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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.

•	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

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•	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

•	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

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

•	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.

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•	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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•	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

•	higher contribution from Canadian Natural Gas Pipelines mainly due to the recovery of increased depreciation in 2019 as a result of higher rates approved in both the Canadian Mainline NEB 2018 Decision and the NGTL 2018-2019 Settlement and higher incentive earnings for the Canadian Mainline

•	lower contribution from Power and Storage primarily due to the sale of our interests in the Cartier Wind power facilities in 2018 and costs related to Napanee's delayed in-service

•	foreign exchange impact of a stronger U.S. dollar on the Canadian dollar equivalent earnings from our U.S. 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 increase in comparable EBITDA described above, therefore having no impact on comparable earnings. In addition, higher depreciation reflects new projects placed in service

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

•	higher income tax expense due to higher comparable earnings before income taxes and lower foreign tax rate differentials

•	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

•	higher AFUDC due to increased capital expenditures for our NGTL System and Mexico projects.

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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	The CFE has recognized force majeure events for these pipelines and approved the payment of fixed capacity charges in accordance with their respective TSAs. Payments will be recognized as revenue over the contract service term commencing once the pipelines are placed in service.

5	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.

6	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.

7	Reflects U.S./Canada foreign exchange rate of 1.34 at March 31, 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 1.34 at March 31, 2019.

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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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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 months ended March 31, 2019, our ownership interest in TC PipeLines, LP was 25.5 per cent, which is unchanged from the same period 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 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.

•	lower revenues from operations as a result of changes in timing of revenue recognition in 2018

•	lower equity earnings from our investment in the Sur de Texas pipeline which records AFUDC during construction, net of interest expense on an inter-affiliate loan from TransCanada. The inter-affiliate loan amount is fully offset in Interest income and other in the Corporate segment

•	a TransGas distribution received and recorded as income in 2018, recorded in Other above.

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•	higher volumes on the Keystone Pipeline System

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

•	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 loss of $16 million for the three months ended March 31, 2019 (2018 – gain of $8 million) related to our U.S. Northeast power marketing contracts. These amounts have been excluded from Power and Storage's comparable earnings as we do not consider the wind-down and sales of the remaining contracts part of our underlying operations

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

•	decreased Western and Eastern Power results largely due to the sale of our interests in the Cartier Wind power facilities in October 2018 and costs related to Napanee's delayed in-service. Refer to the Recent developments section for more information

•	increased Natural Gas Storage results due to higher realized natural gas storage price spreads

•	increased Bruce Power results primarily due to 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.

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

2	Represents our 48.3 per cent (2018 – 48.4 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 sales prices 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 borrowing

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

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

•

higher interest income combined with a lower foreign exchange gain related to an inter-affiliate loan receivable from the Sur de Texas joint venture. The corresponding interest expense and foreign exchange loss in Sur de Texas are reflected in Income from equity investments in the Mexico Natural Gas Pipelines and Corporate segments, respectively, resulting in no 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 $11.7 billion of unutilized, unsecured credit facilities

•	our access to capital markets, including through our DRP and Corporate ATM programs, if deemed appropriate.

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	As the total number of Series 7 preferred shares tendered for conversion did not meet the threshold for conversion, no Series 7 preferred shares were converted into Series 8 preferred shares on April 30, 2019.

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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.

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•	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 months ended March 31, 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	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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•	not to 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 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.

•	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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•	a $265 million net after-tax gain related to the monetization of our U.S. Northeast power generation assets which included a $441 million after-tax gain on the sale of TC Hydro and a loss of $176 million after tax on the sale of the thermal and wind package

•	an after-tax charge of $15 million for integration-related costs associated with the acquisition of Columbia

•	an after-tax charge of $4 million related to the maintenance of Keystone XL assets.

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•	not to 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/(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	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 11, 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 11, 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 three months ended March 31, 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 $35 million and $5 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 $16 million ($12 million, net of tax) at March 31, 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	Amounts reclassified from AOCI on cash flow hedges and equity investments are net of non-controlling interests gains of $1 million and nil, respectively.

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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 10, 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 $1 million and nil, respectively, for the three months ended March 31, 2019 (2018 – nil and nil).

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 months ended March 31, 2019, Net income includes net realized gains of nil (2018 – $1 million) 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 months ended March 31, 2019 includes unrealized losses of $3 million (2018 – gains of $5 million) 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 March 31, 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.

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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 March 31, 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 months ended March 31, 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 9, 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	Amounts available for offset do not include cash collateral pledged or received.

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 three months ended March 31, 2019.

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

1	For the three months ended March 31, 2019, Revenues included unrealized gains of less than $1 million attributed to derivatives in the Level III category that were still held at March 31, 2019 (2018 – unrealized losses of $11 million).

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1	TransCanada’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 TransCanada 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 TransCanada 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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•	First quarter 2019 financial results

◦	Comparable distributable cash flow of $1.6 billion or $1.76 per common share

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

•	Placed approximately $5.3 billion of projects in service including Mountaineer XPress, Gulf XPress and certain NGTL System expansions

•	Continued pre-construction activities on Coastal GasLink pipeline project

•	Received new Presidential Permit for Keystone XL

•	Completed commissioning on White Spruce pipeline

•	Issued $1.0 billion of 30-year fixed-rate medium-term notes in April 2019.

•	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

•	higher contribution from Canadian Natural Gas Pipelines mainly due to the recovery of increased depreciation in 2019 as a result of higher rates approved in both the Canadian Mainline NEB 2018 Decision and the NGTL 2018-2019 Settlement and higher incentive earnings for the Canadian Mainline

•	lower contribution from Power and Storage primarily due to the sale of our interests in the Cartier Wind power facilities in 2018 and costs related to Napanee's delayed in-service

•	foreign exchange impact of a stronger U.S. dollar on the Canadian dollar equivalent earnings from our U.S. 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 increase in comparable EBITDA described above, therefore having no impact on comparable earnings. In addition, higher depreciation reflects new projects placed in service

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

•	higher income tax expense due to higher comparable earnings before income taxes and lower foreign tax rate differentials

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•	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

•	higher AFUDC due to increased capital expenditures for our NGTL System and Mexico projects.

•	Coastal GasLink Pipeline Project: Following the October 2018 positive Final Investment Decision (FID) by LNG Canada, pre-construction activities continue at many locations along the pipeline route.

•	NGTL System: In first quarter 2019, we placed approximately $250 million of projects in service which included the Gordondale Lateral Loop and the Boundary Lake North projects.

•	Mountaineer XPress and Gulf XPress: The Mountaineer XPress project, a Columbia Gas project designed to transport supply from the Marcellus and Utica shale plays to points along the system and the Leach interconnect with Columbia Gulf, was phased into service over first quarter 2019 along with Gulf XPress, a Columbia Gulf project.

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Grand Chenier XPress: In February 2019, we approved the Grand Chenier XPress project, an ANR Pipeline project which will connect supply directly to Gulf Coast LNG export markets through the addition of a mid-point compressor station and incremental compression capability at existing facilities. Subject to a positive customer FID, the anticipated in-service dates are in 2021 and 2022 for Phase I and II, respectively, with estimated project costs of US$0.2 billion.

•	Sur de Texas: The Sur de Texas project has experienced force majeure events that have delayed in-service. Some events are subject to potential dispute and we have taken measures to protect our interests under the contract. Construction and commissioning activities are progressing such that we anticipate mechanical completion in May with an expected June 2019 in-service.

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•

Villa de Reyes and Tula: Construction of the Villa de Reyes project is ongoing with a phased in-service anticipated to commence in the second half of 2019. Commencement of construction of 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 2020. We have negotiated separate CFE contracts that would allow certain segments of Tula and Villa de Reyes to be placed in service when facilities are complete and gas is available.

•	Keystone Pipeline System: In January 2019, we entered into an agreement with Motiva Enterprises LLC (Motiva) to construct a pipeline connection between the Keystone Pipeline system and Motiva’s 630,000 Bbl/d refinery in Port Arthur, Texas. The connection is targeted to be operational in second quarter 2020.

•	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 second quarter 2019.

•	White Spruce: Commissioning has been completed on the White Spruce pipeline, which transports crude oil from Canadian Natural Resources Limited's Horizon facility in northeast Alberta to the Grand Rapids pipeline with commercial in-service achieved in May 2019.

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Napanee: In March 2019, we experienced an equipment failure while progressing commissioning activities at our 900 MW natural gas-fired power plant in Napanee, Ontario. We continue to expect that our total investment in the Napanee facility will be approximately $1.7 billion, however, commencement of commercial operations will be delayed into the second half of 2019 as we repair the damaged equipment.

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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 on a sale to a third party. On March 20, 2019, we terminated the agreement with SWG after entering into an agreement with SRP to sell the Coolidge generating station for approximately US$465 million, subject to timing of the close and related adjustments. The sale will result in an estimated gain of approximately $70 million ($55 million after tax) to be recognized upon closing, which is expected to occur in mid-2019.

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•	Common Share Dividend: Our Board of Directors declared a quarterly dividend of $0.75 per common share for the quarter ending June 30, 2019 on TransCanada'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 first quarter 2019, the DRP participation rate amongst common shareholders was approximately 33 per cent, resulting in $226 million reinvested in common equity under the program.

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