November 2020 acquisition of the remaining 50 per cent ownership interest as well as other adjustments in second quarter 2020.

TC Energy Third Quarter 2021 | 23

BRUCE POWER

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

	three months endedSeptember 30		nine months ended September 30
(millions of $, unless otherwise noted)	2021	2020	2021	2020
Equity income included in comparable EBITDA and EBIT comprised of:
Revenues1	411	432	1,220	1,270
Operating expenses	(214)	(206)	(677)	(653)
Depreciation and other	(85)	(86)	(247)	(278)
Comparable EBITDA and EBIT2	112	140	296	339
Bruce Power – other information
Plant availability3,4	86	93	86	88
Planned outage days4	92	26	257	195
Unplanned outage days	—	16	22	28
Sales volumes (GWh)2	5,101	5,510	15,197	15,818
Realized power price per MWh5	80	78	80	80

All values are in US Dollars.

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

2Represents our 48.4 per cent ownership interest in Bruce Power. Sales volumes include deemed generation and Unit 6 output until January 2020 when its MCR program commenced.

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

4Excludes Unit 6 MCR outage days.

5Calculation 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.

The Unit 6 MCR outage commenced in January 2020. Planned maintenance was completed on Unit 1 in first quarter 2021 and on Unit 3 on October 9, 2021. Refer to the Recent developments – Power and Storage section for additional information. Planned maintenance is still expected to occur on Unit 7 in fourth quarter 2021. The average 2021 plant availability, excluding the Unit 6 MCR, is expected to be in the mid-80 per cent range.

24 | TC Energy Third Quarter 2021

Corporate

The following is a reconciliation of comparable EBITDA and comparable EBIT (our non-GAAP measures) to Corporate segmented (losses)/earnings (the most directly comparable GAAP measure).

	three months ended<br>September 30		nine months ended <br>September 30
(millions of $)	2021	2020	2021	2020
Comparable EBITDA and EBIT	(7)	(7)	(14)	(3)
Specific items:
Voluntary Retirement Program (VRP)	(71)	—	(71)	—
Foreign exchange gain/(loss) – inter-affiliate loans1	42	(54)	45	223
Segmented (losses)/earnings	(36)	(61)	(40)	220

1Reported in Income from equity investments in the Condensed consolidated statement of income.

Corporate segmented losses decreased by $25 million for the three months ended September 30, 2021 while Corporate segmented earnings decreased by $260 million for the nine months ended September 30, 2021 compared to the same periods in 2020. Corporate segmented losses included accrued pre-tax costs for the VRP offered in mid-2021 as well as foreign exchange gains and losses on our proportionate share of peso-denominated inter-affiliate loans to the Sur de Texas joint venture from its partners. These foreign exchange gains and losses are recorded in Income from equity investments in the Corporate segment and have been excluded from our calculation of comparable EBITDA and EBIT as they are fully offset by corresponding foreign exchange losses and gains on the inter-affiliate loan receivable included in Interest income and other. Refer to the Recent developments – Corporate section for additional information on the VRP and Financial risks and financial instruments – Related party transactions section for additional information on our peso-denominated inter-affiliate loans.

Comparable EBITDA and EBIT for Corporate for the three months ended September 30, 2021 was consistent with the same period in 2020 and decreased by $11 million for the nine months ended September 30, 2021 compared to the same period in 2020 primarily due to a U.S. capital tax adjustment recorded in second quarter 2020.

Interest expense

	three months ended<br>September 30		nine months ended <br>September 30
(millions of $)	2021	2020	2021	2020
Interest on long-term debt and junior subordinated notes
Canadian dollar-denominated	(183)	(178)	(530)	(511)
U.S. dollar-denominated	(315)	(324)	(945)	(987)
Foreign exchange impact	(81)	(108)	(238)	(350)
	(579)	(610)	(1,713)	(1,848)
Other interest and amortization expense	(19)	(17)	(50)	(69)
Capitalized interest	2	68	20	219
Interest expense included in comparable earnings	(596)	(559)	(1,743)	(1,698)
Specific item:
Keystone XL preservation and other	—	—	(6)	—
Interest expense	(596)	(559)	(1,749)	(1,698)

TC Energy Third Quarter 2021 | 25

Interest expense increased by $37 million and $51 million for the three and nine months ended September 30, 2021 compared to the same periods in 2020 and included $6 million for the nine months ended September 30, 2021 related to the Keystone XL project-level credit facility for the period following the revocation of the Presidential Permit for the Keystone XL pipeline. This has been removed from our calculation of interest expense included in comparable earnings.

Interest expense included in comparable earnings increased by $37 million and $45 million for the three and nine months ended September 30, 2021 compared to the same periods in 2020 primarily due to the net effect of:

•lower capitalized interest due to its cessation for the Keystone XL pipeline project following the revocation of the Presidential Permit in January 2021, the change to equity accounting for our Coastal GasLink investment upon the sale of a 65 per cent interest in Coastal GasLink LP in second quarter 2020 and the completion of the Napanee power plant in first quarter 2020

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

•lower interest rates on short-term borrowings

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

Allowance for funds used during construction

	three months ended<br>September 30		nine months ended <br>September 30
(millions of $)	2021	2020	2021	2020
Canadian dollar-denominated	40	23	104	83
U.S. dollar-denominated	33	51	73	126
Foreign exchange impact	8	17	18	45
Allowance for funds used during construction	81	91	195	254

AFUDC decreased by $10 million and $59 million for the three and nine months ended September 30, 2021 compared to the same periods in 2020. The increases in Canadian dollar-denominated AFUDC are primarily related to a higher balance of NGTL System expansion projects under construction. The decreases in U.S. dollar-denominated AFUDC are mainly the result of the suspension of recording AFUDC on the Villa de Reyes project effective January 1, 2021 due to ongoing delays on the project and the Columbia Gas BXP project which went into service on January 1, 2021, partially offset by increased capital expenditures on our U.S. natural gas pipeline projects.

Interest income and other

	three months ended<br>September 30		nine months ended <br>September 30
(millions of $)	2021	2020	2021	2020
Interest income and other included in comparable earnings	91	32	341	87
Specific items:
Foreign exchange (losses)/gains – inter-affiliate loan	(42)	54	(45)	(223)
Risk management activities	(125)	78	(183)	(24)
Interest income and other	(76)	164	113	(160)

Interest income and other decreased by $240 million and increased by $273 million for the three and nine months ended September 30, 2021 compared to the same periods in 2020 and included the following specific items which have been removed from our calculation of Interest income and other included in comparable earnings:

•foreign exchange losses and gains on the peso-denominated inter-affiliate loan receivable from the Sur de Texas joint venture

•unrealized losses and gains from changes in the fair value of derivatives used to manage our foreign exchange risk.

26 | TC Energy Third Quarter 2021

Our proportionate share of the corresponding foreign exchange gains and losses and interest expense on the peso-denominated inter-affiliate loans to the Sur de Texas joint venture from its partners are reflected in Income from equity investments in the Corporate and Mexico Natural Gas Pipelines segments, respectively. The foreign exchange losses and gains on these inter-affiliate loans are removed from comparable earnings while the interest income and interest expense are included in comparable earnings with all amounts offsetting and resulting in no impact on net income. Refer to the Financial risks and financial instruments – Related Party Transactions section for additional information.

Interest income and other included in comparable earnings increased by $59 million and $254 million for the three and nine months ended September 30, 2021 compared to the same periods in 2020 mainly due to realized gains in 2021 compared to realized losses in 2020 on derivatives used to manage our net exposure to foreign exchange rate fluctuations on U.S. dollar-denominated income.

Income tax expense

	three months ended<br>September 30		nine months ended <br>September 30
(millions of $)	2021	2020	2021	2020
Income tax expense included in comparable earnings	(195)	(184)	(574)	(520)
Specific items:
Keystone XL asset impairment charge and other1	—	—	660	—
Keystone XL preservation and other1	3	—	8	—
Voluntary Retirement Program	16	—	16	—
Income tax valuation allowance release	—	—	—	281
Loss/(gain) on sale of Ontario natural gas-fired power plants	—	15	(4)	119
Gain on partial sale of Coastal GasLink LP	—	—	—	38
Risk management activities	41	(21)	52	4
Income tax (expense)/recovery	(135)	(190)	158	(78)

1Includes $3 million of deferred income tax recovery and $nil of current income tax expense for the three months ended September 30, 2021 and $788 million of deferred income tax recovery and $120 million of current income tax expense for the nine months ended September 30, 2021.

Income tax expense decreased by $55 million for the three months ended September 30, 2021 compared to the same period in 2020 primarily due to reduced earnings in 2021.

Income tax expense decreased by $236 million for the nine months ended September 30, 2021 to a recovery of $158 million compared to the same period in 2020 primarily due to the net effect of:

•the income tax impact of the Keystone XL pipeline project asset impairment charge in 2021

•the income tax valuation allowance release of $281 million which was recorded in first quarter 2020 following our reassessment of deferred income tax assets that were deemed more likely than not to be realized

•an income tax valuation allowance release related to the Ontario natural gas-fired power plants and Coastal GasLink LP sale transactions in 2020

•the non-taxable portion of capital gains recognized in second quarter 2020.

These items were removed from Income tax expense included in comparable earnings in addition to the income tax impacts of the specific items referenced elsewhere in this MD&A.

Income tax expense included in comparable earnings increased by $11 million for the three months ended September 30, 2021 compared to the same period in 2020 primarily due to higher income subject to tax in 2021, partially offset by higher foreign tax rate differentials. Income tax expense included in comparable earnings increased by $54 million for the nine months ended September 30, 2021 compared to the same period in 2020 primarily due to higher earnings subject to tax and higher flow-through income taxes on Canadian rate-regulated pipelines, partially offset by higher foreign tax rate differentials.

TC Energy Third Quarter 2021 | 27

Net income attributable to non-controlling interests

	three months ended<br>September 30		nine months ended <br>September 30
(millions of $)	2021	2020	2021	2020
Net income attributable to non-controlling interests	(8)	(69)	(83)	(228)

Net income attributable to non-controlling interests for the three and nine months ended September 30, 2021 decreased by $61 million and $145 million compared to the same periods in 2020 primarily as a result of the March 3, 2021 acquisition of all outstanding common units of TC PipeLines, LP not beneficially owned by TC Energy. Subsequent to the acquisition, TC PipeLines, LP became an indirect, wholly-owned subsidiary of TC Energy. Refer to the U.S. Natural Gas Pipelines section and Note 10, Non-controlling interests, of our Condensed consolidated financial statements for additional information.

Preferred share dividends

	three months ended<br>September 30		nine months ended <br>September 30
(millions of $)	2021	2020	2021	2020
Preferred share dividends	(31)	(39)	(108)	(120)

Preferred share dividends decreased by $8 million and $12 million for the three and nine months ended September 30, 2021 compared to the same periods in 2020 primarily due to the redemption of all issued and outstanding Series 13 preferred shares on May 31, 2021.

28 | TC Energy Third Quarter 2021

Recent developments

COVID-19

Amid the ongoing adaptations and restrictions in place as a result of the COVID-19 pandemic, we continue to effectively operate our assets, conduct commercial activities and execute on projects with a focus on health, safety and reliability. While it remains premature to ascertain any long-term impact that COVID-19 may have on our capital program, directionally we have observed some slowdown on certain of our construction activities and capital expenditures largely due to permitting delays as regulators have been unable to process permits and conduct consultations within timeframes that were originally anticipated. In addition, supply chain impacts are manifesting with rising costs for certain commodities and labour shortages in some areas which can cause cost increases and slower progress than anticipated. Further details for capital projects more significantly impacted by COVID-19 are provided below.

The degree to which COVID-19 has a more pronounced longer-term impact on our operations and growth projects will depend on future developments, policies and actions, all of which remain somewhat uncertain. Additional information regarding the risks, uncertainties and impact on our business from COVID-19 can be found throughout this MD&A including the Capital program, Outlook and the Financial risks and financial instruments sections.

CANADIAN NATURAL GAS PIPELINES

Coastal GasLink

From late December 2020 until April 13, 2021, in response to the COVID-19 pandemic, an order of the British Columbia Provincial Health Officer restricted the number of workers on industrial sites across northern British Columbia, including Coastal GasLink, and, as a result, only critical construction activities continued during this time. Major erosion and sediment control work was required in the absence of continued pipeline construction during the winter period. On April 13, 2021, the provincial health order was lifted allowing the project to finalize remobilization plans for the summer construction program.

As a result of scope changes, previous permit delays compared to the original construction schedule and the impacts from COVID-19, including the provincial health order, we continue to expect project costs to increase significantly along with a delay to project completion compared to the original project cost and schedule. Coastal GasLink has sought and will continue to mitigate cost increases and schedule delays. Coastal GasLink expects incremental costs will be included in the final pipeline tolls, subject to certain conditions.

Coastal GasLink is in dispute with LNG Canada with respect to the recognition of certain costs and the impacts on schedule. Construction activities continue and, at this time, we do not expect any suspension of these activities while the parties work toward a resolution. During this time, construction is being funded in part by a subordinated demand revolving facility with TC Energy which provides the project with additional short-term funding and financial flexibility and, on which, $840 million was drawn at September 30, 2021. In October 2021, this amount was fully repaid and further draws were made which resulted in an outstanding balance of $175 million at October 29, 2021. As a further interim measure, TC Energy has committed to providing additional temporary financing to the project, if necessary, of up to $3.3 billion as a bridge to a required increase in project-level financing to fund incremental costs. This financing is expected to be provided at market-based returns. While we do not anticipate our future equity contributions will increase significantly, the portion of this temporary financing that will ultimately be required to be contributed as equity by Coastal GasLink LP partners, including us, will be determined by the substance of a resolution with LNG Canada.

TC Energy Third Quarter 2021 | 29

NGTL System

In the nine months ended September 30, 2021, the NGTL System placed approximately $0.5 billion of capacity projects in service.

2022 NGTL System Expansion Program

In second quarter 2021, we received federal approval for the 2022 NGTL System Expansion Program. With an estimated capital cost of $1.1 billion, the 2022 NGTL System Expansion Program will provide incremental capacity to meet firm-receipt and intra-basin delivery requirements and consist of approximately 166 km (103 miles) of new pipeline, one new compressor unit and associated facilities. Construction activities began in September 2021 with anticipated in-service dates commencing in fourth quarter 2022.

2023 NGTL System Intra-Basin Expansion

In May 2021, we received CER approval to construct and operate $0.3 billion of the NGTL System Intra-Basin Expansion Program. An application for the remaining facilities was submitted to the CER in June 2021 with a decision anticipated in late 2021. Based on the outcome of the 2021 Capacity Optimization Open Season, changes in expected supply have reduced the scope of the program which now has an estimated capital cost of $0.6 billion, consisting of 23 km (14 miles) of new pipeline and two new compressor stations and is underpinned by approximately 255 TJ/d (238 MMcf/d) of new firm-service contracts with 15-year terms. The Intra-Basin Expansion is expected to be placed in service commencing in 2023.

NGTL System/Foothills West Path Delivery Program

In November 2019, we announced our West Path Delivery Program which is an expansion of the NGTL System and Foothills for contracted incremental export capacity on GTN. The Canadian portion of the expansion program has an estimated capital cost of $1.2 billion and consists of approximately 108 km (67 miles) of pipeline and associated facilities with in-service dates in fourth quarter 2022 and fourth quarter 2023. The program is underpinned by approximately 275 TJ/d (258 MMcf/d) of new firm-service contracts with terms that exceed 30 years. Applications to construct and operate $0.2 billion of the facilities received CER approval in April 2021 and applications for the remaining facilities have been submitted, with federal approvals anticipated in fourth quarter 2022.

U.S. NATURAL GAS PIPELINES

Columbia Gas Section 4 Rate Case

Columbia Gas filed a Section 4 Rate Case with FERC in July 2020 requesting an increase to its maximum transportation rates effective February 1, 2021, subject to refund upon completion of the rate proceeding. On July 28, 2021, Columbia Gas notified FERC that it reached a settlement-in-principle with its customers addressing all remaining issues in the case, including but not limited to the resolution of rates and continuation of Columbia Gas's modernization program. On October 29, 2021, Columbia Gas filed its settlement with FERC, and is now awaiting Commission approval, with 2021 revenues expected to be generally consistent with estimates recorded to date. We expect FERC approval of the settlement in early 2022.

GTN Rate Case Settlement

On September 29, 2021, GTN filed an uncontested rate settlement which would set new recourse rates for GTN effective January 1, 2022 and institute a rate moratorium through December 31, 2023. The revised rates are not expected to have a significant impact on our U.S. Natural Gas Pipelines segment comparable earnings. In addition, GTN must file for new rates no later than April 1, 2024.

Acquisition of TC PipeLines, LP

On March 3, 2021, we completed the previously announced acquisition pursuant to the agreement dated December 14, 2020. Refer to the Recent developments – Corporate section for additional information.

Grand Chenier XPress

Phase I of Grand Chenier XPress, an expansion project on ANR connecting supply directly to U.S. Gulf Coast LNG export facilities, went into service in April 2021. Phase II is expected to be placed in service in early 2022.

30 | TC Energy Third Quarter 2021

Delivery Market Projects

We are actively developing projects that will replace and upgrade certain facilities while reducing emissions along portions of our pipeline systems in principal delivery markets. The enhanced facilities will improve reliability of the systems and allow for additional transportation services to address growing demand under long-term contracts while reducing direct carbon dioxide equivalent (CO2e) emissions. Consistent with this initiative, the VR project on Columbia Gas has been sanctioned, subject to customary conditions precedent and normal-course regulatory approvals. This project represents an approximate US$0.7 billion capital investment and is targeted to be placed in service during the second half of 2025. In addition, the WR project on ANR has also been sanctioned and will serve markets in the midwestern U.S. This project has an estimated capital cost of approximately US$0.8 billion and is expected to be placed in service in fourth quarter 2025.

MEXICO NATURAL GAS PIPELINES

Tula and Villa de Reyes

The CFE initiated arbitration in June 2019 for the Tula and Villa de Reyes projects, disputing fixed capacity payments due to force majeure events. Arbitration proceedings are currently suspended through December 31, 2021 while management advances settlement discussions with the CFE.

Villa de Reyes construction is ongoing but completion has been delayed due to COVID-19 contingency measures and challenges gaining access to land in certain local communities. Management is working closely with state and local governments to complete negotiations and achieve access to land so that construction can be completed. We expect to reach partial in-service by the end of 2021, with the remainder of the construction of Villa de Reyes completed in the first half of 2022.

LIQUIDS PIPELINES

Keystone XL

On June 9, 2021, following the revocation of the Presidential Permit for the Keystone XL pipeline project on January 20, 2021, and after a comprehensive review of options in consultation with our partner, the Government of Alberta, we terminated the Keystone XL pipeline project.

The Keystone XL investment was evaluated for impairment in first quarter 2021 along with our investments in related capital projects including Heartland Pipeline, TC Terminals and Keystone Hardisty Terminal. We determined that the carrying amount of these assets was no longer fully recoverable. As a result, we recognized an asset impairment charge, net of expected contractual recoveries and other contractual and legal obligations related to termination activities, of $2.8 billion ($2.2 billion after tax) for the nine months ended September 30, 2021, which was excluded from comparable earnings. The asset impairment charge was based on the excess of the carrying value of $3.3 billion over the estimated fair value of $0.2 billion. Termination activities and related costs will continue through 2022 with any adjustments to the estimated fair value and future contractual and legal obligations expensed as determined and excluded from comparable earnings. Refer to Note 5, Keystone XL, of our Condensed consolidated financial statements for additional information.

TC Energy Third Quarter 2021 | 31

Although we recorded a $2.2 billion after-tax asset impairment charge, net of expected contractual recoveries and other contractual and legal obligations related to the Keystone XL pipeline project termination activities, a significant portion of this amount was shared with the Government of Alberta, thereby reducing the net financial impact to TC Energy. In June 2021, Class A Interests previously issued to the Government of Alberta totaling $394 million were repurchased for a nominal amount, the $1.0 billion (US$849 million) balance on the credit facility was guaranteed and fully paid by the Government of Alberta and $91 million of Class C Interests were issued to the Government of Alberta entitling them to future liquidation proceeds from specified Keystone XL project assets. After considering these transactions, including the income tax impact thereon, the net financial impact to us as a result of the termination of Keystone XL and related projects at September 30, 2021 was $1.1 billion determined as follows:

(millions of $)	September 30, 2021
Asset impairment charge and other (after tax)1	2,194
Government of Alberta Class A Interests repurchased for a nominal amount2	(394)
Credit facility balance – guaranteed and paid by the Government of Alberta (net) 2,3	(737)
Net financial impact of the termination of the Keystone XL pipeline project	1,063

1Refer to Note 5, Keystone XL, of our Condensed consolidated financial statements for additional information.

2Recognized through the Condensed consolidated statement of equity.

3Net of income taxes and Class C Interests issued.

After the Presidential Permit was revoked, construction activities ceased except for certain activities required to clean up and reclaim worksites in adherence to our commitment to safety, the environment, and our regulatory requirements. We will continue to coordinate with regulators, stakeholders and Indigenous groups to meet our environmental and regulatory commitments and ensure a safe exit from the Keystone XL pipeline project. The majority of these associated costs were funded through a final drawdown on the project-level credit facility which occurred in June 2021, subsequent to which the credit facility was fully repaid by the Government of Alberta and terminated.

We continue to manage legacy challenges to the 2019 Presidential Permit and the Bureau of Land Management Grant of Right-of-Way, which remain pending before the federal district court in Montana, in a manner consistent with the termination of the project.

On July 2, 2021, TC Energy filed a Notice of Intent to 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. We will be seeking to recover more than US$15 billion in damages as a result of the U.S. Government's breach of its NAFTA obligations. This claim is in a preliminary stage and the timing of outcome is unknown at present.

Northern Courier

On September 16, 2021, we announced the sale of our remaining 15 per cent equity interest in Northern Courier Pipeline to Astisiy Limited Partnership, comprised of Suncor and eight Indigenous communities in the Regional Municipality of Wood Buffalo, for gross proceeds of approximately $30 million before post-closing adjustments. The transaction is anticipated to close in fourth quarter 2021, subject to customary closing conditions and the receipt of the required regulatory approvals.

Port Neches

On March 8, 2021, we entered a joint venture with Motiva Enterprises (Motiva) to construct the US$152 million Port Neches Link pipeline system which will connect the Keystone Pipeline System to Motiva’s Port Neches Terminal which supplies 630,000 Bbl/d to their Port Arthur refinery. This common carrier pipeline system will also include facilities to tie in additional liquids terminals to the Keystone Pipeline System with other downstream infrastructure and is expected to be in service in the second half of 2022.

32 | TC Energy Third Quarter 2021

POWER AND STORAGE

Sharp Hills Wind Power Purchase Agreement

On September 20, 2021, we executed a 15-year PPA for 100 per cent of the power produced and the rights to all environmental attributes from the 297 MW Sharp Hills Wind Farm located in eastern Alberta. The Sharp Hills Wind Farm is anticipated to be operational in 2023, subject to customary regulatory approvals and conditions.

Bruce Power Outage

As part of the planned inspections, testing, analysis and maintenance activities at Bruce Power during the current Unit 6 MCR outage and the recently completed Unit 3 planned outage, higher than anticipated readings of hydrogen concentration in pressure tubes were detected. These readings were limited to a very small area of the respective pressure tubes and did not impact safety nor pressure tube integrity as concluded following an assessment of all of the Bruce Power units. On October 9, 2021, Unit 3 returned to service after the Canadian Nuclear Safety Commission approved Bruce Power's restart request following extensive inspections which demonstrated that safety and pressure tube integrity continued to meet regulatory requirements. Bruce Power will be incorporating additional inspections as part of their normal surveillance programs to address the new findings while progressing further programs that demonstrate fitness for service at elevated hydrogen concentration levels.

Bruce Power Life Extension

The Unit 6 MCR program continues on budget and on schedule. The program is nearing the end of the Inspection Phase and is about to enter the Installation Phase. Preparation of the Unit 3 MCR program, which is the next scheduled MCR outage, continues and Bruce Power expects to submit its final cost and schedule duration estimate to the IESO in fourth quarter 2021.

Bruce Power Uprate Initiative

Bruce Power recently launched Project 2030 with the goal of achieving a site peak output of 7,000 MW by 2030 in support of climate change targets and future clean energy needs. Project 2030 will focus on continued asset optimization, innovation and leveraging new technology, which could include integration with storage and other forms of energy, to increase the site peak output at Bruce Power.

Ontario Pumped Storage Project

As part of our strategy to capture opportunities that capitalize on the transition to a less carbon-intensive energy mix, we are developing a 1,000 MW pumped hydro storage project in Meaford, Ontario near Bruce Power. Once complete, this facility is designed to provide emission-free electricity to the province while reducing greenhouse gas emissions by an expected 490,000 tonnes and delivering more than $250 million in annual electricity savings to Ontario ratepayers. On July 28, 2021, we reached an agreement with the Department of National Defence that, subject to conditions and regulatory approval, allows for the development of this project on the Meaford base. We will continue to consult with the Saugeen Ojibway Nation, other Indigenous Rightsholders and communities along with other local stakeholders as we continue to advance this project, which remains subject to a number of conditions and approvals, including approval of our Board of Directors.

Renewable Energy Requests for Information (RFI)

Through an RFI process in second quarter 2021, we announced that we were seeking to identify potential contracts and/or investment opportunities in up to 620 MW of wind energy projects, 300 MW of solar projects and 100 MW of energy storage projects to meet the electricity needs of a portion of our U.S. pipeline assets. The project team is currently evaluating proposals, has commenced negotiations and expects to finalize contracts by the end of the year.

OTHER ENERGY TRANSITION DEVELOPMENTS

Alberta Carbon Grid

On June 17, 2021, we announced a partnership with Pembina Pipeline Corporation to jointly develop a carbon transportation and sequestration system which, when fully constructed, would be capable of transporting more than 20 million tonnes of CO2 annually. By leveraging existing pipelines and a newly developed sequestration hub, the Alberta Carbon Grid (ACG) is

TC Energy Third Quarter 2021 | 33

expected to provide an infrastructure platform for Alberta-based industries to manage their emissions and contribute to a lower-carbon economy. Designed to be an open-access system, the ACG would connect the Fort McMurray, Alberta Industrial Heartland and Drayton Valley regions to key sequestration locations and delivery points across the province.

Irving Oil Decarbonization

On August 12, 2021, we signed a memorandum of understanding to explore the joint development of a series of proposed energy projects focused on reducing greenhouse gas emissions and creating new economic opportunities in New Brunswick and Atlantic Canada. Together with Irving Oil, we have identified a series of potential projects for exploration focused on decarbonizing current assets and deploying emerging technologies to reduce overall emissions. The partnership’s initial focus will consider a suite of upgrade projects at Irving Oil’s refinery in Saint John, New Brunswick, with the goal of significantly reducing emissions through the production and use of low-carbon power generation.

Hydrogen Hubs

On October 7, 2021, we announced a partnership with Nikola Corporation to collaborate on developing, constructing, operating and owning large-scale hydrogen production facilities (hubs) in the United States and Canada. We are actively collaborating to identify and develop projects to establish the infrastructure required to deliver low-cost and low-carbon hydrogen at scale in line with each company’s core objectives. Both parties desire to accelerate the adoption of heavy-duty zero-emission fuel cell electric vehicles (FCEVs) and hydrogen across industrial sectors by establishing hubs in key geographic locations.

A key objective of the collaboration is to establish hubs producing 150 tonnes or more of hydrogen per day near highly traveled truck corridors to serve Nikola’s planned need for hydrogen to fuel its Class 8 FCEVs within the next five years. Our significant pipeline, storage and power assets can potentially be leveraged to lower the cost and increase the speed of delivery of these hubs. This may include exploring the integration of midstream assets to enable hydrogen distribution and storage via pipeline and/or to deliver carbon dioxide to permanent sequestration sites to decarbonize the hydrogen production process.

CORPORATE

Voluntary Retirement Program

In mid-2021, we offered a one-time VRP to eligible employees. Participants in the program will retire by December 31, 2021 and receive a transition payment in addition to existing retirement benefits. For the three and nine months ended September 30, 2021, we have expensed a total of $89 million before tax, mainly related to the VRP transition payments, which was included in Plant operating costs and other. Of the total program costs, $71 million was excluded from comparable earnings and $18 million was recorded in Revenues related to costs that are recoverable through regulatory and tolling structures on a flow-through basis.

Retirement and Appointment of our Executive Vice-President and CFO

On May 17, 2021, we announced that Don Marchand, Executive Vice-President and Chief Financial Officer (CFO), will retire from TC Energy on November 1, 2021. Mr. Marchand stepped down as CFO on July 31, 2021 and Joel Hunter, previously Senior Vice-President, Capital Markets, succeeded Mr. Marchand as Executive Vice-President and CFO as of August 1, 2021.

Acquisition of TC PipeLines, LP

On March 3, 2021, we completed the acquisition of all of the outstanding common units of TC PipeLines, LP not beneficially owned by TC Energy, resulting in TC PipeLines, LP becoming an indirect, wholly-owned subsidiary of TC Energy. Upon close of the transaction and in accordance with the acquisition terms, TC PipeLines, LP common unitholders received 0.70 common shares of TC Energy for each issued and outstanding publicly-held TC PipeLines, LP common unit resulting in the issuance of 38 million TC Energy common shares valued at approximately $2.1 billion, net of transaction costs. Refer to Note 10, Non-controlling interests, of our Condensed consolidated financial statements for additional information.

34 | TC Energy Third Quarter 2021

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 to meet our financing needs, manage our capital structure and to preserve our credit ratings.

We believe we have the financial capacity to fund our existing capital program through predictable and growing cash flows from operations, access to capital markets, portfolio management, joint ventures, asset-level financing, cash on hand and substantial committed credit facilities. Annually, in fourth quarter, we renew and extend our credit facilities as required.

At September 30, 2021, our current assets totaled $8.7 billion and current liabilities amounted to $17.0 billion, leaving us with a working capital deficit of $8.3 billion compared to $6.8 billion at December 31, 2020. Our working capital deficiency is considered to be in the normal course of business and is managed through:

•our ability to generate predictable and growing cash flows from operations

•a total of $10.0 billion of committed revolving credit facilities, of which $7.0 billion of short-term borrowing capacity remains available, net of $3.0 billion backstopping outstanding commercial paper balances. We also have arrangements in place for a further $2.4 billion of demand credit facilities of which $1.1 billion remained available as at September 30, 2021

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

CASH PROVIDED BY OPERATING ACTIVITIES

	three months ended<br>September 30		nine months ended <br>September 30
(millions of $)	2021	2020	2021	2020
Net cash provided by operations	1,712	1,783	5,089	5,119
(Decrease)/increase in operating working capital	(227)	(120)	32	187
Funds generated from operations	1,485	1,663	5,121	5,306
Specific items:
Current income tax expense on Keystone XL asset impairment charge, preservation and other	—	—	120	—
Keystone XL preservation and other	14	—	35	—
Voluntary Retirement Program	71	—	71	—
Current income tax recovery on Voluntary Retirement Program	(14)	—	(14)	—
Comparable funds generated from operations	1,556	1,663	5,333	5,306

Net Cash Provided by Operations

Net cash provided by operations decreased by $71 million and $30 million for the three and nine months ended September 30, 2021 compared to the same periods in 2020 primarily due to lower funds generated from operations, partially offset by the amount 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 decreased by $107 million for the three months ended September 30, 2021 compared to the same period in 2020 primarily due to lower comparable EBITDA, higher current income taxes and lower distributions from the operating activities of our equity investments, partially offset by realized gains in 2021 compared to realized losses in 2020 on derivatives used to manage our net exposure to foreign exchange rate fluctuations on U.S. dollar-denominated income.

TC Energy Third Quarter 2021 | 35

Comparable funds generated from operations increased by $27 million for the nine months ended September 30, 2021 compared to the same period in 2020 primarily due to higher comparable earnings, including realized gains in 2021 compared to realized losses in 2020 on derivatives used to manage our net exposure to foreign exchange rate fluctuations on U.S. dollar-denominated income. This increase was partially offset by fees collected in 2020 associated with the successful completion of the Sur de Texas pipeline and lower distributions from the operating activities of our equity investments in 2021.

CASH USED IN INVESTING ACTIVITIES

	three months ended<br>September 30		nine months ended <br>September 30
(millions of $)	2021	2020	2021	2020
Capital spending
Capital expenditures	(1,446)	(2,063)	(4,305)	(6,049)
Capital projects in development	—	—	—	(122)
Contributions to equity investments	(241)	(187)	(706)	(498)
	(1,687)	(2,250)	(5,011)	(6,669)
Proceeds from sale of assets, net of transaction costs	—	—	—	3,407
Loan to affiliate	(620)	(250)	(840)	(250)
Deferred amounts and other	(66)	(137)	(470)	(359)
Net cash used in investing activities	(2,373)	(2,637)	(6,321)	(3,871)

Capital expenditures in 2021 were incurred primarily for the expansion of the NGTL System, ANR and Columbia Gas projects as well as maintenance capital expenditures. Lower capital spending in 2021 compared to 2020 reflected reduced spending on Columbia Gas projects, the sale of a 65 per cent equity interest in and subsequent equity accounting for Coastal GasLink LP in second quarter 2020, along with the termination of the Keystone XL pipeline project following the January 20, 2021 revocation of the Presidential Permit, partially offset by higher capital spending on ANR.

Costs incurred on capital projects in development in 2020 were mostly attributable to spending on the Keystone XL pipeline project prior to its reclassification to Plant, property and equipment upon reaching a positive final investment decision in March 2020.

Contributions to equity investments increased in 2021 compared to 2020 mainly due to higher investment in Bruce Power.

In second quarter 2020, we closed the sale of our Ontario natural gas-fired power plants for net proceeds of approximately $2.8 billion and the sale of a 65 per cent equity interest in Coastal GasLink LP for net proceeds of $656 million.

TC Energy entered into a subordinated demand revolving credit facility with Coastal GasLink LP to provide additional short-term liquidity and funding flexibility to the project. During the nine months ended September 30, 2021, $840 million was drawn on this facility. In October 2021, this amount was fully repaid and further draws were made which resulted in an outstanding balance of $175 million at October 29, 2021. Refer to Note 7, Loans receivable from affiliates, of our Condensed consolidated financial statements for additional information.

36 | TC Energy Third Quarter 2021

CASH PROVIDED BY FINANCING ACTIVITIES

	three months ended<br>September 30		nine months ended <br>September 30
(millions of $)	2021	2020	2021	2020
Notes payable issued/(repaid), net	1,448	338	(1,012)	(2,765)
Long-term debt issued, net of issue costs	47	35	7,798	5,571
Long-term debt repaid	—	—	(980)	(2,241)
Junior subordinated notes issued, net of issue costs	—	—	495	—
Loss on settlement of financial instruments	—	—	—	(130)
Redeemable non-controlling interest repurchased	—	—	(633)	—
Contributions from redeemable non-controlling interest	—	524	—	578
Dividends and distributions paid	(903)	(854)	(2,652)	(2,514)
Common shares issued	4	3	64	86
Preferred shares redeemed	—	—	(500)	—
Acquisition of TC PipeLines, LP transaction costs	—	—	(15)	—
Net cash provided by/(used in) financing activities	596	46	2,565	(1,415)

Long-term debt issued

On October 12, 2021, TCPL issued US$1.25 billion of Senior Unsecured Notes due in October 2024 bearing interest at a fixed rate of 1.00 per cent, and US$1.0 billion of Senior Unsecured Notes due in October 2031 bearing interest at a fixed rate of 2.50 per cent.

On June 9, 2021, TCPL issued $750 million of Medium Term Notes due in June 2024 bearing interest at a floating rate, $500 million of Medium Term Notes due in June 2031 bearing interest at a fixed rate of 2.97 per cent and $250 million of Medium Term Notes due in September 2047 bearing interest at a fixed rate of 4.33 per cent.

On January 4, 2021, we established a US$4.1 billion project-level credit facility to support the construction of the Keystone XL pipeline project, which was fully guaranteed by the Government of Alberta and non-recourse to us. The availability of this credit facility was subsequently reduced to US$1.6 billion, on which we drew a total of US$849 million, with full repayment by the Government of Alberta of the amount outstanding in June 2021. Refer to Note 5, Keystone XL, of our Condensed consolidated financial statements for additional information.

In December 2020, our subsidiary, Columbia Pipeline Group, Inc., entered into a US$4.2 billion Term Loan due in June 2022 bearing interest at a floating rate. In January 2021, US$4.0 billion was drawn on the Term Loan and the total availability under the loan agreement was reduced accordingly.

Long-term debt repaid/retired

In January 2021, TCPL repaid US$400 million of Debentures bearing interest at a fixed rate of 9.875 per cent.

In March 2021, our subsidiary, TC PipeLines, LP, redeemed US$350 million of Senior Unsecured Notes bearing interest at a fixed rate of 4.65 per cent.

As noted above, in June 2021, the Government of Alberta repaid the US$849 million ($1.0 billion) outstanding balance under the Keystone XL project-level credit facility, with no cash impact to us, and the facility was subsequently terminated. Refer to Note 5, Keystone XL, of our Condensed consolidated financial statements for additional information.

Junior subordinated notes issued

In March 2021, we issued $500 million of Junior Subordinated Notes through TransCanada Trust, a wholly-owned financing trust subsidiary of TCPL. We used the proceeds from the issuance to redeem all issued and outstanding TC Energy Series 13 preferred shares on May 31, 2021 pursuant to their terms. Refer to Note 9, Junior subordinated notes issued, of our Condensed consolidated financial statements for additional information.

TC Energy Third Quarter 2021 | 37

Redeemable non-controlling interest repurchased

On January 8, 2021, we exercised our call right in accordance with contractual terms and paid US$497 million to repurchase the Government of Alberta Class A Interests which were classified as Current liabilities on the Consolidated balance sheet at December 31, 2020. This transaction was funded by draws on the Keystone XL project-level credit facility which was guaranteed by the Government of Alberta as discussed above.

DIVIDENDS

On November 4, 2021, we declared quarterly dividends on our common shares of $0.87 per share payable on January 31, 2022 to shareholders of record at the close of business on December 31, 2021.

SHARE INFORMATION

At October 29, 2021, we had 981 million issued and outstanding common shares and 8 million outstanding options to buy common shares, of which 4 million were exercisable.

On May 31, 2021, we redeemed all of the 20 million issued and outstanding Series 13 preferred shares at a redemption price of $25.00 per share and paid the final quarterly dividend of $0.34375 per Series 13 preferred share for the period up to but excluding May 31, 2021 as previously declared on May 6, 2021.

On March 3, 2021, we issued 37,955,093 TC Energy common shares to acquire all the outstanding common units of TC PipeLines, LP, valued at approximately $2.1 billion, net of transaction costs. Refer to the Recent developments – Corporate section for additional information on the acquisition.

On February 1, 2021, 818,876 Series 5 preferred shares were converted, on a one-for-one basis, into Series 6 preferred shares and 175,208 Series 6 preferred shares were converted, on a one-for-one basis, into Series 5 preferred shares.

CREDIT FACILITIES

At October 29, 2021, we had a total of $9.8 billion of committed revolving credit facilities of which $7.3 billion of short-term borrowing capacity remains available, net of $2.5 billion backstopping outstanding commercial paper balances. We also have arrangements in place for a further $2.4 billion of demand credit facilities of which $1.1 billion remains available.

On March 4, 2021, our subsidiary, TC PipeLines, LP, terminated a US$500 million unsecured revolving credit facility bearing interest at a floating rate on which no amount was outstanding.

Refer to the Financial risks and financial instruments section for more information about liquidity, market and other risks.

CONTRACTUAL OBLIGATIONS

Capital expenditure commitments at September 30, 2021 are largely consistent with December 31, 2020, reflecting the net effect of an approximate $0.9 billion reduction related to the termination of the Keystone XL pipeline project and an increase in new capital commitments primarily related to NGTL System expansions and U.S. natural gas pipeline projects.

There were no other material changes to our contractual obligations in third quarter 2021 or to payments due in the next five years or after. Refer to our 2020 Annual Report for more information about our contractual obligations.

38 | TC Energy Third Quarter 2021

Financial risks and financial instruments

We are exposed to market risk and counterparty credit risk 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 2020 Annual Report for more information about the risks we face in our business which have not changed substantially since December 31, 2020, other than as noted within this MD&A. Refer to the Recent developments – COVID-19 section of this MD&A for further information regarding the impact of COVID-19 on our financial risks.

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.

Many of our financial instruments and contractual obligations with variable rate components reference U.S. dollar LIBOR, of which certain rate settings will cease to be published at the end of 2021 with full cessation by mid-2023. We continue to monitor developments and are addressing necessary system and contractual changes while assessing the adoption of the standard market proposed reference rates. This includes testing system solutions and analyzing existing agreements to determine the effect of reference rate reform on our consolidated financial statements. These changes are not expected to have a material impact on our consolidated financial statements.

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 can affect our comparable EBITDA and net income. Refer to the Consolidated results – Foreign exchange section for additional information.

A small portion of our Mexico Natural Gas Pipelines monetary assets and liabilities are peso-denominated, while the functional currency for our Mexico operations is U.S. dollars. These peso-denominated balances are revalued to U.S. dollars and, as a result, changes in the value of the Mexican peso against the U.S. dollar can affect our net income. This exposure is managed using foreign exchange derivatives.

Net investment hedges

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, foreign exchange forwards 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

•loans receivable.

TC Energy Third Quarter 2021 | 39

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 due to significant market events. Although the effects of the COVID-19 pandemic and other market disruptions on our customers are difficult to predict, similar to 2020, we are not expecting a material negative impact to our 2021 earnings or cash flows. Refer to our 2020 Annual Report for more information about the factors that mitigate our counterparty credit risk exposure.

We review financial assets carried at amortized cost for impairment using the lifetime expected loss of the financial asset at initial recognition and throughout the life of the financial asset. We use historical credit loss and recovery data, adjusted for our judgment regarding current economic and credit conditions, along with supportable forecasts to determine any impairment, which is recognized in Plant operating costs and other. At September 30, 2021, we had no significant credit losses, no significant credit risk concentration and no significant amounts past due or impaired.

We have significant credit and performance exposure to financial institutions because they 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.

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

Loans Receivable from Affiliates

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.

Sur de Texas

At September 30, 2021 and December 31, 2020, the Loan receivable from affiliate on our Condensed consolidated balance sheet of MXN$20.9 billion or $1.3 billion, represented our 60 per cent proportionate share of long-term debt financing to the Sur de Texas joint venture. Our Condensed consolidated statement of income reflects the related interest income and foreign exchange impact on this loan receivable which were fully offset upon consolidation with corresponding amounts included in our 60 per cent proportionate share of Sur de Texas equity earnings as follows:

	three months ended<br>September 30		nine months ended <br>September 30		Affected line item in the Condensed consolidated statement of income
(millions of $)	2021	2020	2021	2020
Interest income1	22	25	64	87	Interest income and other
Interest expense2	(22)	(25)	(64)	(87)	Income from equity investments
Foreign exchange (losses)/gains1	(42)	54	(45)	(223)	Interest income and other
Foreign exchange gains/(losses)1	42	(54)	45	223	Income from equity investments

1Included in our Corporate segment.

2Included in our Mexico Natural Gas Pipelines segment.

40 | TC Energy Third Quarter 2021

Coastal GasLink Pipeline Limited Partnership

We hold a 35 per cent equity interest in Coastal GasLink LP which has contracted us to construct and operate the Coastal GasLink pipeline. In 2020, we entered into a subordinated demand revolving credit facility with Coastal GasLink LP to provide additional short-term liquidity and funding flexibility to the project. The facility bears interest at a floating market-based rate and had a capacity of $850 million at September 30, 2021 with an outstanding balance of $840 million (December 31, 2020 – nil) reflected in Other current assets on our Condensed consolidated balance sheet. In October 2021, this amount was fully repaid and further draws were made which resulted in an outstanding balance of $175 million at October 29, 2021.

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 recovered or refunded through the tolls charged by us. As a result, these gains and losses are deferred as regulatory assets or regulatory liabilities 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 is as follows:

(millions of $)	September 30, 2021	December 31, 2020
Other current assets	207	235
Other long-term assets	44	41
Accounts payable and other	(272)	(72)
Other long-term liabilities	(63)	(59)
	(84)	145

TC Energy Third Quarter 2021 | 41

Unrealized and realized (losses)/gains on derivative instruments

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

	three months ended<br>September 30		nine months ended <br>September 30
(millions of $)	2021	2020	2021	2020
Derivative Instruments Held for Trading1
Amount of unrealized (losses)/gains in the period
Commodities	(43)	(2)	(27)	14
Foreign exchange	(125)	78	(183)	(24)
Amount of realized gains/(losses) in the period
Commodities	58	68	167	146
Foreign exchange	37	(11)	195	(62)
Derivative Instruments in Hedging Relationships2
Amount of realized (losses)/gains in the period
Commodities	(9)	2	(32)	4
Interest rate	(6)	(6)	(18)	(10)

1Realized and unrealized losses and gains on held-for-trading derivative instruments used to purchase and sell commodities are included on a net basis in Revenues. Realized and unrealized losses and gains on foreign exchange held-for-trading derivative instruments are included on a net basis in Interest income and other.

2In the three and nine months ended September 30, 2021 and 2020, there were no gains or losses included in Net income relating to discontinued cash flow hedges where it was probable that the anticipated transaction would not occur.

For further details on our non-derivative and derivative financial instruments, including classification assumptions made in the calculation of fair value and additional discussion of exposure to risks and mitigation activities, refer to Note 14, Risk management and financial instruments, of our Condensed consolidated financial statements.

42 | TC Energy Third Quarter 2021

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, 2021, 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 2021 that had or are likely to have a material impact on our internal control over financial reporting.

CRITICAL ACCOUNTING ESTIMATES AND ACCOUNTING POLICY CHANGES

When we prepare financial statements that conform with U.S. GAAP, we are required to make estimates and assumptions that affect the timing and amounts we record for our assets, liabilities, revenues and expenses because these items may be affected by future events. We base the estimates and assumptions on the most current information available, using our best judgment. We also regularly assess the assets and liabilities themselves. A summary of our critical accounting estimates is included in our 2020 Annual Report.

Accounting Changes

Our significant accounting policies have remained unchanged since December 31, 2020 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 2020 Annual Report.

TC Energy Third Quarter 2021 | 43

Quarterly results

SELECTED QUARTERLY CONSOLIDATED FINANCIAL DATA

	2021			2020				2019
(millions of $, except per share amounts)	Third	Second	First	Fourth	Third	Second	First	Fourth
Revenues	3,240	3,182	3,381	3,297	3,195	3,089	3,418	3,263
Net income/(loss) attributable to common shares	779	975	(1,057)	1,124	904	1,281	1,148	1,108
Comparable earnings	972	1,038	1,108	1,080	893	863	1,109	970
Per share statistics:
Net income/(loss) per common share – basic	$0.80	$1.00	($1.11)	$1.20	$0.96	$1.36	$1.22	$1.18
Comparable earnings per common share	$0.99	$1.06	$1.16	$1.15	$0.95	$0.92	$1.18	$1.03
Dividends declared per common share	$0.87	$0.87	$0.87	$0.81	$0.81	$0.81	$0.81	$0.75

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 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 generally remain relatively stable during any fiscal year. Over the long term, however, they fluctuate because of:

•regulatory decisions

•negotiated settlements with shippers

•newly constructed assets being placed in service

•acquisitions and divestitures

•developments outside of the normal course of operations.

In Liquids Pipelines, annual revenues and segmented earnings are based on contracted and uncontracted spot transportation, as well as liquids marketing activities. Quarter-over-quarter revenues and segmented earnings 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.

In Power and Storage, quarter-over-quarter revenues and segmented earnings 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

•planned and unplanned plant outages

•developments outside of the normal course of operations

•certain fair value adjustments.

44 | TC Energy Third Quarter 2021

FACTORS AFFECTING FINANCIAL INFORMATION BY QUARTER

We calculate comparable measures by adjusting certain GAAP and non-GAAP measures for specific items we believe are significant but not reflective of our underlying operations in the period.

Comparable earnings exclude the unrealized gains and losses from changes in the fair value of certain derivatives used to reduce our exposure to specific financial and commodity price risks. These derivatives generally provide effective economic hedges but do not meet the criteria for hedge accounting. As a result, the 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 part of our underlying operations. We also exclude the unrealized foreign exchange gains and losses on the Loan receivable from affiliate as well as the corresponding proportionate share of Sur de Texas foreign exchange gains and losses, as these amounts do not accurately reflect the gains and losses that will be realized at settlement. These amounts offset within each reporting period, resulting in no impact on net income.

In third quarter 2021, comparable earnings also excluded:

•a $55 million after-tax expense with respect to transition payments incurred as part of the VRP

•preservation and other costs of $11 million after tax primarily related to the preservation and storage of Keystone XL pipeline project assets.

In second quarter 2021, comparable earnings also excluded:

•an incremental $2 million after-tax asset impairment charge, net of expected contractual recoveries and other contractual and legal obligations, related to the termination of the Keystone XL pipeline project

•preservation and other costs of $16 million after tax primarily related to the preservation and storage of Keystone XL pipeline project assets and interest expense on the Keystone XL project-level credit facility prior to its termination

•a $13 million after-tax recovery of certain costs from the IESO associated with the Ontario natural gas-fired power plants sold in 2020.

In first quarter 2021, comparable earnings also excluded:

•an after-tax asset impairment charge, net of expected contractual recoveries and other contractual and legal obligations, of $2.2 billion related to the formal suspension of the Keystone XL pipeline project following the January 20, 2021 revocation of the Presidential Permit.

In fourth quarter 2020, comparable earnings also excluded:

•an income tax valuation allowance release of $18 million related to certain prior years' U.S. income tax losses resulting from our reassessment of deferred income tax assets that are more likely than not to be realized

•an additional $18 million income tax recovery related to state income taxes on the sale of certain Columbia Midstream assets in 2019

•an incremental after-tax loss of $81 million for the three months ended December 31, 2020 related to the sale of our Ontario natural gas-fired power plants.

In third quarter 2020, comparable earnings also excluded:

•an incremental after-tax loss of $45 million related to the sale of the Ontario natural gas-fired power plants

•a $6 million reduction in the after-tax gain related to the sale of a 65 per cent equity interest in Coastal GasLink LP.

In second quarter 2020, comparable earnings also excluded:

•an after-tax gain of $408 million related to the sale of a 65 per cent equity interest in Coastal GasLink LP

•an incremental after-tax loss of $80 million related to the sale of the Ontario natural gas-fired power plants.

In first quarter 2020, comparable earnings also excluded:

•an income tax valuation allowance release of $281 million following our reassessment of deferred income tax assets that are deemed more likely than not to be realized

•an incremental after-tax loss of $77 million related to the Ontario natural gas-fired power plant assets held for sale.

TC Energy Third Quarter 2021 | 45

In fourth quarter 2019, comparable earnings also excluded:

•an income tax valuation allowance release of $195 million related to certain prior years' U.S. income tax losses resulting from our reassessment of deferred income tax assets that are more likely than not to be realized

•an incremental after-tax loss of $61 million related to the Ontario natural gas-fired power plant assets held for sale

•an additional $19 million expense related to state income taxes on the sale of certain Columbia Midstream assets.

46 | TC Energy Third Quarter 2021

Document

EXHIBIT 13.2

Condensed consolidated statement of income

	three months ended<br>September 30		nine months ended <br>September 30
(unaudited - millions of Canadian $, except per share amounts)	2021	2020	2021	2020
Revenues
Canadian Natural Gas Pipelines	1,129	1,162	3,374	3,281
U.S. Natural Gas Pipelines	1,275	1,186	3,832	3,745
Mexico Natural Gas Pipelines	153	156	456	562
Liquids Pipelines	563	606	1,652	1,827
Power and Storage	120	85	489	287
	3,240	3,195	9,803	9,702
Income from Equity Investments	265	200	681	934
Operating and Other Expenses
Plant operating costs and other	1,160	976	3,005	2,829
Property taxes	191	174	583	549
Depreciation and amortization	610	673	1,888	1,938
Asset impairment charge and other	—	—	2,854	—
	1,961	1,823	8,330	5,316
Net (Loss)/Gain on Sale of Assets	—	(66)	17	43
Financial Charges
Interest expense	596	559	1,749	1,698
Allowance for funds used during construction	(81)	(91)	(195)	(254)
Interest income and other	76	(164)	(113)	160
	591	304	1,441	1,604
Income before Income Taxes	953	1,202	730	3,759
Income Tax Expense/(Recovery)
Current	152	100	419	287
Deferred	(17)	90	(577)	(209)
	135	190	(158)	78
Net Income	818	1,012	888	3,681
Net income attributable to non-controlling interests	8	69	83	228
Net Income Attributable to Controlling Interests	810	943	805	3,453
Preferred share dividends	31	39	108	120
Net Income Attributable to Common Shares	779	904	697	3,333
Net Income per Common Share
Basic and diluted	$0.80	$0.96	$0.72	$3.55
Weighted Average Number of Common Shares (millions)
Basic and diluted	979	940	970	940

See accompanying notes to the Condensed consolidated financial statements.

TC Energy Third Quarter 2021 | 47

Condensed consolidated statement of comprehensive income

	three months ended<br>September 30		nine months ended <br>September 30
(unaudited - millions of Canadian $)	2021	2020	2021	2020
Net Income	818	1,012	888	3,681
Other Comprehensive Income/(Loss), Net of Income Taxes
Foreign currency translation gains and losses on net investment in foreign operations	450	(491)	(81)	417
Change in fair value of net investment hedges	(27)	26	(3)	(6)
Change in fair value of cash flow hedges	(15)	(1)	(15)	(578)
Reclassification to net income of gains and losses on cash flow hedges	15	10	33	480
Reclassification to net income of actuarial gains and losses on pension and other post-retirement benefit plans	5	4	12	1
Other comprehensive income/(loss) on equity investments	25	14	155	(6)
Other comprehensive income/(loss)	453	(438)	101	308
Comprehensive Income	1,271	574	989	3,989
Comprehensive income attributable to non-controlling interests	10	35	73	263
Comprehensive Income Attributable to Controlling Interests	1,261	539	916	3,726
Preferred share dividends	31	39	108	120
Comprehensive Income Attributable to Common Shares	1,230	500	808	3,606

See accompanying notes to the Condensed consolidated financial statements.

48 | TC Energy Third Quarter 2021

Condensed consolidated statement of cash flows

	three months ended<br>September 30		nine months ended <br>September 30
(unaudited - millions of Canadian $)	2021	2020	2021	2020
Cash Generated from Operations
Net income	818	1,012	888	3,681
Depreciation and amortization	610	673	1,888	1,938
Deferred income taxes	(17)	90	(577)	(209)
Asset impairment charge and other	—	—	2,854	—
Income from equity investments	(265)	(200)	(681)	(934)
Distributions received from operating activities of equity investments	238	277	740	802
Employee post-retirement benefits funding, net of expense	8	(22)	14	(6)
Net loss/(gain) on sale of assets	—	66	(17)	(43)
Equity allowance for funds used during construction	(59)	(63)	(138)	(168)
Unrealized losses/(gains) on financial instruments	168	(76)	210	10
Foreign exchange losses/(gains) on Loan receivable from affiliate	42	(54)	45	223
Other	(58)	(40)	(105)	12
Decrease/(increase) in operating working capital	227	120	(32)	(187)
Net cash provided by operations	1,712	1,783	5,089	5,119
Investing Activities
Capital expenditures	(1,446)	(2,063)	(4,305)	(6,049)
Capital projects in development	—	—	—	(122)
Contributions to equity investments	(241)	(187)	(706)	(498)
Proceeds from sale of assets, net of transaction costs	—	—	—	3,407
Loan to affiliate	(620)	(250)	(840)	(250)
Deferred amounts and other	(66)	(137)	(470)	(359)
Net cash used in investing activities	(2,373)	(2,637)	(6,321)	(3,871)
Financing Activities
Notes payable issued/(repaid), net	1,448	338	(1,012)	(2,765)
Long-term debt issued, net of issue costs	47	35	7,798	5,571
Long-term debt repaid	—	—	(980)	(2,241)
Junior subordinated notes issued, net of issue costs	—	—	495	—
Loss on settlement of financial instruments	—	—	—	(130)
Redeemable non-controlling interest repurchased	—	—	(633)	—
Contributions from redeemable non-controlling interest	—	524	—	578
Dividends on common shares	(852)	(761)	(2,465)	(2,226)
Dividends on preferred shares	(32)	(39)	(109)	(121)
Distributions to non-controlling interests	(8)	(54)	(67)	(167)
Distributions on Class C Interests	(11)	—	(11)	—
Common shares issued	4	3	64	86
Preferred shares redeemed	—	—	(500)	—
Acquisition of TC PipeLines, LP transaction costs	—	—	(15)	—
Net cash provided by/(used in) financing activities	596	46	2,565	(1,415)
Effect of Foreign Exchange Rate Changes on Cash and Cash Equivalents	34	(19)	(6)	16
(Decrease)/Increase in Cash and Cash Equivalents	(31)	(827)	1,327	(151)
Cash and Cash Equivalents
Beginning of period	2,888	2,019	1,530	1,343
Cash and Cash Equivalents
End of period	2,857	1,192	2,857	1,192

See accompanying notes to the Condensed consolidated financial statements.

TC Energy Third Quarter 2021 | 49

Condensed consolidated balance sheet

(unaudited - millions of Canadian )	September 30, 2021	December 31, 2020
ASSETS
Current Assets
Cash and cash equivalents	2,857	1,530
Accounts receivable	2,611	2,162
Inventories	743	629
Other current assets	2,510	880
	8,721	5,201
Plant, Property and Equipment	69,284	69,775
Loan Receivable from Affiliate	1,286	1,338
Equity Investments	7,512	6,677
Restricted Investments	2,056	1,898
Regulatory Assets	1,884	1,753
Goodwill	12,599	12,679
Other Long-Term Assets	1,181	979
	104,523	100,300
LIABILITIES
Current Liabilities
Notes payable	3,172	4,176
Accounts payable and other	4,989	3,816
Redeemable non-controlling interest	—	633
Dividends payable	864	795
Accrued interest	581	595
Current portion of long-term debt	7,373	1,972
	16,979	11,987
Regulatory Liabilities	4,143	4,148
Other Long-Term Liabilities	1,420	1,475
Deferred Income Tax Liabilities	5,419	5,806
Long-Term Debt	35,097	34,913
Junior Subordinated Notes	8,948	8,498
	72,006	66,827
Redeemable Non-Controlling Interest	—	393
EQUITY
Common shares, no par value	26,622	24,488
Issued and outstanding:
Preferred shares	3,487	3,980
Additional paid-in capital	736	2
Retained earnings	3,523	5,367
Accumulated other comprehensive loss	(1,975)	(2,439)
Controlling Interests	32,393	31,398
Non-Controlling Interests	124	1,682
	32,517	33,080
	104,523	100,300

All values are in US Dollars.

Commitments, Contingencies and Guarantees (Note 15)

Variable Interest Entities (Note 16)

Subsequent Event (Note 17)

See accompanying notes to the Condensed consolidated financial statements.

50 | TC Energy Third Quarter 2021

Condensed consolidated statement of equity

	three months ended<br>September 30		nine months ended <br>September 30
(unaudited - millions of Canadian $)	2021	2020	2021	2020
Balance at beginning of period	26,618	24,480	24,488	24,387
Shares issued:
Acquisition of TC PipeLines, LP, net of transaction costs	—	—	2,063	—
Exercise of stock options	4	3	71	96
Balance at end of period	26,622	24,483	26,622	24,483
Preferred Shares
Balance at beginning of period	3,487	3,980	3,980	3,980
Redemption of shares	—	—	(493)	—
Balance at end of period	3,487	3,980	3,487	3,980
Additional Paid-In Capital
Balance at beginning of period	734	—	2	—
Keystone XL project-level credit facility retirement and issuance of Class C Interests	—	—	737	—
Acquisition of TC PipeLines, LP	—	—	(398)	—
Repurchase of redeemable non-controlling interest	—	—	394	—
Issuance of stock options, net of exercises	2	2	1	(1)
Reclassification of additional paid-in capital deficit to retained earnings	—	(2)	—	1
Balance at end of period	736	—	736	—
Retained Earnings
Balance at beginning of period	3,596	4,880	5,367	3,955
Net income attributable to controlling interests	810	943	805	3,453
Common share dividends	(851)	(762)	(2,555)	(2,284)
Preferred share dividends	(32)	(38)	(87)	(98)
Redemption of preferred shares	—	—	(7)	—
Reclassification of additional paid-in capital deficit to retained earnings	—	2	—	(1)
Balance at end of period	3,523	5,025	3,523	5,025
Accumulated Other Comprehensive Loss
Balance at beginning of period	(2,426)	(882)	(2,439)	(1,559)
Other comprehensive income/(loss) attributable to controlling interests	451	(404)	111	273
Acquisition of TC PipeLines, LP	—	—	353	—
Balance at end of period	(1,975)	(1,286)	(1,975)	(1,286)
Equity Attributable to Controlling Interests	32,393	32,202	32,393	32,202
Equity Attributable to Non-Controlling Interests
Balance at beginning of period	122	1,753	1,682	1,634
Net income attributable to non-controlling interests	8	67	82	229
Other comprehensive income/(loss) attributable to non-controlling interests	2	(34)	(10)	35
Distributions declared to non-controlling interests	(8)	(56)	(67)	(168)
Acquisition of TC PipeLines, LP	—	—	(1,563)	—
Balance at end of period	124	1,730	124	1,730
Total Equity	32,517	33,932	32,517	33,932

See accompanying notes to the Condensed consolidated financial statements.

TC Energy Third Quarter 2021 | 51

Notes to Condensed consolidated financial statements

(unaudited)

BASIS OF PRESENTATION

These Condensed consolidated financial statements of TC Energy Corporation (TC Energy or the Company) have been prepared by management in accordance with U.S. GAAP. The accounting policies applied are consistent with those outlined in TC Energy’s annual audited Consolidated financial statements for the year ended December 31, 2020, except as described in Note 2, Accounting changes. Capitalized and abbreviated terms that are used but not otherwise defined herein are identified in the 2020 audited Consolidated financial statements included in TC Energy’s 2020 Annual Report.

These Condensed consolidated financial statements reflect adjustments, all of which are normal recurring adjustments that are, in the opinion of management, necessary to reflect fairly the financial position and results of operations for the respective periods. These Condensed consolidated financial statements do not include all disclosures required in the annual financial statements and should be read in conjunction with the 2020 audited Consolidated financial statements included in TC Energy’s 2020 Annual Report.

Earnings for interim periods may not be indicative of results for the fiscal year in certain of the Company’s segments primarily due to:

•Natural gas pipelines segments – the timing of regulatory decisions and seasonal fluctuations in short-term throughput volumes on U.S. pipelines

•Liquids Pipelines – fluctuations in throughput volumes on the Keystone Pipeline System and marketing activities

•Power and Storage – the impact of seasonal weather conditions on customer demand and market pricing in addition to maintenance outages in certain of the Company’s investments in electrical power generation plants and Canadian non-regulated gas storage facilities.

Use of Estimates and Judgments

In preparing these financial statements, TC Energy is required to make estimates and assumptions that affect both the amount and timing of recording assets, liabilities, revenues and expenses since the determination of these items may be dependent on future events. The Company uses the most current information available and exercises careful judgment in making these estimates and assumptions. In the opinion of management, these Condensed consolidated financial statements have been properly prepared within reasonable limits of materiality and within the framework of the Company’s significant accounting policies included in the annual audited Consolidated financial statements for the year ended December 31, 2020, except as described in Note 2, Accounting changes.

ACCOUNTING CHANGES

Reference Rate Reform

In response to the expected cessation of the London Interbank Offered Rate (LIBOR), of which certain rate settings will cease to be published at the end of 2021 with full cessation by mid-2023, the FASB issued new optional guidance in March 2020 that eases the potential burden in accounting for such reference rate reform. The new guidance provides optional expedients for contracts and hedging relationships that are affected by reference rate reform if certain criteria are met. Each of the expedients can be applied as of January 1, 2020 through December 31, 2022. For eligible hedging relationships existing as of January 1, 2020 and prospectively, the Company has applied an optional expedient allowing an entity to assume that the hedged forecasted transaction in a cash flow hedge is probable of occurring. The Company continues to monitor developments and is addressing necessary system and contractual changes while assessing the adoption of the standard market proposed reference rates. This includes testing system solutions and analyzing existing agreements to determine the effect of reference rate reform on its consolidated financial statements. These changes are not expected to have a material

52 | TC Energy Third Quarter 2021

impact on the consolidated financial statements. The Company will continue to evaluate the timing and potential impact of adoption for other optional expedients when deemed necessary.

Changes in Accounting Policies for 2021

Income taxes

In December 2019, the FASB issued new guidance that simplified the accounting for income taxes and clarified existing guidance. This new guidance was effective January 1, 2021 and did not have a material impact on the Company's consolidated financial statements.

SEGMENTED INFORMATION

three months ended September 30, 2021	U.S. Natural Gas Pipelines	Mexico Natural Gas Pipelines	Liquids Pipelines		Power and Storage
(unaudited - millions of Canadian )				Corporate1		Total
Revenues	1,275	153	563		120		—		3,240
Intersegment revenues	36	—	—		1		(37)	2	—
	1,311	153	563		121		(37)		3,240
Income from equity investments	54	34	18		113		42	3	265
Plant operating costs and other4	(385)	(16)	(194)		(97)		(41)	2	(1,160)
Property taxes	(93)	—	(22)		(1)		—		(191)
Depreciation and amortization	(195)	(27)	(80)		(20)		—		(610)
Segmented Earnings/(Losses)	692	144	285		116		(36)		1,544
Interest expense									(596)
Allowance for funds used during construction									81
Interest income and other3									(76)
Income before Income Taxes									953
Income tax expense									(135)
Net Income									818
Net income attributable to non-controlling interests									(8)
Net Income Attributable to Controlling Interests									810
Preferred share dividends									(31)
Net Income Attributable to Common Shares									779

All values are in US Dollars.

1Includes intersegment eliminations.

2The Company records intersegment sales at contracted rates. For segmented reporting, these transactions are included as Intersegment revenues in the segment providing the service and Plant operating costs and other in the segment receiving the service. These transactions are eliminated on consolidation. Intersegment profit is recognized when the product or service has been provided to third parties or otherwise realized.

3Income from equity investments includes the Company's proportionate share of Sur de Texas foreign exchange gains and losses on the peso-denominated loans from affiliates which are fully offset in Interest income and other by the corresponding foreign exchange losses and gains on the affiliate receivable balance. Refer to Note 7, Loans receivable from affiliates, for additional information.

4Includes an $89 million expense with respect to transition payments incurred as part of the Voluntary Retirement Program.

TC Energy Third Quarter 2021 | 53

three months ended September 30, 2020	U.S. Natural Gas Pipelines	Mexico Natural Gas Pipelines	Liquids Pipelines		Power and Storage
(unaudited - millions of Canadian )				Corporate1		Total
Revenues	1,186	156	606		85		—		3,195
Intersegment revenues	41	—	—		—		(41)	2	—
	1,227	156	606		85		(41)		3,195
Income/(loss) from equity investments	65	26	19		144		(54)	3	200
Plant operating costs and other	(352)	(12)	(178)		(45)		34	2	(976)
Property taxes	(77)	—	(23)		(1)		—		(174)
Depreciation and amortization	(219)	(28)	(82)		(18)		—		(673)
Net loss on sale of assets	—	—	—		(60)		—		(66)
Segmented Earnings/(Losses)	644	142	342		105		(61)		1,506
Interest expense									(559)
Allowance for funds used during construction									91
Interest income and other3									164
Income before Income Taxes									1,202
Income tax expense									(190)
Net Income									1,012
Net income attributable to non-controlling interests									(69)
Net Income Attributable to Controlling Interests									943
Preferred share dividends									(39)
Net Income Attributable to Common Shares									904

All values are in US Dollars.

1Includes intersegment eliminations.

3Income/(loss) from equity investments includes the Company's proportionate share of Sur de Texas foreign exchange gains and losses on the peso-denominated loans from affiliates which are fully offset in Interest income and other by the corresponding foreign exchange losses and gains on the affiliate receivable balance. Refer to Note 7, Loans receivable from affiliates, for additional information.

54 | TC Energy Third Quarter 2021

nine months ended September 30, 2021	U.S. Natural Gas Pipelines	Mexico Natural Gas Pipelines	Liquids Pipelines		Power and Storage
(unaudited - millions of Canadian )				Corporate1		Total
Revenues	3,832	456	1,652		489		—		9,803
Intersegment revenues	110	—	—		14		(124)	2	—
	3,942	456	1,652		503		(124)		9,803
Income from equity investments	176	100	54		298		45	3	681
Plant operating costs and other4	(1,019)	(41)	(509)		(319)		39	2	(3,005)
Property taxes	(276)	—	(78)		(4)		—		(583)
Depreciation and amortization	(570)	(81)	(238)		(58)		—		(1,888)
Asset impairment charge and other	—	—	(2,854)		—		—		(2,854)
Gain on sale of assets	—	—	—		17		—		17
Segmented Earnings/(Losses)	2,253	434	(1,973)		437		(40)		2,171
Interest expense									(1,749)
Allowance for funds used during construction									195
Interest income and other3									113
Income before Income Taxes									730
Income tax recovery									158
Net Income									888
Net income attributable to non-controlling interests									(83)
Net Income Attributable to Controlling Interests									805
Preferred share dividends									(108)
Net Income Attributable to Common Shares									697

All values are in US Dollars.

1Includes intersegment eliminations.

4Includes an $89 million expense with respect to transition payments incurred as part of the Voluntary Retirement Program.

TC Energy Third Quarter 2021 | 55

nine months ended September 30, 2020	U.S. Natural Gas Pipelines	Mexico Natural Gas Pipelines	Liquids Pipelines		Power and Storage
(unaudited - millions of Canadian )				Corporate1		Total
Revenues	3,745	562	1,827		287		—		9,702
Intersegment revenues	126	—	—		7		(133)	2	—
	3,871	562	1,827		294		(133)		9,702
Income from equity investments	196	99	56		355		223	3	934
Plant operating costs and other	(1,099)	(41)	(498)		(138)		130	2	(2,829)
Property taxes	(249)	—	(77)		(4)		—		(549)
Depreciation and amortization	(612)	(88)	(249)		(48)		—		(1,938)
Net gain/(loss) on sale of assets	—	—	—		(321)		—		43
Segmented Earnings	2,107	532	1,059		138		220		5,363
Interest expense									(1,698)
Allowance for funds used during construction									254
Interest income and other3									(160)
Income before Income Taxes									3,759
Income tax expense									(78)
Net Income									3,681
Net income attributable to non-controlling interests									(228)
Net Income Attributable to Controlling Interests									3,453
Preferred share dividends									(120)
Net Income Attributable to Common Shares									3,333

All values are in US Dollars.

1Includes intersegment eliminations.

Total Assets by Segment

(unaudited - millions of Canadian $)	September 30, 2021	December 31, 2020
Canadian Natural Gas Pipelines	24,415	22,852
U.S. Natural Gas Pipelines	44,829	43,217
Mexico Natural Gas Pipelines	7,554	7,215
Liquids Pipelines	14,709	16,744
Power and Storage	5,684	5,062
Corporate	7,332	5,210
	104,523	100,300

56 | TC Energy Third Quarter 2021

REVENUES

Disaggregation of Revenues

The following tables summarize total Revenues for the three and nine months ended September 30, 2021 and 2020:

three months ended September 30, 2021	U.S. <br>Natural <br>Gas <br>Pipelines	Mexico <br>Natural <br>Gas <br>Pipelines	Liquids Pipelines	Power and Storage	Total
(unaudited - millions of Canadian )
Revenues from contracts with customers
Capacity arrangements and transportation	967	146	520	—	2,742
Power generation	—	—	—	72	72
Natural gas storage and other1	296	7	1	59	383
	1,263	153	521	131	3,197
Other revenues2,3	12	—	42	(11)	43
	1,275	153	563	120	3,240

All values are in US Dollars.

1Includes $20 million of fee revenues from an affiliate related to development and construction of the Coastal GasLink pipeline project which is 35 per cent owned by TC Energy.

2Other revenues include income from the Company's marketing activities, financial instruments and lease arrangements. Refer to Note 14, Risk management and financial instruments, for additional information on financial instruments.

3Includes $31 million of operating lease income.

three months ended September 30, 2020	U.S. <br>Natural <br>Gas <br>Pipelines	Mexico <br>Natural <br>Gas <br>Pipelines	Liquids Pipelines	Power and Storage	Total
(unaudited - millions of Canadian )
Revenues from contracts with customers
Capacity arrangements and transportation	1,005	150	537	—	2,827
Power generation	—	—	—	40	40
Natural gas storage and other1	165	6	—	15	213
	1,170	156	537	55	3,080
Other revenues2,3	16	—	69	30	115
	1,186	156	606	85	3,195

All values are in US Dollars.

1Includes $27 million of fee revenues from an affiliate related to development and construction of the Coastal GasLink pipeline project which is 35 per cent owned by TC Energy.

3Includes $33 million of operating lease income.

TC Energy Third Quarter 2021 | 57

nine months ended September 30, 2021	U.S.<br><br>Natural<br><br>Gas<br><br>Pipelines	Mexico<br><br>Natural<br><br>Gas<br><br>Pipelines	Liquids Pipelines	Power and Storage	Total
(unaudited - millions of Canadian )
Revenues from contracts with customers
Capacity arrangements and transportation	3,034	433	1,491	—	8,262
Power generation	—	—	—	230	230
Natural gas storage and other1	753	23	3	217	1,066
	3,787	456	1,494	447	9,558
Other revenues2,3	45	—	158	42	245
	3,832	456	1,652	489	9,803

All values are in US Dollars.

1Includes $70 million of fee revenues from an affiliate related to development and construction of the Coastal GasLink pipeline project which is 35 per cent owned by TC Energy.

3Includes $95 million of operating lease income.

nine months ended September 30, 2020	U.S.<br><br>Natural<br><br>Gas<br><br>Pipelines	Mexico<br><br>Natural<br><br>Gas<br><br>Pipelines	Liquids Pipelines	Power and Storage	Total
(unaudited - millions of Canadian )
Revenues from contracts with customers
Capacity arrangements and transportation	3,194	458	1,670	—	8,564
Power generation	—	—	—	143	143
Natural gas storage and other1	494	104	2	54	693
	3,688	562	1,672	197	9,400
Other revenues2,3	57	—	155	90	302
	3,745	562	1,827	287	9,702

All values are in US Dollars.

1Includes $116 million of fee revenues from affiliates, of which $77 million is related to the construction of the Sur de Texas pipeline project which is 60 per cent owned by TC Energy and $39 million is related to development and construction of the Coastal GasLink pipeline project which is 35 per cent owned by TC Energy.

3Includes $98 million of operating lease income.

Contract Balances

(unaudited - millions of Canadian $)	September 30, 2021	December 31, 2020	Affected line item on the Condensed consolidated balance sheet
Receivables from contracts with customers	1,517	1,330	Accounts receivable
Contract assets	354	132	Other current assets
Long-term contract assets	232	192	Other long-term assets
Contract liabilities1	74	129	Accounts payable and other
Long-term contract liabilities	203	203	Other long-term liabilities

1During the nine months ended September 30, 2021, $12 million (2020 – $10 million) of revenues were recognized that were included in contract liabilities at the beginning of the period.

58 | TC Energy Third Quarter 2021

Contract assets and long-term contract assets primarily relate to the Company’s right to revenues for services completed but not invoiced at the reporting date on long-term committed capacity natural gas pipelines contracts. The change in contract assets is primarily related to the transfer to Accounts receivable when these rights become unconditional and the customer is invoiced, as well as the recognition of additional revenues that remain to be invoiced. Contract liabilities and long-term contract liabilities primarily relate to force majeure fixed capacity payments received on long-term capacity arrangements in Mexico.

Future Revenues from Remaining Performance Obligations

As at September 30, 2021, future revenues from long-term pipeline capacity arrangements and transportation as well as natural gas storage and other contracts extending through 2048 are approximately $23.8 billion, of which approximately $1.6 billion is expected to be recognized during the remainder of 2021.

KEYSTONE XL

Asset Impairment Charge and Other

On June 9, 2021, following the revocation of the Presidential Permit for the Keystone XL pipeline on January 20, 2021, and after a comprehensive review of options in consultation with the Government of Alberta, the Company terminated the Keystone XL pipeline project. The Keystone XL investment was evaluated for impairment in first quarter 2021 along with TC Energy's investments in related capital projects, including Heartland Pipeline, TC Terminals and Keystone Hardisty Terminal. As a result, the Company determined that the carrying amount of these assets within the Liquids Pipelines segment was no longer fully recoverable and recognized an asset impairment charge, net of expected contractual recoveries and other contractual and legal obligations related to termination activities, of $2,854 million ($2,194 million after tax) for the nine months ended September 30, 2021. The asset impairment charge was based on the excess of the carrying value of $3,301 million over the estimated fair value of $175 million. Termination activities and related costs will continue through 2022 with any adjustments to the estimated fair value and future contractual and legal obligations expensed as determined.

nine months ended September 30, 2021		Asset impairment charge and other
(unaudited - millions of Canadian )	Pre tax		After tax
Asset impairment charge
Plant and equipment		412		312
Related capital projects in development		230		175
Other capitalized costs		2,158		1,642
Capitalized interest		326		248
		3,126		2,377
Other
Contractual recoveries		(697)		(531)
Contractual and legal obligations related to termination activities		425		348
		2,854		2,194

All values are in US Dollars.

The estimated fair value of $175 million related to plant and equipment is based on the price that is expected to be received from selling these assets in their current condition and is updated as required. Key assumptions used in the determination of selling price included an estimated two-year disposal period and current energy market demand. The valuation considered a variety of potential selling prices based on various markets that could be used to dispose of these assets and required the use of unobservable inputs. As a result, the fair value is classified in Level III of the fair value hierarchy.

TC Energy Third Quarter 2021 | 59

As the Company did not see the related capital projects in development proceeding at the time of the assessment in first quarter 2021, it recorded an asset impairment charge equal to the carrying value of these projects included in Other long-term assets on the Condensed consolidated balance sheet as the estimated fair value of these related projects was determined to be nil.

Redeemable Non-Controlling Interest and Long-Term Debt

On January 8, 2021, the Company exercised its call right in accordance with contractual terms and paid $633 million (US$497 million) to repurchase the Government of Alberta Class A Interests in certain Keystone XL subsidiaries which were classified as Current liabilities on the Consolidated balance sheet at December 31, 2020. This transaction was funded by draws on the project-level credit facility which was guaranteed by the Government of Alberta and non-recourse to TC Energy.

Following the revocation of the Presidential Permit for the Keystone XL pipeline on January 20, 2021, the Company ceased accruing a return on the remaining Government of Alberta Class A Interests.

In June 2021, in accordance with the terms of the guarantee, the Government of Alberta repaid the full outstanding balance on the Keystone XL project-level credit facility totaling $1,028 million (US$849 million), which was subsequently terminated. As part of this arrangement, TC Energy issued $91 million of Class C Interests in the Keystone XL subsidiaries which entitle the Government of Alberta to future liquidation proceeds from specified Keystone XL project assets. The issuance of Class C Interests was recorded in Accounts payable and other on the Condensed consolidated balance sheet at their fair value. Termination of the project-level credit facility, net of the issuance of Class C Interests, resulted in $937 million ($737 million after tax) recorded to Additional paid-in capital.

In June 2021, the Company repurchased the remaining Government of Alberta Class A Interests for a nominal amount, which was accounted for as an equity transaction and resulted in $394 million recognized in Additional paid-in capital.

The changes in Redeemable non-controlling interest classified in mezzanine equity were as follows:

	three months ended<br>September 30		nine months ended <br>September 30
(unaudited - millions of Canadian $)	2021	2020	2021	2020
Balance at beginning of period	—	325	393	—
Class A Interests issued	—	392	—	720
Net income/(loss) attributable to redeemable non-controlling interest1	—	2	1	(1)
Class A Interests repurchased	—	—	(394)	—
Balance at end of period	—	719	—	719

1 Includes a return accrual up to January 20, 2021 and a foreign currency translation loss on Class A Interests, both of which were presented within Net income attributable to non-controlling interests in the Condensed consolidated statement of income.

INCOME TAXES

Effective Tax Rates

The effective income tax rates were negative 22 per cent and two per cent for the nine months ended September 30, 2021 and 2020, respectively. The decrease in the effective income tax rate is primarily due to the impacts of the Keystone XL asset impairment charge recorded in the nine months ended September 30, 2021 as well as the release of income tax valuation allowances and the non-taxable portion of capital gains recognized in the nine months ended September 30, 2020.

60 | TC Energy Third Quarter 2021

LOANS RECEIVABLE FROM AFFILIATES

Sur de Texas

At September 30, 2021 and December 31, 2020, Loan receivable from affiliate on the Company's Condensed consolidated balance sheet reflected a MXN$20.9 billion or $1.3 billion loan receivable from the Sur de Texas joint venture which represents TC Energy's 60 per cent proportionate share of long-term debt financing to the joint venture. The Company's Condensed consolidated statement of income reflected the related interest income and foreign exchange impact on this loan receivable which were fully offset upon consolidation with corresponding amounts included in TC Energy’s 60 per cent proportionate share of Sur de Texas equity earnings as follows:

(unaudited - millions of Canadian )	three months ended<br>September 30				nine months ended <br>September 30			Affected line item in the Condensed consolidated statement of income
		2020		2021		2020
Interest income1	22		25		64		87	Interest income and other
Interest expense2	(22)		(25)		(64)		(87)	Income from equity investments
Foreign exchange (losses)/gains1	(42)		54		(45)		(223)	Interest income and other
Foreign exchange gains/(losses)1	42		(54)		45		223	Income from equity investments

All values are in US Dollars.

1Included in the Corporate segment.

2Included in the Mexico Natural Gas Pipelines segment.

Coastal GasLink Pipeline Limited Partnership

TC Energy holds a 35 per cent equity interest in Coastal GasLink Pipeline Limited Partnership (Coastal GasLink LP), which has contracted the Company to construct and operate the Coastal GasLink pipeline. In 2020, the Company entered into a subordinated demand revolving credit facility with Coastal GasLink LP to provide additional short-term liquidity and funding flexibility to the project. The facility bears interest at a floating market-based rate and had a capacity of $850 million at September 30, 2021 with an outstanding balance of $840 million (December 31, 2020 – nil) reflected in Other current assets on the Company's Condensed consolidated balance sheet. At October 29, 2021, the capacity on the facility was reduced to $500 million, on which the outstanding balance was $175 million.

LONG-TERM DEBT

Long-Term Debt Issued

Long-term debt issued by the Company in the nine months ended September 30, 2021 included the following:

(unaudited - millions of Canadian , unless otherwise noted)
Company	Type	Maturity date	Amount	Interest rate
TransCanada PipeLines Limited	Medium Term Notes	June 2024	750	Floating
TransCanada PipeLines Limited	Medium Term Notes	June 2031	500	2.97	%
TransCanada PipeLines Limited	Medium Term Notes	September 2047	250	4.33	%
Tuscarora Gas Transmission Company	Unsecured Term Loan	August 2024	US 13	Floating
Keystone XL subsidiaries1	Project-Level Credit Facility	June 2021	US 849	Floating
Columbia Pipeline Group, Inc.	Unsecured Term Loan	June 2022	US 4,040	Floating

All values are in US Dollars.

1On January 4, 2021, the Company established a US$4.1 billion project-level credit facility to support the construction of the Keystone XL pipeline, which was fully guaranteed by the Government of Alberta and non-recourse to TC Energy. The availability of this credit facility was subsequently reduced to US$1.6 billion and all amounts outstanding were fully repaid by the Government of Alberta in June 2021. Refer to Note 5, Keystone XL, for additional information.

TC Energy Third Quarter 2021 | 61

Long-Term Debt Retired/Repaid

Long-term debt retired/repaid by the Company in the nine months ended September 30, 2021 included the following:

(unaudited - millions of Canadian , unless otherwise noted)
Company	Type	Amount	Interest rate
TransCanada PipeLines Limited	Debentures	US 400	9.875	%
TC PipeLines, LP	Senior Unsecured Notes	US 350	4.65	%
Keystone XL subsidiaries1	Project-Level Credit Facility	US 849	Floating

All values are in US Dollars.

1 In June 2021, in accordance with the terms of the guarantee, the Government of Alberta repaid the US$849 million outstanding balance under the Keystone XL project-level credit facility bearing interest at a floating rate, subsequent to which it was terminated, resulting in no cash impact to TC Energy. Refer to Note 5, Keystone XL, for additional information.

On March 4, 2021, the Company's subsidiary, TC PipeLines, LP, terminated a US$500 million unsecured revolving credit facility bearing interest at a floating rate on which no amount was outstanding.

Capitalized Interest

In the three and nine months ended September 30, 2021, TC Energy capitalized interest related to capital projects of $2 million and $20 million, respectively (2020 – $68 million and $219 million, respectively).

JUNIOR SUBORDINATED NOTES ISSUED

Junior subordinated notes issued by the Company in the nine months ended September 30, 2021 included the following:

(unaudited - millions of Canadian )
Company	Type	Maturity date	Amount	Interest rate
TransCanada PipeLines Limited	Junior Subordinated Notes1	March 2081	500	4.45	%

All values are in US Dollars.

1The Junior subordinated notes were issued to TransCanada Trust, a financing trust subsidiary wholly owned by TCPL. While the obligations of TransCanada Trust are fully and unconditionally guaranteed by TCPL on a subordinated basis, TransCanada Trust is not consolidated in TC Energy's financial statements since TCPL does not have a variable interest in TransCanada Trust and the only substantive assets of TransCanada Trust are junior subordinated notes of TCPL.

In March 2021, TransCanada Trust (the Trust) issued $500 million of Trust Notes – Series 2021-A to investors with a fixed interest rate of 4.20 per cent per annum for the first 10 years and resetting on the 10th anniversary and every five years thereafter. All of the proceeds of the issuance by the Trust were loaned to TCPL for $500 million of junior subordinated notes of TCPL at an initial fixed rate of 4.45 per cent per annum, including a 0.25 per cent administration charge. The rate on the junior subordinated notes of TCPL will reset every five years commencing March 2031 until March 2051 to the then Five Year Government of Canada Yield, as defined in the document governing the subordinated notes, plus 3.316 per cent per annum; from March 2051 until March 2081, the interest rate will reset to the then Five Year Government of Canada Yield plus 4.066 per cent per annum. The junior subordinated notes are callable at TCPL's option at any time from December 4, 2030 to March 4, 2031 and on each interest payment and reset date thereafter at 100 per cent of the principal amount plus accrued and unpaid interest to the date of redemption.

The Junior subordinated notes are subordinated in right of payment to existing and future senior indebtedness and other obligations of TCPL.

62 | TC Energy Third Quarter 2021

NON-CONTROLLING INTERESTS

Acquisition of TC PipeLines, LP

On December 14, 2020, the Company entered into a definitive agreement and plan of merger to acquire all the outstanding common units of TC PipeLines, LP not beneficially owned by TC Energy or its affiliates in exchange for TC Energy common shares. Upon close of the transaction on March 3, 2021, TC PipeLines, LP common unitholders received 0.70 TC Energy common shares for each issued and outstanding publicly-held TC PipeLines, LP common unit representing, in aggregate, 37,955,093 TC Energy common shares. As a result, TC PipeLines, LP became an indirect, wholly-owned subsidiary of TC Energy.

As the Company controlled TC PipeLines, LP, this acquisition was accounted for as an equity transaction with the following impact reflected on the Condensed consolidated balance sheet:

(unaudited - millions of Canadian $)	March 3, 2021
Common shares	2,063
Additional paid-in capital	(398)
Accumulated other comprehensive loss	353
Non-controlling interests	(1,563)
Deferred income tax liabilities	(443)
Other	(12)

COMMON SHARES AND PREFERRED SHARES

The Board of Directors of TC Energy declared quarterly dividends as follows:

	three months ended<br>September 30		nine months ended September 30
(unaudited - Canadian $, rounded to two decimals)	2021	2020	2021	2020
per common share	0.87	0.81	2.61	2.43
per Series 1 preferred share	0.22	0.22	0.65	0.65
per Series 2 preferred share	0.13	0.14	0.38	0.58
per Series 3 preferred share	0.11	0.11	0.32	0.37
per Series 4 preferred share	0.09	0.10	0.26	0.46
per Series 5 preferred share	0.12	0.14	0.37	0.42
per Series 6 preferred share	0.11	0.11	0.31	0.42
per Series 7 preferred share	0.24	0.24	0.73	0.73
per Series 9 preferred share	0.24	0.24	0.71	0.71
per Series 11 preferred share	0.21	0.24	0.42	0.48
per Series 13 preferred share	—	0.34	0.34	0.69
per Series 15 preferred share	0.31	0.31	0.61	0.61

Acquisition of TC PipeLines, LP

On March 3, 2021, TC Energy issued 37,955,093 common shares to acquire all the outstanding publicly-held common units of TC PipeLines, LP. Refer to Note 10, Non-controlling interests, for additional information.

TC Energy Third Quarter 2021 | 63

Preferred Shares

On May 31, 2021, TC Energy redeemed all of the 20,000,000 issued and outstanding Series 13 preferred shares at a redemption price of $25.00 per share and paid the final quarterly dividend of $0.34375 per Series 13 preferred share for the period up to but excluding May 31, 2021 as previously declared on May 6, 2021. The Company used the proceeds from the March 2021 issuance of $500 million of Junior Subordinated Notes through the Trust to finance this preferred share redemption.

OTHER COMPREHENSIVE INCOME/(LOSS) AND ACCUMULATED OTHER COMPREHENSIVE LOSS

Components of other comprehensive income/(loss), including the portion attributable to non-controlling interests and related tax effects, are as follows:

three months ended September 30, 2021	Income Tax Recovery/(Expense)	Net of Tax Amount
(unaudited - millions of Canadian )
Foreign currency translation gains on net investment in foreign operations	9	450
Change in fair value of net investment hedges	9	(27)
Change in fair value of cash flow hedges	4	(15)
Reclassification to net income of gains and losses on cash flow hedges	(3)	15
Reclassification to net income of actuarial gains and losses on pension and other post-retirement benefit plans	(2)	5
Other comprehensive income on equity investments	(9)	25
Other Comprehensive Income	8	453

All values are in US Dollars.

three months ended September 30, 2020	Income Tax Recovery/(Expense)	Net of Tax Amount
(unaudited - millions of Canadian )
Foreign currency translation losses on net investment in foreign operations	(2)	(491)
Change in fair value of net investment hedges	(8)	26
Change in fair value of cash flow hedges	—	(1)
Reclassification to net income of gains and losses on cash flow hedges	(3)	10
Reclassification to net income of actuarial gains and losses on pension and other post-retirement benefit plans	(2)	4
Other comprehensive income on equity investments	(4)	14
Other Comprehensive Loss	(19)	(438)

All values are in US Dollars.

64 | TC Energy Third Quarter 2021

nine months ended September 30, 2021	Income Tax Recovery/(Expense)	Net of Tax Amount
(unaudited - millions of Canadian )
Foreign currency translation losses on net investment in foreign operations	(3)	(81)
Change in fair value of net investment hedges	1	(3)
Change in fair value of cash flow hedges	4	(15)
Reclassification to net income of gains and losses on cash flow hedges	(8)	33
Reclassification to net income of actuarial gains and losses on pension and other post-retirement benefit plans	(4)	12
Other comprehensive income on equity investments	(52)	155
Other Comprehensive Income	(62)	101

All values are in US Dollars.

nine months ended September 30, 2020	Income Tax Recovery/(Expense)	Net of Tax Amount
(unaudited - millions of Canadian )
Foreign currency translation gains on net investment in foreign operations	70	417
Change in fair value of net investment hedges	2	(6)
Change in fair value of cash flow hedges	188	(578)
Reclassification to net income of gains and losses on cash flow hedges	(159)	480
Reclassification to net income of actuarial gains and losses on pension and other post-retirement benefit plans	(1)	1
Other comprehensive loss on equity investments	2	(6)
Other Comprehensive Income	102	308

All values are in US Dollars.

The changes in AOCI by component are as follows:

three months ended September 30, 2021	Cash Flow Hedges	Pension and OPEB Plan Adjustments	Equity Investments	Total1
(unaudited - millions of Canadian )
AOCI balance at July 1, 2021	(139)	(278)	(605)	(2,426)
Other comprehensive income/(loss) before reclassifications2	(15)	—	18	424
Amounts reclassified from AOCI	15	5	7	27
Net current period other comprehensive income	—	5	25	451
AOCI balance at September 30, 2021	(139)	(273)	(580)	(1,975)

All values are in US Dollars.

1All amounts are net of tax. Amounts in parentheses indicate losses recorded to OCI.

2Other comprehensive income/(loss) before reclassifications on currency translation adjustments, cash flow hedges and equity investments are net of non-controlling interest gains of $2 million, nil and nil, respectively.

TC Energy Third Quarter 2021 | 65

nine months ended September 30, 2021	Cash Flow Hedges	Pension and OPEB Plan Adjustments	Equity Investments	Total1
(unaudited - millions of Canadian )
AOCI balance at January 1, 2021	(143)	(285)	(738)	(2,439)
Other comprehensive (loss)/income before reclassifications2	(16)	—	134	46
Amounts reclassified from AOCI3	33	12	20	65
Net current period other comprehensive (loss)/income	17	12	154	111
Acquisition of TC PipeLines, LP4	(13)	—	4	353
AOCI balance at September 30, 2021	(139)	(273)	(580)	(1,975)

All values are in US Dollars.

1All amounts are net of tax. Amounts in parentheses indicate losses recorded to OCI.

2Other comprehensive (loss)/income before reclassifications on currency translation adjustments, cash flow hedges and equity investments are net of non-controlling interest losses of $12 million, gains of $1 million and $1 million, respectively.

3Losses related to cash flow hedges reported in AOCI and expected to be reclassified to net income in the next 12 months are estimated to be $62 million ($47 million, net of tax) at September 30, 2021. These estimates assume constant commodity prices, interest rates and foreign exchange rates over time, however, the amounts reclassified will vary based on the actual value of these factors at the date of settlement.

4Represents the historical OCI attributable to non-controlling interests of TC PipeLines, LP which was reclassified to AOCI upon completion of the acquisition of all the outstanding publicly-held common units of TC PipeLines, LP on March 3, 2021. Refer to Note 10, Non-controlling interests, for additional information.

Details about reclassifications out of AOCI into the Condensed consolidated statement of income are as follows:

	Amounts Reclassified from AOCI				Affected line item in the Condensed consolidated statement of income1
	three months ended<br>September 30		nine months ended <br>September 30
(unaudited - millions of Canadian $)	2021	2020	2021	2020
Cash flow hedges
Commodities	(8)	—	(13)	—	Revenues (Power and Storage)
Interest rate	(10)	(10)	(28)	(21)	Interest expense
Interest rate	—	—	—	(613)	Net (loss)/gain on sale of assets2
	(18)	(10)	(41)	(634)	Total before tax
	3	3	8	159	Income tax expense/(recovery)2
	(15)	(7)	(33)	(475)	Net of tax3
Pension and other post-retirement benefit plan adjustments
Amortization of actuarial losses	(7)	(6)	(16)	(2)	Plant operating costs and other4
	2	2	4	1	Income tax expense/(recovery)
	(5)	(4)	(12)	(1)	Net of tax
Equity investments
Equity income	(9)	(4)	(27)	(11)	Income from equity investments
	2	1	7	3	Income tax expense/(recovery)
	(7)	(3)	(20)	(8)	Net of tax

1All amounts in parentheses indicate expenses to the Condensed consolidated statement of income.

2Includes a loss of $613 million ($459 million, net of tax) for the nine months ended September 30, 2020 related to a contractually required derivative instrument used to hedge the interest rate risk associated with project-level financing of the Coastal GasLink pipeline construction. The derivative instrument was derecognized as part of the sale of a 65 per cent equity interest in Coastal GasLink LP.

3Amounts reclassified from AOCI on cash flow hedges are net of non-controlling interests of nil for the three and nine months ended September 30, 2021 (2020 – losses of $3 million and $5 million, respectively).

4These AOCI components are included in the computation of net benefit cost. Refer to Note 13, Employee post-retirement benefits, for additional information.

66 | TC Energy Third Quarter 2021

EMPLOYEE POST-RETIREMENT BENEFITS

The net benefit cost recognized for the Company’s pension benefit plans and other post-retirement benefit plans is as follows:

	three months ended September 30				nine months ended September 30
	Pension benefit plans		Other <br>post-retirement benefit plans		Pension benefit plans		Other <br>post-retirement benefit plans
(unaudited - millions of Canadian $)	2021	2020	2021	2020	2021	2020	2021	2020
Service cost1	44	39	2	1	129	116	5	4
Other components of net benefit cost1
Interest cost	30	32	3	3	90	100	9	11
Expected return on plan assets	(59)	(58)	(4)	(3)	(176)	(173)	(10)	(11)
Amortization of actuarial losses	7	5	—	—	18	16	1	1
Amortization of regulatory asset	6	7	1	1	20	19	2	2
	(16)	(14)	—	1	(48)	(38)	2	3
Net Benefit Cost	28	25	2	2	81	78	7	7

1Service cost and other components of net benefit cost are included in Plant operating costs and other in the Condensed consolidated statement of income.

TC Energy Third Quarter 2021 | 67

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS

Risk Management Overview

TC Energy has exposure to market risk and counterparty credit risk, and has strategies, policies and limits in place to manage the impact of these risks on earnings, cash flows and shareholder value.

Counterparty credit risk

TC Energy’s exposure to counterparty credit risk includes its cash and cash equivalents, accounts receivable and certain contractual recoveries, available-for-sale assets, the fair value of derivative assets and loans receivable.

While the majority of the Company's credit exposure is to large creditworthy entities, TC Energy maintains close monitoring and communication with those counterparties experiencing greater financial pressures due to significant market events, including the COVID-19 pandemic. Refer to TC Energy's 2020 Annual Report for more information about the factors that mitigate the Company's counterparty credit risk exposure.

The Company reviews financial assets carried at amortized cost for impairment using the lifetime expected loss of the financial asset at initial recognition and throughout the life of the financial asset. TC Energy uses historical credit loss and recovery data, adjusted for management's judgment regarding current economic and credit conditions, along with supportable forecasts to determine any impairment, which is recognized in Plant operating costs and other. At September 30, 2021, there were no significant credit losses, no significant credit risk concentration and no significant amounts past due or impaired.

Net investment in foreign operations

The Company hedges a portion of its net investment in foreign operations (on an after-tax basis) with U.S. dollar-denominated debt, cross-currency interest rate swaps, foreign exchange forwards and foreign exchange options as appropriate.

The fair values and notional amounts for the derivatives designated as a net investment hedge were as follows:

	September 30, 2021		December 31, 2020
(unaudited - millions of Canadian $, unless otherwise noted)	Fair value1,2	Notional amount	Fair value1,2	Notional amount
U.S. dollar foreign exchange options (maturing 2021 to 2023)	7	US 3,600	45	US 2,200
U.S. dollar cross-currency interest rate swaps (maturing 2022 to 2025)	23	US 400	23	US 400
U.S. dollar foreign exchange forward contracts (maturing 2021)3	7	—	—	—
	37	US 4,000	68	US 2,600

1Fair value equals carrying value.

2No amounts have been excluded from the assessment of hedge effectiveness.

3Notional amount presented on a net basis.

The notional amounts and fair values of U.S. dollar-denominated debt designated as a net investment hedge were as follows:

(unaudited - millions of Canadian $, unless otherwise noted)	September 30, 2021	December 31, 2020
Notional amount	25,800 (US 20,400)	27,700 (US 21,800)
Fair value	31,300 (US 24,700)	33,800 (US 26,500)

68 | TC Energy Third Quarter 2021

Non-derivative financial instruments

Fair value of non-derivative financial instruments

Available-for-sale assets are recorded at fair value which is calculated using quoted market prices where available. Certain non-derivative financial instruments included in Cash and cash equivalents, Accounts receivable, Other current assets, Loan receivable from affiliate, Restricted investments, Other long-term assets, Notes payable, Accounts payable and other, Dividends payable, Accrued interest and Other long-term liabilities have carrying amounts that approximate their fair value due to the nature of the item or the short time to maturity. Each of these instruments are classified in Level II of the fair value hierarchy, except for the Company's LMCI equity securities which are classified in Level I.

Credit risk has been taken into consideration when calculating the fair value of non-derivative instruments.

Balance sheet presentation of non-derivative financial instruments

The following table details the fair value of non-derivative financial instruments, excluding those where carrying amounts approximate fair value, and would be classified in Level II of the fair value hierarchy:

	September 30, 2021		December 31, 2020
(unaudited - millions of Canadian $)	Carrying<br><br>amount	Fair<br><br>value	Carrying<br><br>amount	Fair<br><br>value
Long-term debt including current portion	(42,470)	(49,875)	(36,885)	(46,054)
Junior subordinated notes	(8,948)	(9,494)	(8,498)	(8,908)
	(51,418)	(59,369)	(45,383)	(54,962)

Available-for-sale assets summary

The following tables summarize additional information about the Company's restricted investments that were classified as available-for-sale assets:

	September 30, 2021		December 31, 2020
(unaudited - millions of Canadian $)	LMCI restricted investments	Other restricted investments1	LMCI restricted investments	Other restricted investments1
Fair values of fixed income securities2,3
Maturing within 1 year	—	42	—	17
Maturing within 1-5 years	—	89	—	66
Maturing within 5-10 years	1,097	—	985	—
Maturing after 10 years	78	—	85	—
Fair value of equity securities2,4	775	—	736	—
	1,950	131	1,806	83

1Other restricted investments have been set aside to fund insurance claim losses to be paid by the Company's wholly-owned captive insurance subsidiary.

2Available-for-sale assets are recorded at fair value and included in Other current assets and Restricted investments on the Company's Condensed consolidated balance sheet.

3Classified in Level II of the fair value hierarchy.

4Classified in Level I of the fair value hierarchy.

TC Energy Third Quarter 2021 | 69

	September 30, 2021		September 30, 2020
(unaudited - millions of Canadian $)	LMCI restricted investments1	Other restricted investments2	LMCI restricted investments1	Other restricted investments2
Net unrealized (losses)/gains in the period
three months ended	(13)	—	27	—
nine months ended	(4)	(1)	88	3
Net realized gains in the period 3
three months ended	9	—	5	—
nine months ended	6	—	15	—

1Gains and losses arising from changes in the fair value of LMCI restricted investments impact the subsequent amounts to be collected through tolls to cover future pipeline abandonment costs. As a result, the Company records these gains and losses as regulatory assets or liabilities.

2Gains and losses on other restricted investments are included in Interest income and other in the Condensed consolidated statement of income.

3Realized gains and losses on the sale of LMCI restricted investments are determined using the average cost basis.

Derivative instruments

Fair value of derivative instruments

The fair value of foreign exchange and interest rate derivatives has been calculated using the income approach which uses period-end market rates and applies a discounted cash flow valuation model. The fair value of commodity derivatives has been calculated using quoted market prices where available. In the absence of quoted market prices, third-party broker quotes or other valuation techniques have been used. The fair value of options has been calculated using the Black-Scholes pricing model. Credit risk has been taken into consideration when calculating the fair value of derivative instruments. Unrealized gains and losses on derivative instruments are not necessarily representative of the amounts that will be realized on settlement.

In some cases, even though the derivatives are considered to be effective economic hedges, they do not meet the specific criteria for hedge accounting treatment or are not designated as a hedge and are accounted for at fair value with changes in fair value recorded in net income in the period of change. This may expose the Company to increased variability in reported earnings because the fair value of the derivative instruments can fluctuate significantly from period to period.

70 | TC Energy Third Quarter 2021

Balance sheet presentation of derivative instruments

The balance sheet classification of the fair value of derivative instruments was as follows:

at September 30, 2021	Net<br> Investment Hedges	Held for<br> Trading	Total Fair Value of Derivative Instruments1
(unaudited - millions of Canadian )
Other current assets
Commodities2	—	119	119
Foreign exchange	27	61	88
	27	180	207
Other long-term assets
Commodities2	—	12	12
Foreign exchange	31	1	32
	31	13	44
Total Derivative Assets	58	193	251
Accounts payable and other
Commodities2	—	(175)	(200)
Foreign exchange	(3)	(47)	(50)
Interest rate	—	—	(22)
	(3)	(222)	(272)
Other long-term liabilities
Commodities2	—	(6)	(13)
Foreign exchange	(18)	(13)	(31)
Interest rate	—	—	(19)
	(18)	(19)	(63)
Total Derivative Liabilities	(21)	(241)	(335)
Total Derivatives	37	(48)	(84)

All values are in US Dollars.

1Fair value equals carrying value.

2Includes purchases and sales of power, natural gas and liquids.

TC Energy Third Quarter 2021 | 71

at December 31, 2020	Net<br> Investment Hedges	Held for<br> Trading	Total Fair Value of Derivative Instruments1
(unaudited - millions of Canadian )
Other current assets
Commodities2	—	13	13
Foreign exchange	47	175	222
	47	188	235
Other long-term assets
Foreign exchange	22	19	41
	22	19	41
Total Derivative Assets	69	207	276
Accounts payable and other
Commodities2	—	(32)	(40)
Foreign exchange	(1)	(10)	(11)
Interest rate3	—	—	(21)
	(1)	(42)	(72)
Other long-term liabilities
Commodities2	—	(4)	(10)
Interest rate3	—	—	(49)
	—	(4)	(59)
Total Derivative Liabilities	(1)	(46)	(131)
Total Derivatives	68	161	145

All values are in US Dollars.

1Fair value equals carrying value.

2Includes purchases and sales of power, natural gas and liquids.

3For the nine months ended September 30, 2020, a $130 million payment to settle a loss on financial instruments was included in Net cash provided by/(used in) financing activities in the Condensed consolidated statement of cash flows.

The majority of derivative instruments held for trading have been entered into for risk management purposes and all are subject to the Company's risk management strategies, policies and limits. These include derivatives that have not been designated as hedges or do not qualify for hedge accounting treatment but have been entered into as economic hedges to manage the Company's exposures to market risk.

Notional and maturity summary

The maturity and notional amount or quantity outstanding related to the Company's derivative instruments excluding hedges of the net investment in foreign operations was as follows:

at September 30, 2021	Power	Natural Gas	Liquids	Foreign Exchange	Interest Rate
(unaudited)
Purchases1	607	128	61	—	—
Sales1	1,261	72	25	—	—
Millions of U.S. dollars	—	—	—	6,582	1,100
Millions of Mexican pesos	—	—	—	4,947	—
Maturity dates	2021-2026	2021-2027	2021-2028	2021-2023	2022-2026

1Volumes for power, natural gas and liquids derivatives are in GWh, Bcf and MMBbls, respectively.

72 | TC Energy Third Quarter 2021

at December 31, 2020	Power	Natural Gas	Liquids	Foreign Exchange	Interest Rate
(unaudited)
Purchases1	185	13	26	—	—
Sales1	1,786	14	30	—	—
Millions of U.S. dollars	—	—	—	4,432	1,100
Millions of Mexican pesos	—	—	—	1,700	—
Maturity dates	2021-2025	2021-2027	2021	2021-2022	2022-2026

1Volumes for power, natural gas and liquids derivatives are in GWh, Bcf and MMBbls, respectively.

Unrealized and realized (losses)/gains on derivative instruments

The following summary does not include hedges of the net investment in foreign operations:

	three months ended<br>September 30		nine months ended <br>September 30
(unaudited - millions of Canadian $)	2021	2020	2021	2020
Derivative Instruments Held for Trading1
Amount of unrealized (losses)/gains in the period
Commodities	(43)	(2)	(27)	14
Foreign exchange	(125)	78	(183)	(24)
Amount of realized gains/(losses) in the period
Commodities	58	68	167	146
Foreign exchange	37	(11)	195	(62)
Derivative Instruments in Hedging Relationships2
Amount of realized (losses)/gains in the period
Commodities	(9)	2	(32)	4
Interest rate	(6)	(6)	(18)	(10)

Derivatives in cash flow hedging relationships

The components of OCI (Note 12) related to the change in fair value of derivatives in cash flow hedging relationships before tax and including the portion attributable to non-controlling interests were as follows:

	three months ended<br>September 30		nine months ended <br>September 30
(unaudited - millions of Canadian $, pre-tax)	2021	2020	2021	2020
Change in fair value of derivative instruments recognized in OCI1
Commodities	(16)	(1)	(31)	5
Interest rate	(3)	—	12	(771)
	(19)	(1)	(19)	(766)

1No amounts have been excluded from the assessment of hedge effectiveness. Amounts in parentheses indicate losses recorded to OCI.

TC Energy Third Quarter 2021 | 73

Effect of fair value and cash flow hedging relationships

The following table details amounts presented in the Condensed consolidated statement of income in which the effects of fair value or cash flow hedging relationships were recorded:

	three months ended September 30		nine months ended September 30
(unaudited - millions of Canadian $)	2021	2020	2021	2020
Fair Value Hedges
Interest rate contracts1
Hedged items	—	2	—	(3)
Derivatives designated as hedging instruments	—	—	—	1
Cash Flow Hedges
Reclassification of losses on derivative instruments from AOCI to net income2,3
Interest rate contracts1	(10)	(13)	(28)	(639)
Commodity contracts4	(8)	—	(13)	—

1Presented within Interest expense in the Condensed consolidated statement of income, except for a loss of $613 million recorded in May 2020 related to a contractually required derivative instrument used to hedge the interest rate risk associated with project-level financing of the Coastal GasLink pipeline construction. The derivative instrument was derecognized as part of the sale of a 65 per cent equity interest in Coastal GasLink LP. The loss was included in Net (loss)/gain on sale of assets.

2Refer to Note 12, Other comprehensive income/(loss) and accumulated other comprehensive loss, for the components of OCI related to derivatives in cash flow hedging relationships including the portion attributable to non-controlling interests.

3There are no amounts recognized in earnings that were excluded from effectiveness testing.

4Presented within Revenues (Power and Storage) in the Condensed consolidated statement of income.

Offsetting of derivative instruments

The Company enters into derivative contracts with the right to offset in the normal course of business as well as in the event of default. TC Energy has no master netting agreements, however, similar contracts are entered into containing rights to offset. The Company has elected to present the fair value of derivative instruments with the right to offset on a gross basis on the Condensed consolidated balance sheet. The following table shows the impact on the presentation of the fair value of derivative instrument assets and liabilities had the Company elected to present these contracts on a net basis:

at September 30, 2021	Amounts available<br><br>for offset1	Net amounts
(unaudited - millions of Canadian )
Derivative instrument assets
Commodities	(107)	24
Foreign exchange	(68)	52
	(175)	76
Derivative instrument liabilities
Commodities	107	(106)
Foreign exchange	68	(13)
Interest rate	—	(41)
	175	(160)

All values are in US Dollars.

1Amounts available for offset do not include cash collateral pledged or received.

74 | TC Energy Third Quarter 2021

at December 31, 2020	Amounts available<br><br>for offset1	Net amounts
(unaudited - millions of Canadian )
Derivative instrument assets
Commodities	(7)	6
Foreign exchange	(11)	252
	(18)	258
Derivative instrument liabilities
Commodities	7	(43)
Foreign exchange	11	—
Interest rate	—	(70)
	18	(113)

All values are in US Dollars.

1Amounts available for offset do not include cash collateral pledged or received.

With respect to the derivative instruments presented above, the Company provided cash collateral of $129 million and letters of credit of $66 million at September 30, 2021 (December 31, 2020 – $54 million and $39 million, respectively) to its counterparties. At September 30, 2021, the Company held no cash collateral and a $6 million balance in letters of credit (December 31, 2020 – nil and nil, respectively) from counterparties on asset exposures.

Credit-risk-related contingent features of derivative instruments

Derivative contracts entered into to manage market risk often contain financial assurance provisions that allow parties to the contracts to manage credit risk. These provisions may require collateral to be provided if a credit-risk-related contingent event occurs, such as a downgrade in the Company’s credit rating to non-investment grade. The Company may also need to provide collateral if the fair value of its derivative financial instruments exceeds pre-defined exposure limits.

Based on contracts in place and market prices at September 30, 2021, the aggregate fair value of all derivative instruments with credit-risk-related contingent features that were in a net liability position was $5 million (December 31, 2020 – $4 million), for which the Company has provided no collateral in the normal course of business. If the credit-risk-related contingent features in these agreements were triggered on September 30, 2021, the Company would have been required to provide collateral equal to the fair value of the related derivative instruments discussed above. Collateral may also need to be provided should the fair value of derivative instruments exceed pre-defined contractual exposure limit thresholds.

The Company has sufficient liquidity in the form of cash and undrawn committed revolving credit facilities to meet these contingent obligations should they arise.

TC Energy Third Quarter 2021 | 75

Fair Value Hierarchy

The Company’s financial assets and liabilities recorded at fair value have been categorized into three categories based on a fair value hierarchy.

Levels	How fair value has been determined
Level I	Quoted prices in active markets for identical assets and liabilities that the Company has the ability to access at the measurement date. An active market is a market in which frequency and volume of transactions provides pricing information on an ongoing basis.
Level II	This category includes interest rate and foreign exchange derivative assets and liabilities where fair value is determined using the income approach and commodity derivatives where fair value is determined using the market approach.<br><br>Inputs include published exchange rates, interest rates, interest rate swap curves, yield curves and broker quotes from external data service providers.
Level III	This category includes long-dated commodity transactions in certain markets where liquidity is low and the Company uses the most observable inputs available or, if not available, long-term broker quotes to estimate the fair value for these transactions.<br><br>There is uncertainty caused by using unobservable market data which may not accurately reflect possible future changes in fair value.

The fair value of the Company’s derivative assets and liabilities measured on a recurring basis, including both current and non-current portions, were categorized as follows:

at September 30, 2021	Significant other observable inputs (Level II)1		Significant unobservable inputs <br>(Level III)1
(unaudited - millions of Canadian )		Total
Derivative instrument assets
Commodities	107		—	131
Foreign exchange	120		—	120
Derivative instrument liabilities
Commodities	(163)		(6)	(213)
Foreign exchange	(81)		—	(81)
Interest rate	(41)		—	(41)
	(58)		(6)	(84)

All values are in US Dollars.

1There were no transfers from Level II to Level III for the nine months ended September 30, 2021.

at December 31, 2020	Significant other observable inputs (Level II)1		Significant unobservable inputs<br><br>(Level III)1
(unaudited - millions of Canadian )		Total
Derivative instrument assets
Commodities	10		—	13
Foreign exchange	263		—	263
Derivative instrument liabilities
Commodities	(31)		(4)	(50)
Foreign exchange	(11)		—	(11)
Interest rate	(70)		—	(70)
	161		(4)	145

All values are in US Dollars.

1There were no transfers from Level II to Level III for the year ended December 31, 2020.

76 | TC Energy Third Quarter 2021

The following table presents the net change in fair value of derivative assets and liabilities classified as Level III of the fair value hierarchy:

	three months ended<br>September 30		nine months ended <br>September 30
(unaudited - millions of Canadian $)	2021	2020	2021	2020
Balance at beginning of period	(5)	(4)	(4)	(7)
Total (losses)/gains included in Net income	(1)	1	(2)	4
Total losses included in OCI	—	(1)	—	(1)
Balance at end of period1	(6)	(4)	(6)	(4)

1For the three and nine months ended September 30, 2021, there were unrealized losses of $1 million and $2 million, respectively, recognized in Revenues attributed to derivatives in the Level III category that were held at September 30, 2021 (2020 – unrealized gains of $1 million and $4 million, respectively).

COMMITMENTS, CONTINGENCIES AND GUARANTEES

Commitments

TC Energy’s capital expenditure commitments at December 31, 2020 included certain construction costs associated with the Keystone XL pipeline project. Following the revocation of the Presidential Permit for the Keystone XL pipeline on January 20, 2021, the Company and its partner terminated the project on June 9, 2021. As a result, capital commitments related to Keystone XL have been reduced by approximately $0.9 billion. Refer to Note 5, Keystone XL, for more information.

Contingencies

TC Energy and its subsidiaries are subject to various legal proceedings, arbitrations and actions arising in the normal course of business. While the final outcome of such legal proceedings and actions cannot be predicted with certainty, it is the opinion of management that the resolution of such proceedings and actions, excluding the legal proceeding related to Keystone XL described below, will not have a material impact on the Company’s consolidated financial position or results of operations.

On July 2, 2021, TC Energy filed a Notice of Intent to 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. The Company will be seeking to recover more than US$15 billion in damages as a result of the U.S. Government's breach of its NAFTA obligations. This claim is in a preliminary stage and the timing of outcome is unknown at present.

Guarantees

As part of its role as operator of the Northern Courier pipeline, TC Energy has guaranteed the financial performance of the pipeline related to delivery and terminalling of bitumen and diluent and contingent financial obligations under sub-lease agreements.

TC Energy and its partner on the Sur de Texas pipeline, IEnova, have jointly guaranteed the financial performance of the entity which owns the pipeline. Such agreements include a guarantee and a letter of credit which are primarily related to the delivery of natural gas.

TC Energy and its joint venture partner on Bruce Power, BPC Generation Infrastructure Trust, have each severally guaranteed certain contingent financial obligations of Bruce Power related to a lease agreement and contractor and supplier services.

The Company and its partners in certain other jointly-owned entities have either (i) jointly and severally, (ii) jointly or (iii) severally guaranteed the financial performance of these entities. Such agreements include guarantees and letters of credit which are primarily related to construction services and the payment of liabilities. For certain of these entities, any payments made by TC Energy under these guarantees in excess of its ownership interest are to be reimbursed by its partners.

TC Energy Third Quarter 2021 | 77

The carrying value of these guarantees has been included in Other long-term liabilities on the Condensed consolidated balance sheet. Information regarding the Company’s guarantees is as follows:

		September 30, 2021		December 31, 2020
(unaudited - millions of Canadian $)	Term	Potential<br>exposure1	Carrying<br><br>value	Potential<br>exposure1	Carrying<br>value
Northern Courier	to 2055	300	26	300	26
Sur de Texas	to 2043	100	—	100	—
Bruce Power	to 2023	88	—	88	—
Other jointly-owned entities	to 2043	80	4	78	4
		568	30	566	30

1TC Energy's share of the potential estimated current or contingent exposure.

VARIABLE INTEREST ENTITIES

Consolidated VIEs

The Company's consolidated VIEs consist of legal entities where the Company is the primary beneficiary. As the primary beneficiary, the Company has the power, through voting or similar rights, to direct the activities of the VIE that most significantly impact economic performance including purchasing or selling significant assets; maintenance and operations of assets; incurring additional indebtedness; or determining the strategic operating direction of the entity. In addition, the Company has the obligation to absorb losses or the right to receive benefits from the consolidated VIE that could potentially be significant to the VIE. A significant portion of the Company’s assets are held through VIEs in which the Company holds a 100 per cent voting interest, the VIE meets the definition of a business and the VIE’s assets can be used for general corporate purposes. The consolidated VIEs whose assets cannot be used for purposes other than the settlement of the VIE’s obligations, or are not considered a business, are as follows:

78 | TC Energy Third Quarter 2021

(unaudited - millions of Canadian $)	September 30, 2021	December 31, 2020
ASSETS
Current Assets
Cash and cash equivalents	35	254
Accounts receivable	66	61
Inventories	28	26
Other	13	11
	142	352
Plant, Property and Equipment	3,619	3,325
Equity Investments	702	714
Goodwill	421	424
Other Long-Term Assets	—	8
	4,884	4,823
LIABILITIES
Current Liabilities
Accounts payable and other	263	109
Redeemable non-controlling interest	—	633
Accrued interest	22	21
Current portion of long-term debt	105	579
	390	1,342
Regulatory Liabilities	64	60
Other Long-Term Liabilities	3	11
Deferred Income Tax Liabilities	12	12
Long-Term Debt	2,557	2,468
	3,026	3,893

At December 31, 2020, certain consolidated VIEs had a redeemable non-controlling interest that ranked above the Company's equity interest. Refer to Note 5, Keystone XL, for additional information.

TC Energy Third Quarter 2021 | 79

Non-Consolidated VIEs

The Company’s non-consolidated VIEs consist of legal entities where the Company is not the primary beneficiary as it does not have the power to direct the activities that most significantly impact the economic performance of these VIEs or where this power is shared with third parties. The Company contributes capital to these VIEs and receives ownership interests that provide it with residual claims on assets after liabilities are paid.

The carrying value of these VIEs and the maximum exposure to loss as a result of the Company's involvement with these VIEs are as follows:

(unaudited - millions of Canadian $)	September 30, 2021	December 31, 2020
Balance sheet
Equity investments
Bruce Power	3,777	3,306
Pipeline equity investments	1,597	1,371
Current loan receivable from affiliate1	840	—
Off-balance sheet exposure2
Bruce Power	1,077	1,183
Pipeline equity investments	1,655	1,506
Maximum exposure to loss	8,946	7,366

1 Refer to Note 7, Loans receivable from affiliates, for additional information.

2 Includes maximum potential exposure to guarantees and future funding commitments. Subsequent to September 30, 2021, TC Energy committed an additional $2.2 billion, if necessary, for temporary financing with respect to its pipeline equity investments.

SUBSEQUENT EVENT

Long-Term Debt Issuance

80 | TC Energy Third Quarter 2021

Document

EXHIBIT 31.1

Certifications

I, François L. Poirier, certify that:

1.I have reviewed this quarterly report on Form 6-K of TC Energy Corporation;

2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the issuer as of, and for, the periods presented in this report;

4.The issuer’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the issuer and have:

(a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the issuer, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b)Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c)Evaluated the effectiveness of the issuer’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d)Disclosed in this report any change in the issuer’s internal control over financial reporting that occurred during the issuer’s most recent fiscal quarter (the issuer’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the issuer’s internal control over financial reporting; and

5.The issuer’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the issuer’s auditors and the audit committee of the issuer’s board of directors (or persons performing the equivalent functions):

(a)All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the issuer’s ability to record, process, summarize and report financial information; and

(b)Any fraud, whether or not material, that involves management or other employees who have a significant role in the issuer’s internal control over financial reporting.

Dated: November 5, 2021	/s/ François L. Poirier
	François L. Poirier
	President and Chief Executive Officer

1 of 2

Certifications

I, François L. Poirier, certify that:

1.I have reviewed this quarterly report on Form 6-K of TransCanada PipeLines Limited;

(b)Any fraud, whether or not material, that involves management or other employees who have a significant role in the issuer’s internal control over financial reporting.

Dated: November 5, 2021	/s/ François L. Poirier
	François L. Poirier
	President and Chief Executive Officer

2 of 2

Document

EXHIBIT 31.2

Certifications

I, Joel E. Hunter, certify that:

1.I have reviewed this quarterly report on Form 6-K of TC Energy Corporation;

(b)Any fraud, whether or not material, that involves management or other employees who have a significant role in the issuer’s internal control over financial reporting.

Dated: November 5, 2021	/s/ Joel E. Hunter
	Joel E. Hunter
	Executive Vice-President and Chief Financial Officer

1 of 2

Certifications

I, Joel E. Hunter, certify that:

1.I have reviewed this quarterly report on Form 6-K of TransCanada PipeLines Limited;

(b)Any fraud, whether or not material, that involves management or other employees who have a significant role in the issuer’s internal control over financial reporting.

Dated: November 5, 2021	/s/ Joel E. Hunter
	Joel E. Hunter
	Executive Vice-President and Chief Financial Officer

2 of 2

Document

EXHIBIT 32.1

TC ENERGY CORPORATION

450 – 1st Street S.W.

Calgary, Alberta, Canada

T2P 5H1

CERTIFICATION OF CHIEF EXECUTIVE OFFICER

REGARDING PERIODIC REPORT CONTAINING

FINANCIAL STATEMENTS

I, François L. Poirier, the Chief Executive Officer of TC Energy Corporation (the "Company"), in compliance with 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, hereby certify, in connection with the Company’s Quarterly Report as filed on Form 6-K for the period ended September 30, 2021 with the Securities and Exchange Commission (the "Report"), that:

1.the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

2.the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ François L. Poirier
François L. Poirier
Chief Executive Officer
November 5, 2021

1 of 2

TRANSCANADA PIPELINES LIMITED

450 – 1st Street S.W.

Calgary, Alberta, Canada

T2P 5H1

CERTIFICATION OF CHIEF EXECUTIVE OFFICER

REGARDING PERIODIC REPORT CONTAINING

FINANCIAL STATEMENTS

I, François L. Poirier, the Chief Executive Officer of TransCanada PipeLines Limited (the "Company"), in compliance with 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, hereby certify, in connection with the Company's Quarterly Report as filed on Form 6-K for the period ended September 30, 2021 with the Securities and Exchange Commission (the "Report"), that:

1.the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

2.the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ François L. Poirier
François L. Poirier
Chief Executive Officer
November 5, 2021

2 of 2

Document

EXHIBIT 32.2

TC ENERGY CORPORATION

450 – 1st Street S.W.

Calgary, Alberta, Canada

T2P 5H1

CERTIFICATION OF CHIEF FINANCIAL OFFICER

REGARDING PERIODIC REPORT CONTAINING

FINANCIAL STATEMENTS

I, Joel E. Hunter, the Chief Financial Officer of TC Energy Corporation (the "Company"), in compliance with 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, hereby certify, in connection with the Company’s Quarterly Report as filed on Form 6-K for the period ended September 30, 2021 with the Securities and Exchange Commission (the "Report"), that:

1.the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

2.the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ Joel E. Hunter
Joel E. Hunter
Chief Financial Officer
November 5, 2021

1 of 2

TRANSCANADA PIPELINES LIMITED

450 – 1st Street S.W.

Calgary, Alberta, Canada

T2P 5H1

CERTIFICATION OF CHIEF FINANCIAL OFFICER

REGARDING PERIODIC REPORT CONTAINING

FINANCIAL STATEMENTS

I, Joel E. Hunter, the Chief Financial Officer of TransCanada PipeLines Limited (the "Company"), in compliance with 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, hereby certify, in connection with the Company's Quarterly Report as filed on Form 6-K for the period ended September 30, 2021 with the Securities and Exchange Commission (the "Report"), that:

1.the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

2.the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ Joel E. Hunter
Joel E. Hunter
Chief Financial Officer
November 5, 2021

2 of 2

Document

EXHIBIT 99.1

Quarterly Report to Shareholders

TC Energy reports strong results while progressing numerous growth initiatives

Expects to sanction approximately $7 billion of new capital projects in 2021

Modified dividend growth outlook enhances ability to fund substantial new growth opportunities

CALGARY, Alberta – November 5, 2021 – TC Energy Corporation (TSX, NYSE: TRP) (TC Energy or the Company) today announced net income attributable to common shares for third quarter 2021 of $779 million or $0.80 per share compared to net income of $904 million or $0.96 per share for the same period in 2020. Comparable earnings for third quarter 2021 were $1.0 billion or $0.99 per common share compared to $893 million or $0.95 per common share in 2020. TC Energy's Board of Directors also declared a quarterly dividend of $0.87 per common share for the quarter ending December 31, 2021, equivalent to $3.48 per common share on an annualized basis.

"During the first nine months of 2021, our diversified portfolio of essential energy infrastructure assets continued to perform very well and reliably meet North America's growing demand for energy," said François Poirier, TC Energy’s President and Chief Executive Officer. "Comparable earnings of $3.21 per common share were five per cent higher compared to the same period last year while comparable funds generated from operations totaled $5.3 billion. Both amounts reflect the strong performance of our assets and the utility-like nature of our business together with contributions from projects that entered service in 2020 and 2021."

Our results are underpinned by strong demand for our services along with a constant focus on operational excellence. Flows and utilization levels across many of our systems are higher than historical norms despite the ongoing impacts of COVID-19 and energy market volatility. Given the strong performance year-to-date, we now expect full-year 2021 comparable earnings per share to be modestly higher than last year's record results.

"We are advancing our $22 billion secured capital program and working on a substantive number of other similarly high-quality opportunities," continued Poirier. "Importantly, all of our secured capital projects are underpinned by long-term contracts and/or regulated business models highlighting the fundamental need for this critical new infrastructure while at the same time giving us visibility to the earnings and cash flow they will generate as they enter service."

Looking forward, TC Energy expects its industry leading portfolio of secured capital projects to grow substantially in the coming years as it continues to expand, extend and modernize its existing natural gas pipeline network, advances the Bruce Power life extension program and progresses plans to use renewable energy to power certain of its proprietary energy loads. The Company is also working on numerous other renewable energy projects – from pumped hydro storage to solar to wind and progressing new initiatives in carbon transportation and sequestration as well as large-scale hydrogen production hubs. Success in advancing our current slate of secured projects and various other growth initiatives is expected to support long-term growth in earnings before interest, taxes, depreciation and amortization, or EBITDA, as well as earnings and cash flow per share. Given the capital required to prudently fund this program, TC Energy is modifying its dividend growth outlook.

“We are in the midst of an unprecedented period that is providing a significant number of investment opportunities driven by both the growing demand for energy and the transition to a cleaner energy future,” added Poirier. "We expect to sanction approximately $7 billion of new projects in 2021 with a risk-adjusted return profile that is consistent with previous investments and anticipate annual amounts of more than $5 billion will be added to our secured projects portfolio in each of the next several years."

“In order to judiciously fund our attractive suite of growth opportunities, maintain a strong financial position and enhance our already conservative, utility-like dividend payout ratios, we have modified our near-term dividend growth outlook,” continued Poirier. “We now expect to increase our common share dividend at an average annual rate of three to five per cent. While our previous outlook remains affordable and supported by the strong underlying performance of our business, we believe a modest change is prudent given our vast opportunity set. It will allow us to fund a larger portion of our future capital programs through internally generated cash flow, moderate our leverage and continue to deliver superior long-term total shareholder returns.”

TC Energy remains committed to the sustainable development of its business. To be truly sustainable, we will continue to evolve and innovate by finding creative ways to deliver the energy people need while being positive agents of change within our society. Modernizing our existing systems and assets, decarbonizing our own energy consumption, and driving digital solutions and technologies are some of the areas we are focused on while also seeking opportunities to invest in low-carbon energy and infrastructure. We recently released our 2021 Report on Sustainability which includes targets for all our sustainability commitments. Notably we have set Scope 1 and Scope 2 GHG reduction targets, including reducing the emissions intensity from our operations 30 per cent by 2030 and positioning to achieve net zero emissions from our operations by 2050. We are advancing numerous renewable energy projects and proceeding with new ventures, like our partnerships with Pembina Pipeline Corporation to jointly develop a carbon transportation and sequestration system in Alberta, Irving Oil to jointly develop clean energy projects in eastern Canada, and Nikola Corporation to co-develop large-scale hydrogen production facilities in the United States and Canada, while remaining committed to important projects like Bruce Power’s multi-billion dollar life extension and uprate programs which will continue to be a source of significant emission-less power in Ontario for decades to come.

In all our operations and projects, we remain focused on managing and reducing our GHG emissions and building constructive, enduring relationships with our communities and stakeholders. We believe our creativity, technical strength and unparalleled market connectivity provide us the ability to prosper regardless of the pace and direction of energy transition.

Highlights

(All financial figures are unaudited and in Canadian dollars unless otherwise noted)

•Third quarter 2021 financial results

◦Net income attributable to common shares of $779 million or $0.80 per common share

◦Comparable earnings of $1.0 billion or $0.99 per common share

◦Comparable EBITDA of $2.2 billion

◦Net cash provided by operations of $1.7 billion

◦Comparable funds generated from operations of $1.6 billion

•Declared a quarterly dividend of $0.87 per common share for the quarter ending December 31, 2021

•Continued to advance our $22 billion secured capital program by investing $1.7 billion in various growth projects

•Began construction on the 2022 NGTL System Expansion Program

•Continued to actively develop projects on our U.S. Natural Gas Pipeline network that will replace and upgrade certain facilities while reducing emissions including the US$0.8 billion WR project on ANR

•Uncontested GTN rate settlement filed with FERC which would set new recourse rates for GTN effective January 1, 2022

•Filed Columbia Gas rate settlement with FERC in October which includes continuation of its modernization program with approval expected in early 2022

•Executed a 15-year Power Purchase Agreement (PPA) in September for 100 per cent of the power produced and the rights to all environmental attributes from the 297 MW Sharp Hills Wind Farm

•Advanced the Bruce Power Unit 6 MCR program on budget and on schedule

•Project 2030 launched by Bruce Power with the goal of achieving a site peak output of 7,000 MW by 2030 in support of climate change targets and future clean energy needs

•Continued to develop a 1,000 MW pumped hydro storage project in Meaford, Ontario which is designed to provide emission-free electricity to the province while reducing greenhouse gas emissions

•Signed a memorandum of understanding in August with Irving Oil to explore the joint development of a series of proposed energy projects focused on reducing greenhouse gas emissions and creating new economic opportunities in New Brunswick and Atlantic Canada

•Partnered with Nikola Corporation in October to collaborate on developing, constructing, operating and owning large-scale hydrogen production facilities in the United States and Canada

•Issued US$1.25 billion of 3-year and US$1.0 billion of 10-year fixed rate Senior Unsecured Notes in October

•Released our 2021 Report on Sustainability in October which includes targets for our sustainability commitments, including reducing the emissions intensity from our operations 30 per cent by 2030 and positioning to achieve net zero emissions from our operations by 2050.

Net income attributable to common shares decreased by $125 million or $0.16 per common share to $779 million or $0.80 per share for the three months ended September 30, 2021 compared to the same period last year. Per share results include the impact of common shares issued for the acquisition of the remaining ownership interests in TC PipeLines, LP in first quarter 2021. Net income attributable to common shares includes a number of specific items that we believe are significant but not reflective of our underlying operations in the period. More information on these items, which are excluded from comparable earnings, can be found in the table entitled "Reconciliation of net income to comparable earnings" in our third quarter MD&A.

Comparable EBITDA of $2.2 billion decreased by $54 million for the three months ended September 30, 2021 compared to the same period in 2020 primarily due to the net effect of the following:

•decreased earnings from Liquids Pipelines as a result of lower contributions from liquids marketing activities, mainly attributable to lower margins

•foreign exchange impact of a weaker U.S. dollar on the Canadian dollar equivalent segmented earnings in our U.S. dollar-denominated operations. U.S. dollar-denominated comparable EBITDA increased by US$53 million to US$1.1 billion compared to 2020, however, this was translated at a rate of 1.26 in 2021 versus 1.33 in 2020.

Comparable earnings of $1.0 billion or $0.99 per common share increased by $79 million or $0.04 per common share for the three months ended September 30, 2021 compared to the same period in 2020 and was primarily the net effect of:

•changes in comparable EBITDA described above

•decreased Non-controlling interests following the March 3, 2021 acquisition of all outstanding common units of TC PipeLines, LP not beneficially owned by TC Energy

•higher Interest expense primarily due to lower capitalized interest as a result of its cessation for the Keystone XL pipeline project following the revocation of the Presidential Permit in January 2021, partially offset by the foreign exchange impact from a weaker U.S. dollar on translation of U.S. dollar-denominated interest.

Comparable earnings per share also reflects the impact of common shares issued for the acquisition of the remaining ownership interests in TC PipeLines, LP in first quarter 2021.

Certain of our businesses generate all or most of their earnings in U.S. dollars and, since we report our financial results in Canadian dollars, changes in the value of the U.S. dollar against the Canadian dollar directly affect our comparable EBITDA and may also impact comparable earnings. As our U.S. dollar-denominated operations continue to grow, this exposure increases. A portion of the U.S. dollar-denominated comparable EBITDA exposure is naturally offset by U.S. dollar-denominated amounts below comparable EBITDA within Depreciation and amortization, Interest expense and other income statement line items. The balance of the exposure is actively managed on a rolling two-year forward basis using foreign exchange derivatives, however, the natural exposure beyond that period remains. As noted previously, the net impact of the U.S. dollar movements on comparable earnings for the three months ended September 30, 2021 compared to 2020, after considering natural offsets and economic hedges, was not significant.

NOTABLE RECENT DEVELOPMENTS INCLUDE:

Canadian Natural Gas Pipelines

•Coastal GasLink: As a result of scope changes, previous permit delays compared to the original construction schedule and the impacts from COVID-19, including a British Columbia provincial health order, we continue to expect project costs to increase significantly along with a delay to project completion compared to the original project cost and schedule. Coastal GasLink has sought and will continue to mitigate cost increases and schedule delays. Coastal GasLink expects incremental costs will be included in the final pipeline tolls, subject to certain conditions.

•NGTL System: In the nine months ended September 30, 2021, the NGTL System placed approximately $0.5 billion of capacity projects in service.

Construction activities began in September 2021 for the 2022 NGTL System Expansion Program which received federal approval in second quarter 2021. With an estimated capital cost of $1.1 billion, the program will provide incremental capacity to meet firm-receipt and intra-basin delivery requirements and consist of approximately 166 km (103 miles) of new pipeline, one new compressor unit and associated facilities. Anticipated in-service dates commence in fourth quarter 2022.

U.S. Natural Gas Pipelines

•Delivery Market Projects: We are actively developing projects that will replace and upgrade certain facilities while reducing emissions along portions of our pipeline systems in principal delivery markets. The enhanced facilities will improve reliability of the systems and allow for additional transportation services to address growing demand under long-term contracts while reducing direct carbon dioxide equivalent (CO2e) emissions. Consistent with this initiative, the VR project on Columbia Gas has been sanctioned, subject to customary conditions precedent and normal-course regulatory approvals. This project represents an approximate US$0.7 billion capital investment and is targeted to be placed in service during the second half of 2025. In addition, the WR project on ANR has also been sanctioned and will serve markets in the midwestern U.S. This project has an estimated capital cost of approximately US$0.8 billion and is expected to be placed in service in fourth quarter 2025.

•GTN Rate Case Settlement: On September 29, 2021, GTN filed an uncontested rate settlement which would set new recourse rates for GTN effective January 1, 2022 and institute a rate moratorium through December 31, 2023. The revised rates are not expected to have a significant impact on our U.S. Natural Gas Pipelines segment comparable earnings. In addition, GTN must file for new rates no later than April 1, 2024.

•Columbia Gas Section 4 Rate Case: Columbia Gas filed a Section 4 Rate Case with FERC in July 2020 requesting an increase to its maximum transportation rates effective February 1, 2021, subject to refund upon completion of the rate proceeding. On July 28, 2021, Columbia Gas notified FERC that it reached a settlement-in-principle with its customers addressing all remaining issues in the case, including but not limited to the resolution of rates and continuation of Columbia Gas's modernization program. On October 29, 2021, Columbia Gas filed its settlement with FERC, and is now awaiting Commission approval, with 2021 revenues expected to be generally consistent with estimates recorded to date. We expect FERC approval of the settlement in early 2022.

Mexico Natural Gas Pipelines

•Tula and Villa de Reyes: The CFE initiated arbitration in June 2019 for the Tula and Villa de Reyes projects, disputing fixed capacity payments due to force majeure events. Arbitration proceedings are currently suspended through December 31, 2021 while management advances settlement discussions with the CFE.

Liquids Pipelines

•Northern Courier: On September 16, 2021, we announced the sale of our remaining 15 per cent equity interest in Northern Courier Pipeline to Astisiy Limited Partnership, comprised of Suncor and eight Indigenous communities in the Regional Municipality of Wood Buffalo, for gross proceeds of approximately $30 million before post-closing adjustments. The transaction is anticipated to close in fourth quarter 2021, subject to customary closing conditions and the receipt of the required regulatory approvals.

Power and Storage

•Bruce Power Life Extension: The Unit 6 MCR program continues on budget and on schedule. The program is nearing the end of the Inspection Phase and is about to enter the Installation Phase. Preparation of the Unit 3 MCR program, which is the next scheduled MCR outage, continues and Bruce Power expects to submit its final cost and schedule duration estimate to the IESO in fourth quarter 2021.

•Bruce Power Uprate Initiative: Bruce Power recently launched Project 2030 with the goal of achieving a site peak output of 7,000 MW by 2030 in support of climate change targets and future clean energy needs. Project 2030 will focus on continued asset optimization, innovation and leveraging new technology, which could include integration with storage and other forms of energy, to increase the site peak output at Bruce Power.

•Bruce Power Outage: As part of the planned inspections, testing, analysis and maintenance activities at Bruce Power during the current Unit 6 MCR outage and the recently completed Unit 3 planned outage, higher than anticipated readings of hydrogen concentration in pressure tubes were detected. These readings were limited to a very small area of the respective pressure tubes and did not impact safety nor pressure tube integrity as concluded following an assessment of all of the Bruce Power units. On October 9, 2021, Unit 3 returned to service after the Canadian Nuclear Safety Commission approved Bruce Power's restart request following extensive inspections which demonstrated that safety and pressure tube integrity continued to meet regulatory requirements. Bruce Power will be incorporating additional inspections as part of their normal surveillance programs to address the new findings while progressing further programs that demonstrate fitness for service at elevated hydrogen concentration levels.

•Sharp Hills Wind Power PPA: On September 20, 2021, we executed a 15-year PPA for 100 per cent of the power produced and the rights to all environmental attributes from the 297 MW Sharp Hills Wind Farm located in eastern Alberta. The Sharp Hills Wind Farm is anticipated to be operational in 2023, subject to customary regulatory approvals and conditions.

•Ontario Pumped Storage Project: As part of our strategy to capture opportunities that capitalize on the transition to a less carbon-intensive energy mix, we are developing a 1,000 MW pumped hydro storage project in Meaford, Ontario near Bruce Power. Once complete, this facility is designed to provide emission-free electricity to the province while reducing greenhouse gas emissions by an expected 490,000 tonnes and delivering more than $250 million in annual electricity savings to Ontario ratepayers. On July 28, 2021, we reached an agreement with the Department of National Defence that, subject to conditions and regulatory approval, allows for the development of this project on the Meaford base. We will continue to consult with the Saugeen Ojibway Nation, other Indigenous Rightsholders and communities along with other local stakeholders as we continue to advance this project, which remains subject to a number of conditions and approvals, including approval of our Board of Directors.

•Renewable Energy Requests For Information (RFI): Through an RFI process in second quarter 2021, we announced that we were seeking to identify potential contracts and/or investment opportunities in up to 620 MW of wind energy projects, 300 MW of solar projects and 100 MW of energy storage projects to meet the electricity needs of a portion of our U.S. pipeline assets. The project team is currently evaluating proposals, has commenced negotiations and expects to finalize contracts by the end of the year.

Other Energy Transition Developments

•Irving Oil Decarbonization: On August 12, 2021, we signed a memorandum of understanding to explore the joint development of a series of proposed energy projects focused on reducing greenhouse gas emissions and creating new economic opportunities in New Brunswick and Atlantic Canada. Together with Irving Oil, we have identified a series of potential projects for exploration focused on decarbonizing current assets and deploying emerging technologies to reduce overall emissions. The partnership’s initial focus will consider a suite of upgrade projects at Irving Oil’s refinery in Saint John, New Brunswick, with the goal of significantly reducing emissions through the production and use of low-carbon power generation.

•Hydrogen Hubs: On October 7, 2021, we announced a partnership with Nikola Corporation to collaborate on developing, constructing, operating and owning large-scale hydrogen production facilities (hubs) in the United States and Canada. We are actively collaborating to identify and develop projects to establish the infrastructure required to deliver low-cost and low-carbon hydrogen at scale in line with each company’s core objectives.

A key objective of the collaboration is to establish hubs producing 150 tonnes or more of hydrogen per day near highly traveled truck corridors to serve Nikola’s planned need for hydrogen to fuel its Class 8 fuel cell electric vehicles (FCEVs) within the next five years. Our significant pipeline, storage and power assets can potentially be leveraged to lower the cost and increase the speed of delivery of these hubs. This may include exploring the integration of midstream assets to enable hydrogen distribution and storage via pipeline and/or to deliver carbon dioxide to permanent sequestration sites to decarbonize the hydrogen production process.

Corporate

•Common share dividend: Our Board of Directors declared a quarterly dividend of $0.87 per common share for the quarter ending December 31, 2021. The quarterly amount is equivalent to $3.48 per common share on an annualized basis.

•Voluntary Retirement Program (VRP): In mid-2021, we offered a one-time VRP to eligible employees. Participants in the program will retire by December 31, 2021 and receive a transition payment in addition to existing retirement benefits. For the three and nine months ended September 30, 2021, we have expensed a total of $89 million before tax, mainly related to the VRP transition payments, which was included in Plant operating costs and other. Of the total program costs, $71 million was excluded from comparable earnings and $18 million was recorded in Revenues related to costs that are recoverable through regulatory and tolling structures on a flow-through basis.

•Issuance of long-term debt: On October 12, 2021, TCPL issued US$1.25 billion of Senior Unsecured Notes due in October 2024 bearing interest at a fixed rate of 1.00 per cent and US$1.0 billion of Senior Unsecured Notes due in October 2031 bearing interest at a fixed rate of 2.50 per cent.

Teleconference and Webcast

We will hold a teleconference and webcast on Friday, November 5, 2021 to discuss our third quarter 2021 financial results. François Poirier, President and Chief Executive Officer; Joel Hunter, Executive Vice-President and Chief Financial Officer; and other members of the executive leadership team will discuss TC Energy's financial results and company developments at 9 a.m. (MDT) / 11 a.m. (EDT).

Members of the investment community and other interested parties are invited to participate by calling 1.800.319.4610. No pass code is required. Please dial in 15 minutes prior to the start of the call. A live webcast of the teleconference will be available on TC Energy's website at www.TCEnergy.com/events or via the following URL: http://www.gowebcasting.com/11358.

A replay of the teleconference will be available two hours after the conclusion of the call until midnight (EST) on November 12, 2021. Please call 1.855.669.9658 and enter pass code 7145.

The unaudited interim condensed consolidated financial statements and Management’s Discussion and Analysis (MD&A) are available on our website at www.TCEnergy.com and will be filed today under TC Energy's profile on SEDAR at www.sedar.com and with the U.S. Securities and Exchange Commission on EDGAR at www.sec.gov.

About TC Energy

We are a vital part of everyday life – delivering the energy millions of people rely on to power their lives in a sustainable way. Thanks to a safe, reliable network of natural gas and crude oil pipelines, along with power generation and storage facilities, wherever life happens – we’re there. Guided by our core values of safety, innovation, responsibility, collaboration and integrity, our 7,500 people make a positive difference in the communities where we operate across Canada, the U.S. and Mexico.

TC Energy's common shares trade on the Toronto (TSX) and New York (NYSE) stock exchanges under the symbol TRP. To learn more, visit us at www.TCEnergy.com.

Forward-Looking Information

This release contains certain information that is forward-looking, including the sustainability commitments and targets contained in our 2021 Report on Sustainability and our GHG Emissions Reduction Plan, and is subject to important risks and uncertainties (such statements are usually accompanied by words such as "anticipate", "expect", "believe", "may", "will", "should", "estimate", "intend" or other similar words). Forward-looking statements in this document are intended to provide TC Energy security holders and potential investors with information regarding TC Energy and its subsidiaries, including management's assessment of TC Energy's and its subsidiaries' future plans and financial outlook. All forward-looking statements reflect TC Energy's beliefs and assumptions based on information available at the time the statements were made and as such are not guarantees of future performance. As actual results could vary significantly from the forward-looking information, you should not put undue reliance on forward-looking information and should not use future-oriented information or financial outlooks for anything other than their intended purpose. We do not update our forward-looking information due to new information or future events, unless we are required to by law. For additional information on the assumptions made, and the risks and uncertainties which could cause actual results to differ from the anticipated results, refer to the most recent Quarterly Report to Shareholders and Annual Report filed under TC Energy's profile on SEDAR at www.sedar.com and with the U.S. Securities and Exchange Commission at www.sec.gov and the "Forward-looking information" section of our 2021 Report on Sustainability and our GHG Emissions Reduction Plan which are available on our website at www.TCEnergy.com.

Non-GAAP Measures

This release contains references to non-GAAP measures, including comparable earnings, comparable earnings per common share, comparable EBITDA and comparable funds generated from operations, that do not have any standardized meaning as prescribed by U.S. GAAP and therefore are unlikely to be comparable to similar measures presented by other companies. These non-GAAP measures are calculated on a consistent basis from period to period and are adjusted for specific items in each period, as applicable except as otherwise described in the Condensed consolidated financial statements and MD&A. For more information on non-GAAP measures, refer to TC Energy's most recent Quarterly Report to Shareholders.

Media Inquiries:

Jaimie Harding / Hejdi Carlsen

media@tcenergy.com

403.920.7859 or 800.608.7859

Investor & Analyst Inquiries:

David Moneta / Hunter Mau

investor_relations@tcenergy.com

403.920.7911 or 800.361.6522

Tc Energy Corp 6-K, filed Nov 5, 2021

About this 6-K