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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. See 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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•	planned changes in our business

•	our financial and operational performance, including the performance of our subsidiaries

•	expectations or projections about strategies and goals for growth and expansion

•	expected cash flows and future financing options available to us

•	expected dividend growth

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

•	expected schedules for planned projects (including anticipated construction and completion dates)

•	expected regulatory processes and outcomes, including the expected impact of recent FERC policy changes

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

•	expected capital expenditures and contractual obligations

•	expected operating and financial results

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

•	expected impact of U.S. Tax Reform

•	expected industry, market and economic conditions.

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•	continued wind down of our U.S. Northeast power marketing business

•	inflation rates and commodity prices

•	nature and scope of hedging activities

•	regulatory decisions and outcomes, including those related to recent FERC policy changes

•	interest, tax and foreign exchange rates, including the impact of U.S. Tax Reform

•	planned and unplanned outages and the use of our pipeline and energy assets

•	integrity and reliability of our assets

•	access to capital markets

•	anticipated construction costs, schedules and completion dates.

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

•	the operating performance of our pipeline and energy assets

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

•	the availability and price of energy commodities

•	the amount of capacity payments and revenues from our energy business

•	regulatory decisions and outcomes, including those related to recent FERC policy changes

•	outcomes of legal proceedings, including arbitration and insurance claims

•	performance and credit risk of our counterparties

•	changes in market commodity prices

•	changes in the regulatory environment

•	changes in the political environment

•	changes in environmental and other laws and regulations

•	competitive factors in the pipeline and energy sectors

•	construction and completion of capital projects

•	costs for labour, equipment and materials

•	access to capital markets, including the economic benefit of asset drop downs to TC PipeLines, LP

•	interest, tax and foreign exchange rates, including the impact of U.S. Tax Reform

•	weather

•	cyber security

•	technological developments

•	economic conditions in North America as well as globally.

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•	comparable earnings

•	comparable earnings per common share

•	comparable EBITDA

•	comparable EBIT

•	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 and changes 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 property, plant and equipment, goodwill, investments and other assets including certain ongoing maintenance and liquidation costs

•	acquisition and integration costs.

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•	a $24 million after-tax charge for integration-related costs associated with the acquisition of Columbia

•	a $10 million after-tax charge for costs related to the monetization of our U.S. Northeast power generation business

•	a $7 million after-tax charge related to the maintenance of Keystone XL assets which was expensed in 2017 pending further advancement of the project. In 2018, Keystone XL expenditures are being capitalized

•	a $7 million income tax recovery related to the realized loss on a third-party sale of Keystone XL project assets.

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•	higher contribution from Liquids Pipelines primarily due to earnings from intra-Alberta pipelines placed in service in the second half of 2017, 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, additional contract sales on ANR and Great Lakes and amortization of net regulatory liabilities recognized as a result of U.S. Tax Reform

•	lower income tax expense primarily due to lower income tax rates as a result of U.S. Tax Reform and lower flow-through income taxes in Canadian rate-regulated pipelines

•	higher contribution from Mexico Natural Gas Pipelines mainly due to higher revenues

•	higher interest income and other due to realized gains in 2018 compared to realized losses in 2017 on derivatives used to manage our net exposure to foreign exchange rate fluctuations on U.S. dollar-denominated income

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•	lower earnings from U.S. Power mainly due to the monetization of U.S. Northeast power generation assets in second quarter 2017 and the continued wind down of our U.S. power marketing operations

•	lower earnings from Bruce Power primarily due to lower volumes resulting from increased outage days

•	higher interest expense as a result of long-term debt and junior subordinated notes issuances, net of maturities, partially offset by the repayment of the Columbia acquisition bridge facilities in June 2017.

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•	make a limited Natural Gas Act Section 4 filing to reduce its rates by the percentage reduction in its cost of service shown in its FERC Form No. 501-G

•	commit to file either a pre-packaged uncontested rate settlement or a general Section 4 rate case if it believes that using the limited Section 4 option will not result in just and reasonable rates. If the pipeline commits to file either by December 31, 2018, FERC will not initiate a Natural Gas Act Section 5 investigation of its rates prior to that date

•	file a statement explaining its rationale for why it does not believe the pipeline's rates must change

•	file the one-time report without taking any other action. At that point, FERC would consider whether to initiate a Section 5 investigation of any pipeline that has not submitted a limited Section 4 rate reduction filing or committed to file a general Section 4 rate case.

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1	Reflects our proportionate share of costs related to Portland XPress and various expansion projects.

2	Reflects our proportionate share.

3	Reflects our proportionate share of the remaining capital costs that Bruce Power expects to incur on its life extension investment programs in advance of the Unit 6 major refurbishment outage which is expected to begin in 2020.

4	Reflects U.S./Canada foreign exchange rate of 1.29 at March 31, 2018.

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1	Regulatory approvals have been obtained, additional commercial support is being pursued.

2	Reflects our proportionate share.

3	Carrying value reflects amount remaining after impairment charge recorded in 2015, along with additional amounts capitalized from January 1, 2018.

4	Reflects U.S./Canada foreign exchange rate of 1.29 at March 31, 2018.

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

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1	Results reflect our earnings from TC PipeLines, LP’s ownership interests in GTN, Great Lakes, Iroquois, Northern Border, Bison, PNGTS, North Baja and Tuscarora, as well as general and administrative costs related to TC PipeLines, LP.

2	TC PipeLines, LP periodically conducts ATM equity issuances which decrease our ownership in TC PipeLines, LP. For the three months ended March 31, 2018, our ownership interest in TC PipeLines, LP ranged between 25.7 per cent and 25.5 per cent compared to a range of 26.8 per cent and 26.4 per cent for the same period in 2017.

3	TC PipeLines, LP acquired 49.34 per cent of our 50 per cent interest in Iroquois and our remaining 11.81 per cent interest in PNGTS on June 1, 2017.

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

5	Results reflect earnings from our direct ownership interests in Iroquois, Crossroads and PNGTS (until June 1, 2017) and 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.

6	Results reflect earnings attributable to portions of TC PipeLines, LP, PNGTS (until June 1, 2017) and CPPL (until February 17, 2017) that we do not own.

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•	increased earnings from Columbia Gas and Columbia Gulf growth projects placed in service, additional contract sales on ANR and Great Lakes and favourable commodity prices in Midstream

•	increased earnings due to the amortization of the net regulatory liability recognized in 2017 as a result of U.S. Tax Reform.

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1	Represents our 60 per cent equity interest.

•	higher revenues from operations

•	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 is fully offset in interest income and other in the Corporate segment.

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1	Includes primarily liquids marketing and business development activities.

•	unrealized losses in 2018 from changes in the fair value of derivatives related to our liquids marketing business

•	in 2017, an $8 million charge related to the maintenance of Keystone XL assets which was expensed pending further advancement of the project. In 2018, Keystone XL expenditures are being capitalized.

•	contributions from intra-Alberta pipelines, Grand Rapids and Northern Courier, which began operations in the second half of 2017

•	higher volumes on the Keystone Pipeline System

•	a higher contribution from liquids marketing activities

•	a weaker U.S. dollar which had a negative 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.

2	In second quarter 2017, we completed the sales of our U.S. Northeast power generation assets.

•	unrealized gains and losses from changes in the fair value of derivatives used to reduce our exposure to certain commodity price risks, as noted in the table below

•	in 2017, $11 million of pre-tax costs related to the monetization of our U.S. Northeast power generation business.

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•	lower contribution from U.S. Power due to the sales of our generation assets in second quarter 2017 and the continued wind down of our U.S. Power marketing operations, partially offset by income recognized on the sale of our retail contracts in the first quarter of 2018

•	decreased Bruce Power earnings primarily due to lower volumes resulting from increased outage days. Additional financial and operating information on Bruce Power is provided below

•	decreased Natural Gas Storage results mainly due to lower realized natural gas storage price spreads

•	lower Eastern Power results mainly due to the sale of our Ontario solar assets in December 2017

•	increased Western Power results due to higher realized prices on higher generation volumes.

1	Represents our 48.4 per cent (2017 - 48.4 per cent) ownership interest in Bruce Power. Sales volumes include deemed generation.

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

3	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.

•	in 2018, foreign exchange loss on a peso-denominated inter-affiliate loan to the Sur de Texas project for our proportionate share of the project's financing. There is a corresponding foreign exchange gain included in Interest income and other on the inter-affiliate loan receivable which fully offsets this loss

•	in 2017, pre-tax integration and acquisition costs associated with the acquisition of Columbia.

•	long-term debt and junior subordinated notes issuances, net of maturities

•	final repayment of the Columbia acquisition bridge facilities in June 2017, resulting in lower interest expense and debt amortization expense

•	the positive impact of a weaker U.S. dollar in translating U.S. dollar denominated interest

•	lower capitalized interest primarily due to completion of construction of Grand Rapids and Northern Courier in 2017.

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•	interest income along with the $79 million 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 are reflected in Income from equity investments in the Mexico Natural Gas Pipelines and Corporate segments, respectively. Both currency-related amounts are excluded from comparable earnings

•	unrealized losses on risk management activities in 2018 compared to unrealized gains in 2017. These amounts have been excluded from comparable earnings

•	realized gains in 2018 compared to realized losses in 2017 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 cash flow from operations

•	our access to capital markets

•	approximately $9.1 billion of unutilized, unsecured credit facilities.

1	See the Non-GAAP measures section of this MD&A for further discussion of funds generated from operations, comparable funds generated from operations, comparable distributable cash flow and comparable distributable cash flow per common share.

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1	Includes contributions to Bruce Power to fund our proportionate share of maintenance capital expenditures.

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

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•	accounts receivable

•	the fair value of derivative assets

•	cash and cash equivalents

•	loans receivable.

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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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1	Fair values equal carrying values.

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

3	In the three months ended March 31, 2018, Net income includes net realized gains of $1 million (2017 - $1 million) related to the interest component of cross-currency swap settlements which are reported within interest expense.

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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 net in Revenues. Realized and unrealized gains and losses on interest rate and foreign exchange held for trading derivative instruments are included net in Interest expense and Interest income and other, respectively.

2	In the three months ended March 31, 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 (2017 - nil).

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

2	Reported within Revenues on the Condensed consolidated statement of income.

3	Reported within Interest expense on the Condensed consolidated statement of income.

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•	pattern of revenue recognition, whether the performance obligation is satisfied at a point in time versus over time within a contract

•	term of the contract

•	amount of variable consideration associated with a contract and timing of the associated revenue recognition.

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•	regulators' decisions

•	negotiated settlements with shippers

•	acquisitions and divestitures

•	developments outside of the normal course of operations

•	newly constructed assets being placed in service.

•	regulatory decisions

•	developments outside of the normal course of operations

•	newly constructed assets being placed in service

•	demand for uncontracted transportation services

•	liquids marketing activities

•	certain fair value adjustments.

•	weather

•	customer demand

•	market prices for natural gas and power

•	capacity prices and payments

•	planned and unplanned plant outages

•	acquisitions and divestitures

•	certain fair value adjustments

•	developments outside of the normal course of operations

•	newly constructed assets being placed in service.

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•	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 business, which included an incremental after-tax loss of $7 million recorded on the sale of the thermal and wind package, $23 million of after-tax third-party insurance proceeds related to a 2017 Ravenswood outage and income tax adjustments

•	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 which were expensed pending further advancement of the project.

•	an incremental net loss of $12 million related to the monetization of our U.S. Northeast power business which included an incremental loss of $7 million after tax on the sale of the thermal and wind package and $14 million of after-tax disposition costs and income tax adjustments

•	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 which were being expensed pending further advancement of the project.

•	a $265 million net after-tax gain related to the monetization of our U.S. Northeast power business which included a $441 million after-tax gain on the sale of TC Hydro and an additional 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 which were being expensed pending further advancement of the project.

•	a charge of $24 million after tax for integration-related costs associated with the acquisition of Columbia

•	a charge of $10 million after tax for costs related to the monetization of our U.S. Northeast power generation business

•	a charge of $7 million after tax related to the maintenance of Keystone XL assets which were being expensed pending further advancement of the project

•	a $7 million income tax recovery related to the realized loss on a third-party sale of Keystone XL project assets. A provision for the expected pre-tax loss on these assets was included in our 2015 impairment charge but the related income tax recoveries could not be recorded until realized.

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•	an $870 million after-tax charge related to the loss on U.S. Northeast power assets held for sale which included an $863 million after-tax loss on the thermal and wind package held for sale and $7 million of after-tax costs related to the monetization

•	an additional $68 million after-tax loss on the transfer of environmental credits to the Balancing Pool upon final settlement of the Alberta PPA terminations

•	an after-tax charge of $67 million for costs associated with the acquisition of Columbia which included a $44 million deferred tax adjustment upon acquisition and $23 million of retention, severance and integration costs

•	an after-tax charge of $18 million related to Keystone XL costs for the maintenance and liquidation of project assets which were being expensed pending further advancement of the project

•	an after-tax restructuring charge of $6 million for additional expected future losses under lease commitments. These charges formed part of a restructuring initiative, which commenced in 2015, to maximize the effectiveness and efficiency of our existing operations and reduce overall costs.

•	a $656 million after-tax impairment on the Ravenswood goodwill. As a result of information received during the process to monetize our U.S. Northeast power business in third quarter 2016, it was determined that the fair value of Ravenswood no longer exceeded its carrying value

•	costs associated with the acquisition of Columbia including a charge of $67 million after tax primarily relating to retention, severance and integration expenses

•	$28 million of income tax recoveries related to the realized loss on a third-party sale of Keystone XL plant and equipment. A provision for the expected loss on these assets was included in our fourth quarter 2015 impairment charge but the related tax recoveries could not be recorded until realized

•	a charge of $9 million after tax related to Keystone XL costs for the maintenance and liquidation of project assets which were being expensed pending further advancement of the project

•	a $3 million after-tax charge related to the monetization of our U.S. Northeast power business.

•	a charge of $113 million related to costs associated with the acquisition of Columbia which included $109 million related to dividend equivalent payments on the subscription receipts issued to partially fund the acquisition

•	a charge of $9 million after tax related to Keystone XL costs for the maintenance and liquidation of project assets which were being expensed pending further advancement of the project

•	a charge of $10 million after tax for restructuring charges mainly related to expected future losses under lease commitments.

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•	pattern of revenue recognition, whether the performance obligation is satisfied at a point in time versus over time within a contract

•	term of the contract

•	amount of variable consideration associated with a contract and timing of the associated revenue recognition.

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1	Includes intersegment eliminations.

2

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.

3	Income/(loss) from equity investments includes foreign exchange losses on the Company's inter-affiliate loan with Sur de Texas. The peso-denominated loan to the Sur de Texas joint venture represents the Company's proportionate share of debt financing for this joint venture.

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1	Includes intersegment eliminations.

2

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.

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1

Other revenues includes income from the Company's financial instruments and lease arrangements within each operating segment. Income from lease arrangements includes certain long term PPAs, as well as certain liquids pipelines capacity and transportation arrangements. These arrangements are not in the scope of the new guidance, therefore, revenues related to these contracts are excluded from revenues from contracts with customers. Refer to Note 11, Risk management and financial instruments, for further information on income from financial instruments.

2	Other revenues from U.S. Natural Gas Pipelines includes the amortization of the regulatory liability resulting from U.S. Tax Reform. Refer to Note 6, Income taxes, for further information.

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1	Adjustment relates to contract assets previously included in Accounts receivable.

2	Adjustment relates to contract liabilities previously included in Accounts receivable.

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

2	Comprised of deferred revenue recorded in Accounts payable and other on the Condensed consolidated balance sheet. During the three months ended March 31, 2018, $17 million of revenue was recognized that was included in the contract liability at the beginning of the period.

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

1)	The original expected duration of the contract is one year or less.

3)

The variable revenue generated from the contract is allocated entirely to a wholly unsatisfied performance obligation or to a wholly unsatisfied promise to transfer a distinct good or service that forms part of a single performance obligation in a series. A single performance obligation in a series occurs when the promises under a contract are a series of distinct services that are substantially the same and have the same pattern of transfer to the customer over time.

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

2	Other comprehensive income/(loss) before reclassifications on currency translation adjustments and cash flow hedges is net of non-controlling interest gains of $57 million and $9 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 $22 million ($16 million, net of tax) at March 31, 2018. 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.

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

2	These accumulated other comprehensive loss components are included in the computation of net benefit cost. Refer to Note 10, Employee post-retirement benefits, for further information.

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

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1	Fair values equal carrying values.

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

3	In the three months ended March 31, 2018, Net income includes net realized gains of $1 million (2017 – $1 million) related to the interest component of cross-currency swap settlements which are reported within Interest expense.

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1	Long-term debt is recorded at amortized cost except for US$1.2 billion (December 31, 2017 – US$1.1 billion) that is attributed to hedged risk and recorded at fair value.

2

Net income for the three months ended March 31, 2018 included unrealized gains of $5 million (2017 – $2 million) for fair value adjustments attributable to the hedged interest rate risk associated with interest rate swap fair value hedging relationships on US$1.2 billion of long-term debt at March 31, 2018 (December 31, 2017 – US$1.1 billion). 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 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	Unrealized gains and losses on other restricted investments are included in Interest income and other.

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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.

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1	At March 31, 2018, the balance includes adjustments for discontinued hedging relationships of nil (December 31, 2017 – nil).

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.

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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 net in Revenues. Realized and unrealized gains and losses on interest rate and foreign exchange derivative instruments held for trading are included net in Interest expense and Interest income and other, respectively.

2	In the three months ended March 31, 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 (2017 – nil).

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

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1	Refer to Note 9, Other comprehensive income/(loss) and accumulated other comprehensive loss, for the components of OCI related to derivatives in cash flow hedging relationships including the portion attributable to non-controlling interests.

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 I to Level II or from Level II to Level III for the three months ended March 31, 2018.

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1	There were no transfers from Level I to Level II or from Level II to Level III for the year ended December 31, 2017.

1	For the three months ended March 31, 2018, revenues include unrealized losses of $11 million attributed to derivatives in the Level III category that were still held at March 31, 2018 (2017 – unrealized losses of less than $1 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.

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.

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.

•	First quarter 2018 financial results

◦	Comparable distributable cash flow of $1.4 billion or $1.64 per share reflecting only non-recoverable maintenance capital expenditures

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•	Declared a quarterly dividend of $0.69 per common share for the quarter ending June 30, 2018

•	Placed approximately $160 million of NGTL facilities in service to complete the 2017 Expansion Program as well as the approximate $100 million Sundre Crossover project

•	Successfully completed open seasons for NGTL securing contracts for 620 MMcf/d of incremental firm receipt service and 1.5 Bcf/d of existing and expansion export delivery capacity. These facilities are expected to result in an expansion program of approximately $2.5 billion

•	Filed an NGTL application with the NEB for approval of a negotiated settlement with customers for 2018 and 2019

•	Placed the US$1.6 billion Leach XPress and US$0.3 billion Cameron Access projects in service

•	Received FERC approval for Great Lakes and Northern Border rate settlements

•	FERC proposed changes related to a number of income tax matters with respect to pipeline ratemaking.

•	a higher contribution from Liquids Pipelines primarily due to earnings from intra-Alberta pipelines placed in service in the second half of 2017, higher volumes on the Keystone Pipeline System and increased earnings from liquids marketing activities

•	a higher contribution from U.S. Natural Gas Pipelines mainly due to increased earnings from Columbia Gas and Columbia Gulf growth projects placed in service, additional contract sales on ANR and Great Lakes and amortization of net regulatory liabilities recognized as a result of U.S. Tax Reform

•	lower income tax expense primarily due to lower rates as a result of U.S. Tax Reform and lower flow-through income taxes in Canadian rate-regulated pipelines

•	a higher contribution from Mexico Natural Gas Pipelines mainly due to higher revenues

•	higher interest income and other due to realized gains in 2018 compared to realized losses in 2017 on derivatives used to manage our net exposure to foreign exchange rate fluctuations on U.S. dollar-denominated income

•	lower earnings from U.S. Power mainly due to the monetization of U.S. Northeast power generation assets in second quarter 2017 and the continued wind down of our U.S. power marketing operations

•	lower earnings from Bruce Power primarily due to lower volumes resulting from increased outage days

•	higher interest expense as a result of long-term debt and junior subordinated notes issuances, net of maturities, partially offset by the repayment of the Columbia acquisition bridge facilities in June 2017.

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•	NGTL System: On April 9, 2018, we announced that the Sundre Crossover project was placed in service. The approximate $100 million pipeline project increases NGTL capacity at our Alberta / B.C. Export Delivery Point by 245 TJ/d (228 MMcf/d), enhancing connectivity to key downstream markets in the Pacific Northwest and California.

•	Leach XPress: Leach XPress was placed in service on January 1, 2018. This Columbia Gas project transports approximately 1.6 PJ/d (1.5 Bcf/d) of Marcellus and Utica gas supply to delivery points along the system.

•	Cameron Access: Cameron Access was placed in service on March 13, 2018. This Columbia Gulf project is designed to transport approximately 0.9 PJ/d (0.8 Bcf/d) of gas supply to the Cameron LNG export terminal in Louisiana.

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Mountaineer XPress and WB XPress: In first quarter 2018, estimated project costs of US$3.0 billion for Mountaineer XPress and US$0.9 billion for WB XPress increased by US$0.4 billion and US$0.1 billion, respectively. These increases primarily reflect the impact of delays of various regulatory approvals from the Federal Energy Regulatory Commission (FERC) and other agencies, increased contractor construction costs due to unusually high demand for construction resources in the region, and modifications to contractor work plans and resources to maintain our projected in-service dates.

•	Great Lakes and Northern Border Rate Settlements: In February 2018, FERC approved the 2017 Great Lakes Rate Settlement and the 2017 Northern Border Rate Settlement, both of which were uncontested.

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•	Tula and Villa de Reyes: We continue to work toward finalizing amending agreements for both of these pipelines with the Comisión Federal de Electricidad (CFE) to formalize the schedule and payments resulting from their respective force majeure events. The CFE has commenced payments on both pipelines in accordance with the TSAs.

•	Sur de Texas: Offshore construction is now approximately 80 per cent complete and the project continues to progress toward an anticipated in-service date of late 2018.

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Keystone XL: In December 2017, an appeal to Nebraska's Court of Appeals was filed by intervenors after the Nebraska Public Service Commission (PSC) issued an approval of an alternative route for the Keystone XL project in November 2017. On March 14, 2018, the Nebraska Supreme Court, on its own motion, agreed to bypass the Court of Appeals and hear the appeal case against the PSC’s alternative route itself. We expect the Nebraska Supreme Court, as the final arbiter, could reach a decision by late 2018 or first quarter 2019.

•	White Spruce: In February 2018, the Alberta Energy Regulator issued a permit for the construction of the White Spruce pipeline. Construction has commenced with an anticipated in-service date in second quarter 2019.

•	Monetization of U.S. Northeast power business: On March 1, 2018, as part of the continued wind down of our U.S. power marketing operations, we closed the sale of our U.S. power retail contracts for proceeds of approximately US$23 million and recognized income of US$10 million (US$7 million after tax).

•	Common Share Dividend: Our Board of Directors declared a quarterly dividend of $0.69 per share for the quarter ending June 30, 2018 on TransCanada's outstanding common shares. The quarterly amount is equivalent to $2.76 per common share on an annualized basis.

•	Dividend Reinvestment Plan (DRP): In first quarter 2018, the participation rate in our DRP was approximately 38 per cent of common share dividends, resulting in $234 million reinvested in common equity under the program.

•	ATM Equity Issuance Program: In first quarter 2018, 5.8 million common shares were issued through the corporate ATM program at an average price of $56.51 per common share for gross proceeds of $329 million. An additional 1.6 million common shares were issued in April 2018, bringing year-to-date gross proceeds to $415 million at an average price of $55.64 per common share.

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U.S. Tax Reform and 2018 FERC Actions: In December 2016, FERC issued a Notice of Inquiry (NOI) seeking comment on how to address the issue of whether its existing policies resulted in a ‘double recovery’ of income taxes in a pass-through entity such as a master limited partnership (MLP). The NOI was in response to a decision by the U.S. Court of Appeals for the District of Columbia Circuit in July 2016, in United Airlines, Inc., et al. v. FERC, directing FERC to address the issue.

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