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1	Comparable EBITDA, comparable earnings, comparable earnings per common share, comparable funds generated from operations, comparable distributable cash flow and comparable distributable cash flow per common share are all non-GAAP measures. Refer to the Non-GAAP measures section for more information.

2	Includes capital expenditures, capital projects in development and contributions to equity investments.

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•	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 and contractual obligations

•	expected regulatory processes and outcomes

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

•	expected impact of future tax and accounting changes, commitments and contingent liabilities

•	expected industry, market and economic conditions.

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•	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.

•	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

•	costs for 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

•	changes in environmental and other laws and regulations

•	our ability to effectively anticipate and assess changes to government policies and regulations

•	competition in the pipeline, power and storage sectors

•	unexpected or unusual weather

•	acts of civil disobedience

•	cyber security and technological developments

•	economic conditions in North America as well as globally.

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•	comparable EBITDA

•	comparable EBIT

•	comparable earnings

•	comparable earnings per common share

•	funds generated from operations

•	comparable funds generated from operations

•	comparable distributable cash flow

•	comparable distributable cash flow per common share.

•	certain fair value adjustments relating to risk management activities

•	income tax refunds and adjustments to enacted tax rates

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

•	legal, contractual and bankruptcy settlements

•	impact of regulatory or arbitration decisions relating to prior year earnings

•	restructuring costs

•	impairment of goodwill, investments and other assets

•	acquisition and integration costs.

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•	an after-tax gain of $54 million related to the sale of our Coolidge generating station in May 2019

•	a deferred tax benefit of $32 million related to the impact of an Alberta corporate income tax rate reduction on our Canadian businesses not subject to rate-regulated accounting

•	an after-tax gain of $6 million and an after-tax loss of $6 million for the three and six months ended June 30, 2019 related to our U.S. Northeast power marketing contracts.

•	after-tax losses of $11 million and $5 million for the three and six months ended June 30, 2018 related to our U.S. Northeast power marketing contracts.

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•	higher contribution from Liquids Pipelines primarily due to higher volumes on the Keystone Pipeline System and increased earnings from liquids marketing activities

•	higher contribution from U.S. Natural Gas Pipelines mainly due to increased earnings from Columbia Gas and Columbia Gulf growth projects placed in service

•	higher contribution from Power and Storage primarily due to increased Bruce Power results from a higher realized power price, partially offset by the sale of our interests in the Cartier Wind power facilities in 2018

•	lower flow-through income taxes on the NGTL System and the Canadian Mainline as a result of accelerated tax depreciation enacted in June 2019, partially offset by increased depreciation and higher incentive earnings for the Canadian Mainline in 2019

•	foreign exchange impact of a stronger U.S. dollar on the Canadian dollar equivalent earnings from our U.S. and Mexico operations.

•	higher contribution from U.S. Natural Gas Pipelines mainly due to increased earnings from Columbia Gas and Columbia Gulf growth projects placed in service

•	higher contribution from Liquids Pipelines primarily due to higher volumes on the Keystone Pipeline System and increased earnings from liquids marketing activities

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•	higher contribution from Canadian Natural Gas Pipelines mainly due to the Canadian Mainline recovery of increased depreciation and higher incentive earnings in 2019, partially offset by lower flow-through income taxes on the NGTL System and the Canadian Mainline as a result of accelerated tax depreciation

•	lower contribution from Power and Storage primarily due to the sale of our interests in the Cartier Wind power facilities in 2018, partially offset by increased Bruce Power results from a higher realized power price and higher income on funds invested for future retirement benefits

•	foreign exchange impact of a stronger U.S. dollar on the Canadian dollar equivalent earnings from our U.S. and Mexico operations.

•	changes in comparable EBITDA described above

•	higher depreciation largely in Canadian Natural Gas Pipelines, which is fully recovered in tolls as reflected in the comparable EBITDA discussion above, therefore having no impact on comparable earnings. In addition, higher consolidated depreciation reflects new projects placed in service

•	lower interest income and other due to realized losses in 2019 on derivatives used to manage exposure to foreign exchange rate fluctuations on U.S. dollar-denominated income

•	higher income tax expense due to higher comparable earnings before income taxes and lower foreign tax rate differentials, partially offset by lower flow-through income taxes in our Canadian rate-regulated pipelines

•	higher interest expense primarily as a result of higher levels of short-term borrowings, long-term debt issuances, net of maturities, and the foreign exchange impact on translation of U.S. dollar-denominated interest.

•	changes in comparable EBITDA described above

•	higher depreciation largely in Canadian Natural Gas Pipelines, which is fully recovered in tolls as reflected in the increase in comparable EBITDA described above, therefore having no impact on comparable earnings. In addition, higher consolidated depreciation reflects new projects placed in service

•	higher income tax expense due to higher comparable earnings before income taxes and lower foreign tax rate differentials, partially offset by lower flow-through income taxes in our Canadian rate-regulated pipelines

•	higher interest expense primarily as a result of long-term debt issuances, net of maturities, higher levels of short-term borrowings, and the foreign exchange impact on translation of U.S. dollar-denominated interest

•	lower interest income and other due to realized losses in 2019 compared to realized gains in 2018 on derivatives used to manage exposure to foreign exchange rate fluctuations on U.S. dollar-denominated income.

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1	Amounts reflect our proportionate share of joint venture costs where applicable and 100 per cent of costs related to wholly-owned assets and assets held through TC PipeLines, LP.

2	Represents 100 per cent of required capital prior to potential joint venture partners or project financing.

3	Carrying value is net of the fourth quarter 2018 receipts from the LNG Canada participants for the reimbursement of approximately $0.5 billion of pre-FID costs pursuant to project agreements.

4	Reflects our proportionate share of the Unit 6 Major Component Replacement program costs, expected to be in service in 2023, and amounts to be invested under the Asset Management program through 2023.

5	Includes 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.

6	Reflects U.S./Canada foreign exchange rate of 1.31 at June 30, 2019.

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1	Amounts reflect our proportionate share of joint venture costs where applicable and 100 per cent of costs related to wholly-owned assets and assets held through TC PipeLines, LP.

2	Includes projects subject to a positive customer FID.

3	Carrying value reflects amount remaining after impairment charge recorded in 2015 along with additional amounts capitalized from January 1, 2018. A portion of these costs are recoverable from shippers under certain conditions.

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

5	Reflects our proportionate share of Major Component Replacement program costs for Units 3, 4, 5, 7 and 8, and the remaining Asset Management program costs beyond 2023.

6	Reflects U.S./Canada foreign exchange rate of 1.31 at June 30, 2019.

•	higher expected volumes on the Keystone Pipeline System as well as higher contribution from liquids marketing activities

•	delays in the commencement of operations on the Napanee power plant and Sur de Texas pipeline

•	uncertainty regarding the impact of final U.S. Tax Reform regulations, expected in late 2019, on the cost of financing certain of our U.S. operations

•	asset sales and use of proceeds.

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1	Includes results from Foothills, Ventures LP, Great Lakes Canada and our share of equity income from our investment in TQM as well as general and administrative and business development costs related to our Canadian Natural Gas Pipelines.

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lower flow-through income taxes on the NGTL System and the Canadian Mainline as a result of the Canadian federal government’s accelerated tax depreciation, enacted in June 2019, to allow businesses in Canada to deduct the cost of their investments more quickly. Due to the flow-through treatment of income taxes on our Canadian rate-regulated pipelines, this beneficial income tax change reduces our comparable EBITDA despite having no impact on net income

•	increased depreciation on the Canadian Mainline due to higher rates approved in the NEB 2018 Decision

•	increased incentive earnings on the Canadian Mainline

•	increased rate base earnings on the NGTL System.

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1	Reflects our earnings from TC PipeLines, LP’s ownership interests in eight natural gas pipelines as well as general and administrative costs related to TC PipeLines, LP.

2	For the three and six months ended June 30, 2019, our ownership interest in TC PipeLines, LP was 25.5 per cent which is unchanged from the same periods in 2018.

3	Reflects our 53.55 per cent direct interest in Great Lakes. The remaining 46.45 per cent is held by TC PipeLines, LP.

4	Reflects earnings from our effective ownership in Millennium and Hardy Storage as well as general and administrative and business development costs related to our U.S. natural gas pipelines.

5	Reflects earnings attributable to portions of TC PipeLines, LP that we do not own.

•	increased earnings from Columbia Gas and Columbia Gulf growth projects placed in service

•	decreased earnings from Bison (wholly-owned by TC PipeLines, LP) due to 2018 customer agreements to pay out their future contracted revenues and terminate their contracts.

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1	Represents equity income from our 60 per cent interest. Sur de Texas results include AFUDC during construction, net of interest expense on an inter-affiliate loan from TC Energy. This interest expense is fully offset in Interest income and other in the Corporate segment.

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•	higher volumes on the Keystone Pipeline System

•	higher contribution from liquids marketing activities due to improved margins and volumes

•	contribution from the White Spruce pipeline, which went into service in May 2019

•	positive foreign exchange impact on the Canadian dollar equivalent earnings from our U.S. operations.

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1	Includes our share of equity income from our investments in Portlands Energy and Bruce Power.

•	a pre-tax gain of $68 million related to the sale of our Coolidge generating station in May 2019. Refer to the Recent developments section for more information

•	a pre-tax gain of $8 million and pre-tax loss of $8 million for the three and six months ended June 30, 2019, (2018 – pre-tax losses of $15 million and $7 million, respectively) related to our U.S. Northeast power marketing contracts, the remainder of which were sold in May 2019

•	unrealized gains and losses from changes in the fair value of derivatives used to reduce our exposure to certain commodity price risks, largely related to the remaining U.S. Northeast power marketing contracts.

•	increased Bruce Power results primarily due to a higher realized power price and higher income on funds invested for future retirement benefits, partially offset by lower volumes resulting from higher outage days. Additional financial and operating information on Bruce Power is provided below

•	decreased Western and Eastern Power results largely due to the sale of our interests in the Cartier Wind power facilities in October 2018 and the sale of our Coolidge generating facility in May 2019

•	decreased Natural Gas Storage results for the three months ended June 30, 2019, mainly due to pipeline constraints in the Alberta natural gas market which limited our ability to access our storage facilities, versus increased results for the six months ended June 30, 2019 on account of higher realized natural gas storage price spreads, primarily in first quarter 2019.

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

2	Represents our 48.4 per cent (2018 – 48.3 per cent) ownership interest in Bruce Power. Sales volumes include deemed generation.

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

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

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

•	long-term debt issuances, net of maturities

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

•	higher levels of short-term borrowings

•	higher capitalized interest primarily related to Napanee and Keystone XL.

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•	unrealized gains in 2019 compared to unrealized losses in 2018 from foreign exchange risk management activities. These amounts have been excluded from comparable earnings

•

foreign exchange gains in 2019 compared to foreign exchange losses in 2018 related to a peso-denominated inter-affiliate loan receivable from the Sur de Texas joint venture. The corresponding foreign exchange losses and gains in Sur de Texas are reflected in Income from equity investments, resulting in no net impact on net income. The offsetting currency-related gain and loss amounts are excluded from comparable earnings

•	realized losses in 2019 compared to realized gains in 2018 on derivatives used to manage our net exposure to foreign exchange rate fluctuations on U.S. dollar-denominated income.

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

•	approximately $11.5 billion of unutilized, unsecured credit facilities

•	our access to capital markets.

1	Includes non-recoverable maintenance capital expenditures from all segments including cash contributions to fund our proportionate share of maintenance capital expenditures for our equity investments which are primarily related to contributions to Bruce Power.

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1	Includes draws and repayments on an unsecured loan facility by TC PipeLines, LP.

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

•	cash and cash equivalents

•	accounts receivable

•	available-for-sale assets

•	the fair value of derivative assets

•	a loan receivable.

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

2	In the three and six months ended June 30, 2019 and 2018, 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.

1	Refer to our Condensed consolidated financial statements for the components of OCI related to derivatives in cash flow hedging relationships including the portion attributable to non-controlling interests.

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

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1	Refer to our Condensed consolidated financial statements for the components of OCI related to derivatives in cash flow hedging relationships including the portion attributable to non-controlling interests.

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

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•	to not reassess prior conclusions on existing leases regarding lease identification, lease classification and initial direct costs under the new standard

•	to carry forward the historical lease classification and our accounting treatment for land easements on existing agreements

•	to not recognize ROU assets or lease liabilities for leases that qualify for the short-term lease recognition exemption

•	to not separate lease and non-lease components for all leases for which we are the lessee and for facility and liquids tank terminals for which we are the lessor

•	to use hindsight in determining the lease term and assessing ROU assets for impairment.

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•	whether a contract contains a lease

•	the duration of the lease term including exercising lease renewal options. The lease term for all of our leases includes the noncancellable period of the lease plus any additional periods covered by either our option to extend (or not to terminate) the lease that we are reasonably certain to exercise, or an option to extend (or not to terminate) the lease controlled by the lessor

•	the discount rate for the lease.

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•	regulators' decisions

•	negotiated settlements with shippers

•	newly constructed assets being placed in service

•	acquisitions and divestitures

•	developments outside of the normal course of operations.

•	regulatory decisions

•	newly constructed assets being placed in service

•	acquisitions and divestitures

•	demand for uncontracted transportation services

•	liquids marketing activities

•	developments outside of the normal course of operations

•	certain fair value adjustments.

•	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.

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•	an after-tax gain of $54 million related to the sale of our Coolidge generating station

•	a deferred tax benefit of $32 million related to the impact of an Alberta corporate income tax rate reduction on our Canadian businesses not subject to rate-regulated accounting

•	an after-tax gain of $6 million related to our U.S. Northeast power marketing contracts.

•	an after-tax loss of $12 million related to our U.S. Northeast power marketing contracts.

•	a $143 million after-tax gain related to the sale of our interests in the Cartier Wind power facilities

•	a $115 million deferred income tax recovery from an MLP regulatory liability write-off resulting from the 2018 FERC Actions

•	a $52 million recovery of deferred income taxes as a result of finalizing the impact of U.S. Tax Reform

•	a $27 million income tax recovery related to the sale of our U.S. Northeast power generation assets

•	$25 million of after-tax income recognized on the Bison contract terminations

•	a $140 million after-tax impairment charge on Bison

•	a $15 million after-tax goodwill impairment charge on Tuscarora

•	an after-tax net loss of $7 million related to our U.S. Northeast power marketing contracts.

•	after-tax gain of $8 million related to our U.S. Northeast power marketing contracts.

•	an after-tax loss of $11 million related to our U.S. Northeast power marketing contracts.

•	after-tax gain of $6 million related to our U.S. Northeast power marketing contracts, primarily due to income recognized on the sale of our retail contracts.

•	an $804 million recovery of deferred income taxes as a result of U.S. Tax Reform

•	a $136 million after-tax gain related to the sale of our Ontario solar assets

•	a $64 million net after-tax gain related to the monetization of our U.S. Northeast power generation assets

•	a $954 million after-tax impairment charge for the Energy East pipeline and related projects as a result of our decision not to proceed with the project applications

•	a $9 million after-tax charge related to the maintenance and liquidation of Keystone XL assets.

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•	an incremental net loss of $12 million related to the monetization of our U.S. Northeast power generation assets

•	an after-tax charge of $30 million for integration-related costs associated with the acquisition of Columbia

•	an after-tax charge of $8 million related to the maintenance of Keystone XL assets.

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•	to not reassess prior conclusions on existing leases regarding lease identification, lease classification and initial direct costs under the new standard

•	to carry forward the historical lease classification and its accounting treatment for land easements on existing agreements

•	to not recognize ROU assets or lease liabilities for leases that qualify for the short-term lease recognition exemption

•	to not separate lease and non-lease components for all leases for which the Company is the lessee and for facility and liquids tank terminals for which the Company is the lessor

•	to use hindsight in determining the lease term and assessing ROU assets for impairment.

•	whether a contract contains a lease

•

the duration of the lease term including exercising lease renewal options. The lease term for all of the Company’s leases includes the noncancellable period of the lease plus any additional periods covered by either a Company option to extend (or not to terminate) the lease that the Company is reasonably certain to exercise, or an option to extend (or not to terminate) the lease controlled by the lessor

•	the discount rate for the lease.

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1	Previously referred to as Energy.

2	Includes intersegment eliminations.

3

The Company records intersegment sales at contracted rates. For segmented reporting, these transactions are included as intersegment revenues in the segment providing the service and 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.

4	Income/(loss) from equity investments includes foreign exchange losses on the Company's inter-affiliate loan with Sur de Texas. The offsetting foreign exchange gains on the inter-affiliate loan are included in Interest income and other. The peso-denominated loan to the Sur de Texas joint venture represents the Company's proportionate share of long-term debt financing for this joint venture.

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1	Previously referred to as Energy.

2	Includes intersegment eliminations.

3

The Company records intersegment sales at contracted rates. For segmented reporting, these transactions are included as intersegment revenues in the segment providing the service and 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.

4	Income from equity investments includes foreign exchange gains on the Company's inter-affiliate loan with Sur de Texas. The offsetting foreign exchange losses on the inter-affiliate loan are included in Interest income and other. The peso-denominated loan to the Sur de Texas joint venture represents the Company's proportionate share of long-term debt financing for this joint venture.

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1	Previously referred to as Energy.

2	Includes intersegment eliminations.

3

The Company records intersegment sales at contracted rates. For segmented reporting, these transactions are included as intersegment revenues in the segment providing the service and 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.

4	Income/(loss) from equity investments includes foreign exchange losses on the Company's inter-affiliate loan with Sur de Texas. The offsetting foreign exchange gains on the inter-affiliate loan are included in Interest income and other. The peso-denominated loan to the Sur de Texas joint venture represents the Company's proportionate share of long-term debt financing for this joint venture.

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1	Previously referred to as Energy.

2	Includes intersegment eliminations.

3

The Company records intersegment sales at contracted rates. For segmented reporting, these transactions are included as intersegment revenues in the segment providing the service and 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.

4	Income from equity investments includes foreign exchange gains on the Company's inter-affiliate loan with Sur de Texas. The offsetting foreign exchange losses on the inter-affiliate loan are included in Interest income and other. The peso-denominated loan to the Sur de Texas joint venture represents the Company's proportionate share of long-term debt financing for this joint venture.

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1	Other revenues include income from the Company's marketing activities, financial instruments and lease arrangements. These arrangements are not in the scope of the revenue guidance. Refer to Note 7, Leases, and Note 12, Risk management and financial instruments, for further information on income from lease arrangements and financial instruments, respectively.

1	Other revenues include income from the Company's marketing activities, financial instruments and lease arrangements. These arrangements are not in the scope of the revenue guidance. Refer to Note 12, Risk management and financial instruments, for further information on income from financial instruments.

1	Other revenues include income from the Company's marketing activities, financial instruments and lease arrangements. These arrangements are not in the scope of the revenue guidance. Refer to Note 7, Leases, and Note 12, Risk management and financial instruments, for further information on income from lease arrangements and financial instruments, respectively.

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1	Other revenues include income from the Company's marketing activities, financial instruments and lease arrangements. These arrangements are not in the scope of the revenue guidance. Refer to Note 12, Risk management and financial instruments, for further information on income from financial instruments.

1	Recorded as part of Other current assets on the Condensed consolidated balance sheet.

2	Recorded as part of Intangibles and other assets on the Condensed consolidated balance sheet.

3	Comprised of deferred revenue recorded in Accounts payable and other on the Condensed consolidated balance sheet. During the six months ended June 30, 2019, $6 million of revenue was recognized that was included in contract liabilities at the beginning of the period.

4	Comprised of deferred revenue recorded in Other long-term liabilities on the Condensed consolidated balance sheet.

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1	Included in Accounts payable and other on the Condensed consolidated balance sheet.

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1	Includes short-term leases and variable lease costs.

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

2	Other comprehensive loss before reclassifications on currency translation adjustments and cash flow hedges are net of non-controlling interests losses of $32 million and $9 million, respectively.

3	Amount reclassified from AOCI on cash flow hedges is net of non-controlling interests gains of less than $1 million.

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

2	Other comprehensive loss before reclassifications on currency translation adjustments, cash flow hedges and equity investments are net of non-controlling interests losses of $67 million, $14 million and $1 million, respectively.

3

Losses 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 $21 million ($16 million, net of tax) at June 30, 2019. 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.

4	Amount reclassified from AOCI on cash flow hedges is net of non-controlling interests gains of $1 million.

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

2	These AOCI components are included in the computation of net benefit cost. Refer to Note 11, Employee post-retirement benefits, for further information.

3	Amounts reclassified from AOCI on cash flow hedges and equity investments are net of non-controlling interests gains of less than $1 million and nil, respectively, for the three months ended June 30, 2019 (2018 – $2 million and nil, respectively) and $1 million and nil, respectively, for the six months ended June 30, 2019 (2018 – $3 million and $1 million, respectively).

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

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1	Fair value equals carrying value.

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

3	In the three and six months ended June 30, 2019, Net income includes net realized gains of nil (2018 – nil and $1 million, respectively) related to the interest component of cross-currency swap settlements which are reported within Interest expense on the Company's Condensed consolidated statement of income.

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1	Long-term debt is recorded at amortized cost except for US$450 million (December 31, 2018 – US$750 million) that is attributed to hedged risk and recorded at fair value.

2

Net income for the three and six months ended June 30, 2019 includes unrealized losses of $2 million and $5 million, respectively (2018 – unrealized losses of $1 million and unrealized gains of $4 million, respectively) for fair value adjustments attributable to the hedged interest rate risk associated with interest rate swap fair value hedging relationships on US$450 million of long-term debt at June 30, 2019 (December 31, 2018 – US$750 million). There were no other unrealized gains or losses from fair value adjustments to the non-derivative financial instruments.

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

2	Available-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.

1	Gains 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.

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

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1	Fair value equals carrying value.

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

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1	Fair value equals carrying value.

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

1	At June 30, 2019 and December 31, 2018, adjustments for discontinued hedging relationships included in these balances were nil.

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

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

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

2	In the three and six months ended June 30, 2019 and 2018, 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.

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

1	Refer to Note 10, Other comprehensive (loss)/income 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.

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

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1	Refer to Note 10, Other comprehensive (loss)/income 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.

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

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

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

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1	There were no transfers from Level II to Level III for the six months ended June 30, 2019.

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1	There were no transfers from Level II to Level III for the year ended December 31, 2018.

1	For the three and six months ended June 30, 2019, Revenues included unrealized losses of $3 million attributed to derivatives in the Level III category that were still held at June 30, 2019 (2018 – unrealized gains of $50 million and $44 million, respectively).

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

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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.

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

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.

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.

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

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.

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.

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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.

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.

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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.

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•	Second quarter 2019 financial results

◦	Comparable distributable cash flow of $1.5 billion or $1.64 per common share

•	Declared a quarterly dividend of $0.75 per common share for the quarter ending September 30, 2019

•	Continued construction activities on the Coastal GasLink pipeline project; on July 26, 2019 the National Energy Board (NEB) issued its decision affirming provincial jurisdiction for the project

•	Placed approximately $0.3 billion of NGTL System projects in service in the first half of 2019

•	Placed the White Spruce pipeline in northeast Alberta in service in May 2019

•	Achieved necessary milestones to move Louisiana XPress and Grand Chenier XPress into secured projects at a combined cost of approximately US$0.6 billion

•	Received NEB approval of the North Bay Junction Long Term Fixed Price (NBJ LTFP) service, as filed

•	Closed the sale of our Coolidge generating station in Arizona for US$448 million

•	Entered into an agreement to sell certain Columbia Midstream assets for approximately US$1.3 billion

•	Issued $1.0 billion of 30-year fixed-rate medium-term notes

•	Completed the partial monetization of the Northern Courier pipeline for aggregate gross proceeds of approximately $1.15 billion in July 2019

•	On July 30, 2019, announced an agreement to sell our interests in three Ontario natural gas-fired power plants for approximately $2.87 billion.

•	higher contribution from Liquids Pipelines primarily due to higher volumes on the Keystone Pipeline System and increased earnings from liquids marketing activities

•	higher contribution from U.S. Natural Gas Pipelines mainly due to increased earnings from Columbia Gas and Columbia Gulf growth projects placed in service

•	higher contribution from Power and Storage primarily due to increased Bruce Power results from a higher realized power price, partially offset by the sale of our interests in the Cartier Wind power facilities in 2018

•	lower flow-through income taxes on the NGTL System and the Canadian Mainline as a result of accelerated tax depreciation enacted in June 2019, partially offset by increased depreciation and higher incentive earnings for the Canadian Mainline in 2019

•	foreign exchange impact of a stronger U.S. dollar on the Canadian dollar equivalent earnings from our U.S. and Mexico operations.

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•	changes in comparable EBITDA described above

•	higher depreciation largely in Canadian Natural Gas Pipelines, which is fully recovered in tolls as reflected in the comparable EBITDA discussion above, therefore having no impact on comparable earnings. In addition, higher consolidated depreciation reflects new projects placed in service

•	lower interest income and other due to realized losses in 2019 on derivatives used to manage exposure to foreign exchange rate fluctuations on U.S. dollar-denominated income

•	higher income tax expense due to higher comparable earnings before income taxes and lower foreign tax rate differentials, partially offset by lower flow-through income taxes in our Canadian rate-regulated pipelines

•	higher interest expense primarily as a result of higher levels of short-term borrowings, long-term debt issuances, net of maturities, and the foreign exchange impact on translation of U.S. dollar-denominated interest.

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Coastal GasLink Pipeline Project: Following the October 2018 positive Final Investment Decision (FID) by LNG Canada, construction activities continue at many locations along the pipeline route including the area south of Houston, B.C. which required a B.C. Supreme Court injunction for access. We expect a further decision in third quarter 2019 from the B.C. Supreme Court to extend the injunction to project completion.

•	NGTL System: In the first half of 2019, the NGTL System placed approximately $0.3 billion of capacity projects in service.

•	Canadian Mainline: On May 9, 2019, we received NEB approval of the NBJ LTFP service, as filed.

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•

Sale of Columbia Midstream assets: On July 2, 2019, we entered into an agreement to sell certain Columbia Midstream assets to UGI Energy Services, LLC, a subsidiary of UGI Corporation, for proceeds of approximately US$1.3 billion. The transaction is expected to close in third quarter 2019 subject to post-closing adjustments and customary regulatory approvals. The sale is expected to result in a pre-tax gain of $20 million ($130 million after-tax loss), which includes the release of an estimated $589 million of Columbia's goodwill allocated to these assets that is not deductible for tax purposes. The gain and related tax impact will be recognized upon closing of the transaction. This sale does not include any interest in Columbia Energy Ventures Company, which is our minerals business in the Appalachian basin.

•	East Lateral XPress: In second quarter 2019, we approved the East Lateral XPress project, an expansion project on the Columbia Gulf system that will connect supply to Gulf Coast LNG export markets. Subject to a positive customer FID, the anticipated in-service is 2022 with estimated project costs of US$0.3 billion.

•

Louisiana XPress and Grand Chenier XPress: Combined, the Louisiana XPress and Grand Chenier XPress projects will connect nearly 2 Bcf/d of supply to Gulf Coast LNG export facilities. Both projects have now obtained necessary customer approvals or waivers of conditions allowing the projects to move to the execution phase. The anticipated in-service date of Louisiana XPress is in 2022 and estimated project costs are US$0.4 billion. The anticipated in-service dates for Grand Chenier are in 2021 and 2022 for Phase I and II, respectively, with total estimated project costs of US$0.2 billion.

•

Sur de Texas: In June 2019, we completed construction and commissioning activities for the 775 km (482 mile) Sur de Texas pipeline, which has the capacity to provide up to 2.6 Bcf/d of natural gas supply to Mexico directly from the United States. We communicated the pipeline’s readiness for operation to both the regulator, Comisión Reguladora de Energía (CRE), and our customer, Comisión Federal de Electricidad (CFE), as required under our service contract. We require CFE's acknowledgment of readiness prior to commencing transportation service to CFE. To date, CFE has not provided this acknowledgment and, as a result, we have not been able to commence transportation services under their contract.

•	Villa de Reyes: Construction of the Villa de Reyes project is ongoing, but the project has experienced force majeure events that have delayed the schedule. We anticipate a phased in-service sequence to commence late 2019.

•	Tula: Construction for the central segment of the Tula project has been delayed due to a lack of progress by the Secretary of Energy, the governmental department responsible for Indigenous consultations. Project completion has been revised to the end of 2021.

•

CFE Arbitration: In June 2019, CFE filed requests for arbitration under the Sur de Texas, Villa de Reyes and Tula contracts, seeking nullification of clauses that govern the parties’ responsibilities in instances of force majeure and require reimbursement of fixed capacity payments. We are analyzing the content of the arbitration requests and preparing our response. In our view, the contracts were properly established in accordance with all original bid and regulatory requirements and remain valid and enforceable. We will defend them as necessary through the arbitration proceedings.

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•	White Spruce: The White Spruce pipeline, which transports crude oil from Canadian Natural Resources Limited's Horizon facility in northeast Alberta to the Grand Rapids pipeline, was placed in service in May 2019.

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Northern Courier: On July 17, 2019, we completed the sale of an 85 per cent equity interest in the Northern Courier pipeline to Alberta Investment Management Corporation for gross proceeds of $144 million before post-closing adjustments, resulting in an expected pre-tax gain of $70 million after recording our remaining 15 per cent interest at fair value. On an after-tax basis, the gain of approximately $115 million reflects the utilization of previously unrecognized tax loss benefits. Preceding the equity sale, Northern Courier pipeline issued $1.0 billion of long-term, non-recourse debt, the proceeds from which were paid to TC Energy, resulting in aggregate gross proceeds to TC Energy of approximately $1.15 billion from this asset monetization.

•	Keystone XL: A decision from the Nebraska Supreme Court on the appeal of the Nebraska Public Service Commission route approval remains pending. We expect the decision to be issued in third quarter 2019.

•

Ontario Natural Gas-Fired Power Plants: On July 30, 2019, we entered into an agreement to sell our Halton Hills and Napanee power plants as well as our 50 per cent interest in Portlands Energy Centre to a subsidiary of Ontario Power Generation Inc. for proceeds of approximately $2.87 billion, subject to timing of the close and related adjustments. The sale is expected to close in late 2019 subject to conditions which include regulatory approvals and Napanee reaching commercial operations as outlined in the agreement. We expect this sale to result in a total pre-tax loss of approximately $230 million ($150 million after tax), with $125 million of the pre-tax loss recorded at July 30, 2019 upon classifying the net assets as held for sale. The remaining loss will be recorded on or before closing of the transaction.

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•

Coolidge Generating Station: In December 2018, we entered into an agreement to sell our Coolidge generating station in Arizona to SWG Coolidge Holdings, LLC (SWG). Salt River Project Agriculture Improvement and Power District (SRP), the PPA counterparty, subsequently exercised its contractual right of first refusal (ROFR) on a sale to a third party and we terminated the agreement with SWG. On May 21, 2019, we completed the sale to SRP for proceeds of US$448 million before post-closing adjustments, as per the terms of their ROFR, resulting in a pre-tax gain of $68 million ($54 million after tax).

•	Monetization of U.S. Northeast power business: In May 2019, we sold our remaining U.S. Northeast power marketing contracts. This transaction concludes the wind-down of our U.S. Northeast power marketing business.

•	Common Share Dividend: Our Board of Directors declared a quarterly dividend of $0.75 per common share for the quarter ending September 30, 2019 on TC Energy's outstanding common shares. The quarterly amount is equivalent to $3.00 per common share on an annualized basis.

•	Issuance of Long-term Debt: In April 2019, TCPL issued $1.0 billion of Medium Term Notes due in October 2049 bearing interest at a fixed rate of 4.34 per cent. The net proceeds of this debt issuance were used for general corporate purposes and to fund our capital program.

•	Dividend Reinvestment Plan: In second quarter 2019, the DRP participation rate amongst common shareholders was approximately 34 per cent resulting in $238 million reinvested in common equity under the program. Year-to-date in 2019, the participation rate amongst common shareholders has been approximately 33 per cent resulting in $464 million of dividends reinvested.

•	Corporate Name Change: On May 3, 2019, TransCanada Corporation changed its name to TC Energy Corporation following shareholder approval at our 2019 annual and special meeting.

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